Sanchez Energy (SNECQ) 10-K 27 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Feb. 24, 2017	Jun. 30, 2016
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, 2016
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	Accelerated Filer
Entity Public Float			$ 392,858,811
Entity Common Stock, Shares Outstanding		78,648,272
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 501,917	$ 435,048
Oil and natural gas receivables	41,057	30,668
Joint interest billings receivables	496	1,259
Accounts receivable - related entities	6,401	3,697
Fair value of derivative instruments		172,494
Other current assets	12,934	23,452
Total current assets	562,805	666,618
Oil and natural gas properties, at cost, using the full cost method:
Unproved oil and natural gas properties	231,424	253,529
Proved oil and natural gas properties	3,164,115	2,914,867
Total oil and natural gas properties	3,395,539	3,168,396
Less: Accumulated depreciation, depletion, amortization and impairment	(2,736,951)	(2,412,293)
Total oil and natural gas properties, net	658,588	756,103
Other assets:
Fair value of derivative instruments		5,789
Investments (Investment in SPP measured at fair value of $26.8 million and $0 as of December 31, 2016 and 2015, respectively)	39,656	49,985
Other assets	25,231	22,809
Total assets	1,286,280	1,501,304
Current liabilities:
Accounts payable	1,076	4,184
Other payables	2,251	2,004
Accrued liabilities:
Capital expenditures	35,154	51,983
Other	82,458	69,974
Deferred premium liability	2,079	24,548
Fair value of derivative instruments	31,778
Other current liabilities	22,201	14,813
Total current liabilities	176,997	167,506
Long term debt, net of premium, discount and debt issuance costs	1,712,767	1,705,927
Asset retirement obligations	25,087	25,907
Fair value of derivative instruments	3,236
Other liabilities	64,333	58,133
Total liabilities	1,982,420	1,957,473
Commitments and Contingencies (Note 14)
Stockholders' equity:
Preferred stock ($0.01 par value, 15,000,000 shares authorized; 1,838,985 shares issued and outstanding as of December 31, 2016 and 2015 of 4.875% Convertible Perpetual Preferred Stock, Series A; 3,527,830 and 3,532,330 shares issued and outstanding as of December 31, 2016 and 2015 of 6.500% Convertible Perpetual Preferred Stock, Series B, respectively)	53	53
Common stock ($0.01 par value, 150,000,000 shares authorized; 66,156,378 and 61,928,089 shares issued and outstanding as of December 31, 2016 and 2015, respectively)	670	619
Additional paid-in capital	1,112,397	1,079,513
Accumulated deficit	(1,809,260)	(1,536,354)
Total stockholders’ equity (deficit)	(696,140)	(456,169)
Total liabilities and stockholders’ (equity) deficit	$ 1,286,280	$ 1,501,304

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
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	66,156,378	61,928,089
Common stock, shares outstanding	66,156,378	61,928,089
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%
Recurring basis
Investment in SPP measured at fair value	$ 26,818	$ 0

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
REVENUES:
Oil sales	$ 241,766	$ 307,971	$ 538,887
Natural gas liquid sales	81,744	69,011	66,989
Natural gas sales	107,816	98,797	60,188
Total revenues	431,326	475,779	666,064
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses	164,567	156,528	93,581
Production and ad valorem taxes	19,633	26,870	37,787
Depreciation, depletion, amortization and accretion	159,760	344,572	338,097
Impairment of oil and natural gas properties	169,046	1,365,000	213,821
General and administrative (inclusive of stock-based compensation expense of $37,090, $14,831, and $12,843 and for 2016, 2015, and 2014, respectively)	110,081	74,160	63,692
Total operating costs and expenses	623,087	1,967,130	746,978
Operating loss	(191,761)	(1,491,351)	(80,914)
Other income (expense):
Interest income	856	442	193
Other income (expense)	134	(2,605)	96
Gain on disposal of assets	112,294
Interest expense	(126,973)	(126,399)	(89,800)
Earnings from equity investments	3,466
Net gains (losses) on commodity derivatives	(53,149)	172,886	137,205
Total other income (expense)	(63,372)	44,324	47,694
Loss before income taxes	(255,133)	(1,447,027)	(33,220)
Income tax expense (benefit)	1,825	7,600	(11,429)
Net loss	(256,958)	(1,454,627)	(21,791)
Less:
Preferred stock dividends	(15,948)	(16,008)	(33,590)
Net loss attributable to common stockholders	$ (272,906)	$ (1,470,635)	$ (55,381)
Net loss per common share - basic and diluted (in dollars per share)	$ (4.63)	$ (25.70)	$ (1.06)
Weighted average number of shares used to calculate net loss attributable to common stockholders - basic and diluted (in shares)	58,900	57,229	52,338

Consolidated Statements of Ope5

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Consolidated Statements of Operations
General and administrative, stock-based compensation expense (in dollars)	$ 37,090	$ 14,831	$ 12,843

Consolidated Statements of Stoc

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, 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, net of offering costs of $8,731			$ 50	167,469		167,519
Common shares issued, net of offering costs of $8,731 (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 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 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
Increase (Decrease) in Stockholders' Equity (Deficit)
Preferred stock dividends			$ 10	7,964	(15,948)	(7,974)
Preferred stock dividends (in shares)			967
Restricted stock awards, net of forfeitures			$ 41	(41)
Restricted stock awards, net of forfeitures (in shares)			4,092
Stock-based compensation				24,961		24,961
Net loss					(256,958)	(256,958)
Balance at Dec. 31, 2016	$ 18	$ 35	$ 670	$ 1,112,397	$ (1,809,260)	$ (696,140)
Balance (in shares) at Dec. 31, 2016	1,839	3,528	66,987

Consolidated Statements of Sto7

Consolidated Statements of Stockholders' Equity (Deficit) (Parenthetical) $ in Thousands	12 Months Ended
	Dec. 31, 2014USD ($)
Offering costs	$ 37,364
Common Stock
Offering costs	$ 8,731

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$ (256,958)	$ (1,454,627)	$ (21,791)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	159,760	344,572	338,097
Impairment of oil and natural gas properties	169,046	1,365,000	213,821
Gain on disposal of assets	(112,294)
Stock-based compensation expense	37,090	14,831	12,843
Net (gains) losses on commodity derivative contracts	53,149	(172,886)	(137,205)
Net cash settlement received on commodity derivative contracts	122,145	131,123	5,600
Losses incurred on premiums for derivative contracts	24,548	(121)	(596)
Cash reimbursements received for operating leasehold improvements		2,648
(Gain) loss on investment in SPP	(1,818)	935
Amortization of deferred gain on Western Catarina Midstream Divestiture	(14,813)	(3,086)
Amortization of debt issuance costs	7,840	7,529	9,002
Accretion of debt discount, net	633	703	755
Deferred taxes		7,443	(11,429)
Loss on inventory market adjustment	649
Distributions from equity investments	930
Earnings from equity investments	(3,466)
Changes in operating assets and liabilities:
Accounts receivable	(9,626)	60,480	(26,971)
Other current assets	1,504	(450)	(21,633)
Accounts payable	(3,108)	(25,303)	(2,868)
Accounts receivable - related entities	(2,704)	(3,311)	(1,347)
Other payables	247	(2,290)	1,522
Accrued liabilities	8,498	2,813	51,590
Other current liabilities		(5,166)	5,166
Other liabilities	(1)	1,188	779
Net cash provided by operating activities	181,251	272,025	415,335
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for oil and natural gas properties	(313,342)	(656,136)	(791,260)
Payments for other property and equipment	(5,394)	(8,123)	(14,062)
Proceeds from sale of oil and natural gas properties	179,143	427,571
Acquisition of oil and natural gas properties		(7,658)	(555,942)
Investment in SPP	(25,000)
Purchases of investments	(36,502)	(49,985)
Sale of investments	92,458
Net cash used in investing activities	(108,637)	(294,331)	(1,361,264)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings	60,000		100,000
Repayment of borrowings	(60,000)		(100,000)
Issuance of senior notes, net of premium and discount			1,152,250
Issuance of common stock			176,250
Payments for offering costs			(8,731)
Financing costs	(1,758)	(400)	(37,364)
Preferred dividends paid	(3,987)	(15,960)	(16,293)
Net cash provided by (used in) financing activities	(5,745)	(16,360)	1,266,112
Increase (decrease) in cash and cash equivalents	66,869	(38,666)	320,183
Cash and cash equivalents, beginning of period	435,048	473,714	153,531
Cash and cash equivalents, end of period	501,917	435,048	473,714
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in asset retirement obligations	(2,895)	(1,877)	20,303
Change in accrued capital expenditures	(16,829)	(110,744)	75,843
Capital expenditures in accounts payable			14,545
Common stock issued in exchange for preferred stock		273	123,731
SUPPLEMENTAL DISCLOSURE:
Cash paid for taxes	1,996	158
Cash paid for interest	$ 118,498	$ 121,644	$ 48,064

Organization and Business

Organization and Business	12 Months Ended
	Dec. 31, 2016
Organization and Business
Organization and Business	Note 1. Organization and Busines Sanchez Energy Corporation (together with our consolidated subsidiaries, “Sanchez Energy,” the “Company,” “we,” “our,” “us” or similar terms), a Delaware corporation formed in August 2011, is an independent exploration and production company focused on the acquisition and development of U.S. onshore unconventional oil and natural gas resources, with a current focus on the horizontal development of significant resource potential from the Eagle Ford Shale in South Texas. We also hold an undeveloped acreage position in the Tuscaloosa Marine Shale (“TMS”) in Mississippi and Louisiana, which offers future upside opportunity. As of December 31, 2016, we have assembled approximately 278,000 net leasehold acres with an approximate 94% average working interest in the Eagle Ford Shale. Pro forma for the Comanche Acquisition (defined below), we will have assembled 339,000 net leasehold acres with an approximate 61% average working interest as of December 31, 2016. Following completion of the Comanche Acquisition, we will have over 7,000 gross (4,000 net) locations for potential future drilling. For the year 2017, we plan to invest substantially all of our capital budget in the Eagle Ford Shale. We continue to evaluate opportunities to increase both our acreage and our producing assets through acquisitions. Our successful acquisition of such assets will depend on both the opportunities and the financing alternatives available to us at the time we consider such opportunities. 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, 2016
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 In January 2017, the FASB issued Accounting Standards Update (“ASU”) 2017-01 “Business Combinations (Topic 805) - Clarifying the Definition of a Business,” which provides a new framework for determining whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. Early adoption is permitted, and the Company is currently in the process of evaluating the impact of adoption of this guidance on its consolidated financial statements. In December 2016, the FASB issued Accounting Standards Update ASU 2016-19 “Technical Corrections and Improvements,” which amends a number of Topics in the FASB ASC. The ASU is part of an ongoing FASB project to facilitate Codification updates for non-substantive technical corrections, clarifications, and improvements that are not expected to have a significant effect on accounting practice or create a significant administrative cost to most entities. The ASU will apply to all reporting entities within the scope of the affected accounting guidance. Most amendments are effective upon issuance (December 2016). In November 2016, the FASB issued ASU 2016-18 “Statement of Cash Flows (Topic 230): Restricted Cash,” which requires companies to include cash and cash equivalents that have restrictions on withdrawal or use in total cash and cash equivalents on the statement of cash flows. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. Early adoption is permitted, and the Company is currently in the process of evaluating the impact of adoption of this guidance on its consolidated financial statements. In October 2016, the FASB issued ASU 2016-16 “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” which eliminates a current exception in U.S. GAAP to the recognition of the income tax effects of temporary differences that result from intra-entity transfers of non-inventory assets. The intra-entity exception is being eliminated under the ASU. The standard is required to be applied on a modified retrospective basis and will be effective beginning with the first quarter of 2018. Early adoption is permitted, and the Company is currently in the process of evaluating the impact of adoption of this guidance on its consolidated financial statements. In August 2016, the FASB issued ASU No. 2016-15 “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments”. This ASU is intended to clarify the presentation of cash receipts and payments in specific situations. The amendments in this ASU are effective for financial statements issued for annual periods beginning after December 15, 2017, including interim periods within those annual periods, and early application is permitted. The Company does not anticipate that ASU 2016-15 will have a material effect on its consolidated and condensed financial statements and related disclosures. In March 2016, the FASB issued ASU No. 2016-09 “Improvements to Employee Share-Based Payment Accounting,” effective for annual and interim periods for public companies beginning after December 15, 2016, with a cumulative-effect and prospective approach to be used for implementation. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions including accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, minimum statutory tax withholding requirements and classification of employee taxes paid on the statement of cash flows when an employer withholds shares for tax-withholding purposes. The Company is currently in the process of evaluating the impact of adoption of this guidance on its consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018, with a modified retrospective approach to be used for implementation. The standard updates the previous lease guidance by requiring the recognition of a right-to-use asset and lease liability on the statement of financial position for all leases with lease terms of more than 12 months. The lease liability represents the discounted obligation to make future minimum lease payments and corresponding right-of-use asset on the balance sheet for most leases. Recognition, measurement and presentation of expenses and cash flows arising from a lease will depend on classification as a finance or operating lease. The Company has several operating leases as further discussed in Note 16, “Commitments and Contingencies,” which will be impacted by the new rules under this standard. The Company will not early adopt this standard, and will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019. The Company is currently evaluating the impact of these rules on its financial statements and has started the assessment process by evaluating the population of leases under the revised definition. The adoption of this standard will result in an increase in the assets and liabilities on the Company’s consolidated balance sheets. The quantitative impacts of the new standard are dependent on the leases in force at the time of adoption. As a result, the evaluation of the effect of the new standards will extend over future 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 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. The Company is currently in the process of evaluating the impact of adoption of this guidance on its consolidated financial statements, but do not expect the impact to be material. May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” In March, April, and May of 2016, the FASB issued rules clarifying several aspects of the new revenue recognition standard. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. 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 standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The Company will not early adopt the standard although early adoption is permitted. The Company is currently evaluating whether to apply the retrospective approach or modified retrospective approach with the cumulative effect recognized as of the date of initial application. The Company is currently evaluating the impact the standard is expected to have on its consolidated financial statements by evaluating current revenue streams and evaluating contracts under the revised standards. 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, 2016 and 2015, 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, 2016, the Company recorded a full cost ceiling test impairment after income taxes of $169.0 million. 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. 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, 5%, 8% and 25% of the unproved property balance at December 31, 2016 is expected to be added to the amortization base during the years 2017, 2018 and 2019, respectively. The remaining balances in unproved properties relate to project areas that will not be thoroughly evaluated until after 2019, and represent leasehold interests that have expiration dates beginning in 2020 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, 2016, and notes the year in which the associated costs were incurred (in thousands): Year of Acquisition Prior to 2014 2014 2015 2016 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, 2016, 2015 and 2014 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 2016, the Company capitalized approximately $0.1 million in costs associated with the filing of a Form S-3 Registration Statement, and capitalized approximately $1.6 million associated with amending our Second Amended and Restated Agreement (as defined in Note 5, “Long-Term Debt”). During 2015, the Company capitalized approximately $0.4 million in costs associated with amending our Second Amended and Restated Agreement. 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 Catarina Acquisition (as defined in Note 3, “Acquisitions and Divestitures”). At December 31, 2016 and December 31, 2015, the Company had approximately $35.0 million and $41.0 million, respectively, of debt issuance costs (net of accumulated amortization of $22.5 million and $14.7 million, respectively) remaining that are being amortized over the terms of the respective debt. In accordance with ASU 2015-03, “Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” the debt issuance costs related to the issuance of the 6.125% Notes and Second Amended and Restated Agreement are presented on the balance sheet as a direct deduction from the long-term 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, 2016 and 2015. 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. Stock-based compensation awards and phantom stock awards, including those awards with market performance acceleration conditions, 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. In accordance with the guidance, the inclusion of market performance acceleration conditions does not change the accounting classification as compared to those awards without market performance acceleration conditions. The phantom stock awards are required to be settled in cash by the Company and are classified as a liability. Compensation expense for the unvested awards is revalued at each period end and is amortized over the vesting period of the stock-based award. 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, 2016, 2015 and 2014 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, 2016, 2015 and 2014 as listed below: 2016 2015 2014 Customer A Customer B Customer C Customer D Customer E 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, 2016 or 2015. 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 Preferred Stock using the if‑converted method, if the effect is dilutive.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2016
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 $ Cotulla Disposition On December 14, 2016, SN Cotulla Assets, LLC (“SN Cotulla”), a wholly-owned subsidiary of the Company, completed the initial closing of the sale of certain oil and gas interests and associated assets located in Dimmit County, Frio County, LaSalle County, Zavala County and McMullen County, Texas (the “Cotulla Assets”) to Carrizo (Eagle Ford) LLC (“Carrizo Eagle Ford”), pursuant to a Purchase and Sale Agreement dated October 24, 2016 for an adjusted purchase price of approximately $153.5 million (the “Cotulla Disposition”). The effective date of the Cotulla Disposition is June 1, 2016. Subsequent to December 31, 2016, a second closing on an additional portion of the Cotulla Assets was completed for cash consideration of approximately $7.1 million, and the Cotulla Disposition remains subject to post-closing adjustments and potential future closings. Normally, sales of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized. However, in circumstances where treating a sale like a normal retirement would result in a significant change in the company’s amortization rate, judgment should be applied. The Company determined that adjustments to capitalized costs for the Cotulla Disposition would cause a significant change in the company’s amortization rate. As such, the Company recorded a gain of approximately $112.3 million related to the Cotulla Disposition. The Company expects to record additional gains related to the potential future closings on the Cotulla Disposition in 2017, as noted above. Production Asset Transaction On November 22, 2016, the Company completed the sale of certain non-core producing oil and gas assets, located in South Texas, to SPP for an adjusted purchase price of approximately $25.6 million in cash (the “Production Asset Transaction”). The Production Asset Transaction includes working interests in 23 producing Eagle Ford wellbores located in Dimmit and Zavala counties in South Texas together with escalating working interests in an additional 11 producing wellbores located in the Palmetto Field in Gonzales County, Texas. The effective date of the Production Asset Transaction was July 1, 2016. The aggregate average working interest percentage initially conveyed was 17.92% 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, 2018, 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. The Company did not record any gains or losses related to the Production Asset Transaction. 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. 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.

Cash and Cash Equivalents

Cash and Cash Equivalents	12 Months Ended
	Dec. 31, 2016
Cash and Cash Equivalents
Cash and Cash Equivalents	Note 4. Cash and Cash Equivalents As of December 31, 2016 and 2015, cash and cash equivalents consisted of the following (in thousands): December 31, 2016 2015 Cash at banks $ $ Money market funds Total cash and cash equivalents $ $

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
Long-Term Debt
Long-Term Debt	Note 5. Long‑Term Debt Long-term debt as of December 31, 2016 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. During the first quarter 2016, the Company adopted ASU 2015-03 retrospectively to the comparable periods in this Form 10-Q. Adoption of this guidance affected the balance sheets as of December 31, 2015 as follows (in thousands): Decrease in Long term debt, net of premium, discount and debt issuance costs of approximately $41,039 Decrease in Debt issuance costs, net (Other Assets) of approximately $41,039 As of December 31, 2016 and 2015 the Company’s long-term debt consisted of the following: Amount Outstanding (in thousands) as of December 31, December 31, Interest Rate Maturity date 2016 2015 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 Unamortized debt issuance costs Total long-term debt $ $ The components of interest expense are (in thousands): Year Ended December 31, 2016 2015 2014 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, 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 and collateral agent, and the 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 and collateral agent, and the lenders party thereto (together with all subsequent amendments, the ‘‘Second Amended and Restated Credit Agreement’’). 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, 2016, there were no borrowings and no letters of credit outstanding under the Second Amended and Restated Credit Agreement, which had a borrowing base of $350 million and aggregate elected commitments of $300 million. 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 amount. All of the $300 million aggregate elected commitment amount was available for future revolver borrowings as of December 31, 2016. The Second Amended and Restated Credit Agreement matures on June 30, 2019. The borrowing base under the Second Amended and Restated Credit Agreement is redetermined semi-annually by the lenders based on, among other things, an evaluation of the Company’s and its restricted subsidiaries’ oil and natural gas reserves. Semi-annual redeterminations of the borrowing base are generally scheduled to occur 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 second lien debt, other than high yield or second lien debt issued in exchange for or to refinance existing high yield debt, permitted second lien debt incurred to refinance or replace permitted second lien debt, and permitted 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 a majority of the lenders once between each scheduled redetermination, and (iv) if the required lenders so direct, in connection with asset sales and swap terminations during the period since the most recent borrowing base determination with a combined borrowing base value of more than 10% of the value of the proved developed oil and gas properties included in the most recent reserve report, a reduction in an amount equal to the borrowing base value, as determined by the administrative agent in its reasonable judgment, of such assets and swaps The Company’s 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” and secured by a first priority lien on substantially all of the Company’s assets and the assets of its existing and future subsidiaries including the SPV, defined below, an “unrestricted subsidiary,” but excluding other subsidiaries designated as “unrestricted subsidiaries,” including a first priority lien on all ownership interests in existing and future subsidiaries not designated as “unrestricted subsidiaries.” At the Company’s election, interest on borrowings under the Second Amended and Restated Credit Agreement may be calculated based on an alternate base rate or an adjusted eurodollar (LIBOR) rate, plus an applicable margin. The applicable margin varies from 1.00% to 2.00% for alternate base rate borrowings and from 2.00% to 3.00% for eurodollar (LIBOR) borrowings and letters of credit, if any, depending on the Company’s utilization of the borrowing base. The Company is also required to pay a commitment fee of 0.50% per annum on any unused aggregate elected commitment amount. 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 investments, engage in transactions with affiliates, enter into hedge transactions and make 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) net first lien debt (defined as the excess of first lien debt over cash) to consolidated last twelve months EBITDA of not greater than 2.00 to 1.0 as of the last day of any fiscal quarter. As of December 31, 2016, the Company was in compliance with the covenants of the Second Amended and Restated Credit Agreement. The Second Amended and Restated Credit Amendment, among other things, also (a) permits the repurchase by the Company and its restricted subsidiaries, or by a special purpose unrestricted subsidiary of the Company (the “SPV”), of the Company’s senior unsecured notes and common and preferred equity securities, from cash in excess of lender credit exposure in an aggregate amount up to approximately $298.5 million subject to certain caps on purchases of the Company’s common and preferred equity securities and other limitations; (b) permits (i) the formation and capitalization of the SPV with up to $150 million, (ii) the SPV to purchase, hold and dispose of, including by way of distribution to its immediate parent, up to $150 million of the Company’s senior unsecured notes and common and preferred equity securities, (iii) the SPV to hold cash received from its immediate parent in a deposit account maintained with a lender under the Second Amended and Restated Credit Agreement, and (iv) the SPV to distribute cash to its immediate parent; (c) requires (i) the Company to cause the SPV to distribute all cash held by it or in its name as of the close of business on December 31, 2016 to its immediate parent, (ii) the equity interests in the SPV to be pledged in favor of the secured parties and (iii) the Company to maintain all deposits, securities and commodity accounts with lenders or affiliates of lenders under the Second Amended and Restated Credit Agreement and to enter into account control agreements in favor of the administrative agent for the benefit of the secured parties in respect of each of such accounts; (d) provides that, in the event of a borrowing base deficiency, the Company shall use unrestricted cash of the Company and its subsidiaries in excess of $35 million to prepay borrowings and cash collateralize letter of credit exposure, as applicable; and (e) restricts the Company from increasing its aggregate elected commitment amount until the lenders’ next regularly scheduled borrowing base redetermination, which is expected to occur in the fourth quarter 2016. 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. 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 on the notes 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 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 our acquisition of contiguous acreage in McMullen County, Texas (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 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 $850 million in aggregate principal amount senior unsecured 6.125% notes due 2023 (the Original 6.125% Notes). Interest on the notes 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 used 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. Pursuant to tripartite agreements by and among the Company, U.S. Bank National Association (“U.S. Bank”) and Delaware Trust Company (“Delaware Trust”), effective May 20, 2016, U.S. Bank resigned as the Trustee, Notes Custodian, Registar and Paying Agent (“Trustee”) under the indentures of the Senior Notes and Delaware Trust was appointed as successor Trustee. No other changes to the indentures for the 6.125% Notes or the 7.75% Notes were made at the time of the change in Trustee.

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2016
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 $241.4 million, after deducting underwriters’ fees and offering expenses of $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. As discussed further below in Note 19, “Subsequent Events,” on February 6, 2017, the Company completed a public offering of 11,500,000 shares of common stock (including 1,500,000 shares purchased pursuant to the full exercise of the underwriters’ overallotment option), at an issue price of $12.50 per share. The Company received net proceeds from this offering of $135.9 million, after deducting underwriters’ discounts fees of approximately $7.8 million. Series A Preferred Stock Offering —On September 17, 2012, the Company completed a private placement of 3,000,000 shares of Series A 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 Preferred Stock was $50.00. The Company received net proceeds from the private placement of $144.5 million, after deducting initial purchasers’ discounts and commissions and offering costs of $5.5 million. Each share of Series A 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 Preferred Stock (which is equal to an initial conversion price of $21.51 per share of common stock) and is subject to specified adjustments. As of December 31, 2016, 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 Preferred Stock. The annual dividend on each share of Series A 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, 2016, all dividends accumulated through that date had been paid. The dividends accrued for the period from October 1 to December 31, 2016, were declared by the Board and paid with the Company’s common stock on January 3, 2017. Except as required by law or the Company’s Amended and Restated Certificate of Incorporation, (the “Charter”), holders of the Series A 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 Preferred Stock and the holders of the Series B 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 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 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 Preferred Stock as a result of the fundamental change. Series B Preferred Stock Offering —On March 26, 2013, the Company completed a private placement of 4,500,000 shares of Series B Preferred Stock. The issue price of each share of the Series B 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 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 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. As of December 31, 2016, based on the initial conversion price, approximately 8,244,539 shares of common stock would be issuable upon conversion of all of the outstanding shares of the Series B Preferred Stock. The annual dividend on each share of Series B 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, 2016, all dividends accumulated through that date had been paid. The dividends accrued for the period from October 1 to December 31, 2016, were declared by the Board and paid with the Company’s common stock on January 3, 2017. Except as required by law or the Charter, holders of the Series B 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 Preferred Stock and the holders of the Series A 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 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 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 Preferred Stock as a result of the fundamental change. Preferred Stock Exchange —On February 12, 2014 and February 13, 2014, the Company entered into exchange agreements with certain holders (the “February 2014 Holders”) of the Series A Preferred Stock and the Series B Preferred Stock pursuant to which such holders agreed to exchange an aggregate of (i) 947,490 shares of the Series A 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 Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 2,021,066 shares of the Company’s common stock. Additionally, on May 29, 2014, the Company entered into exchange agreements with certain holders (the “May 2014 Holders”) of the Series A Preferred Stock and the Series B Preferred Stock pursuant to which such holders agreed to exchange an aggregate of (i) 166,025 shares of the Series A 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 Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 553,980 shares of the Company’s 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 Series A Preferred Stock, pursuant to which such holders agreed to exchange an aggregate of 47,500 shares of Series A 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 shares of common stock for each preferred share exchanged for Series A Preferred Stock and Series B 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 (i.e., as an increase in accumulated deficit) to arrive at net loss attributable to common stockholders in our condensed consolidated financial statements. Preferred Stock Conversion— On November 20, 2015, a holder of our Series B Preferred Stock exercised its right to convert 4,500 shares our Series B Preferred Stock, at the prescribed initial conversion rate of 2.337 shares of common stock per share of Series B 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 the Company’s 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 earnings (loss) per share for the years ended December 31, 2016, 2015, and 2014 (in thousands, except per share amounts): Year Ended December 31, 2016 2015 2014 Net loss $ $ $ Less: Preferred stock dividends Net loss allocable to participating securities (1)(2) — — — Net loss attributable to common stockholders $ $ $ Weighted average number of unrestricted outstanding common shares used to calculate basic net loss per share Dilutive shares (3)(4)(5) — — — Denominator for diluted loss per common share Net 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, 2016, 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, 2016 excludes 2,113,462 shares of weighted average restricted stock and 12,554,481 shares of common stock resulting from an assumed conversion of the Company's Series A Preferred Stock and Series B Preferred Stock from the calculation of the denominator for diluted earnings (loss) per common share as these shares were anti-dilutive. (4) The year ended December 31, 2015 excludes 2,663,010 shares of weighted average restricted stock and 12,529,314 shares of common stock resulting from an assumed conversion of the Company's Series A Preferred Stock and Series B Preferred Stock from the calculation of the denominator for diluted earnings (loss) per common share as these shares were anti-dilutive. (5) 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 Preferred Stock and Series B Preferred Stock from the calculation of the denominator for diluted earnings (loss) per common share as these shares were anti-dilutive.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2016
Stock-Based Compensation
Stock-Based Compensation	Note 7. Stock‑Based Compensation At the Annual Meeting of Stockholders of the Company held on May 24, 2016 (“2016 Annual Meeting”), the Company’s stockholders approved the Sanchez Energy Corporation Third Amended and Restated 2011 Long Term Incentive Plan (the “LTIP”). The Board had previously approved the LTIP on May 21, 2015, subject to stockholder approval. The Company’s directors and consultants as well as employees of SOG and its 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 stock options, stock appreciation rights, restricted shares, phantom stock, other stock-based awards or stock awards, or any combination thereof. The maximum shares of common stock that may be delivered with respect to awards under the LTIP shall be (i) 17,239,790 shares plus (ii) upon the issuance of additional shares of common stock from time to time after April 1, 2016, an automatic increase equal to the lesser of (A) 15% of such issuance of additional shares of common stock, and (B) such lesser number of shares of common stock as determined by the Board or Compensation Committee; provided, however, withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. If any award is forfeited, cancelled, exercised, paid, or otherwise terminates or expires without the actual delivery of shares of common stock pursuant to such award (the grant of restricted stock is not a delivery of shares of common stock for this purpose), the shares subject to such award shall again be available for awards under the LTIP. There shall not be any limitation on the number of awards that may be paid in cash. Any shares delivered pursuant an award shall consist, in whole or in part, of shares of common stock newly issued by the Company, shares of common stock acquired in the open market, from any affiliate of the Company, or any combination of the foregoing, as determined by the Board or Compensation Committee in its discretion. The LTIP is administered by the Compensation Committee of the Board 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 stockholder approval as may be required by the exchange upon which shares of the common stock 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. The Company records stock-based compensation expense for awards granted to its directors (for their services as directors) in accordance with the provisions of ASC 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 (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 re-measured 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. During the year ended December 31, 2016, the Company issued 156,126 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 $8.00 and $5.81 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 4.4 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 1.1 million shares of restricted common stock with cliff vesting at the end of a five-year period or earlier if the common stock closing price equals or exceeds certain benchmarks as set forth in the forms of agreement. 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 approximately 0.1 million shares of restricted common stock vest in equal annual 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 value 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 one year 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. In February 2016 and April 2016, the Compensation Committee approved several new forms of agreement for use in equity awards pursuant to the LTIP. The new forms of agreements consist of two new forms of restricted stock award agreements, one of which provides for vesting in equal annual increments over a three year period from the grant date (the “Grant Date”) and the other of which provides for cliff vesting five years after the Grant Date or earlier if the common stock closing price equals or exceeds certain benchmarks as set forth in the form of agreement (the “Performance Accelerated Restricted Stock” or “PARS”), and two new forms of phantom stock agreements payable only in cash, one of which provides for vesting in equal annual increments over a three year period from the Grant Date (the “Phantom Stock”) and the other of which provides for cliff vesting five years after the Grant Date or earlier if the Company’s common stock closing price equals or exceeds certain benchmarks as set forth in the form of agreement (the “Performance Accelerated Phantom Stock” or “PAPS”). The PARS, PAPS and Phantom Stock awards granted to certain employees of the Sanchez Group (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 718, “Compensation – Stock Compensation.” In accordance with the guidance, the inclusion of market performance acceleration conditions does not change the accounting classification as compared to the restricted stock without market performance acceleration conditions, as both are still classified as equity within the Company’s balance sheet. The Phantom Stock awards are required to be settled in cash by the Company and, per the guidance, should be classified as a liability. Compensation expense for the unvested awards is revalued at each period end and is amortized over the vesting period of the stock-based award. During the year ended December 31, 2016, the Company issued approximately 1.1 million shares of PARS pursuant to the LTIP to certain employees of SOG (including the Company’s officers), with whom the Company has a services agreement. These PARS shares vest have cliff vesting at the end of a five-year period or earlier if the common stock closing price equals or exceeds certain benchmarks as set forth in the forms of agreement. During the year ended December 31, 2016, the Company issued approximately 4.0 million shares of Phantom Stock and PAPS pursuant to the LTIP to certain employees of SOG (including the Company’s officers), with whom the Company has a services agreement. Approximately 2.8 million shares of Phantom Stock vest in equal annual amounts over a three-year period and the remaining 1.2 million shares of PAPS have cliff vesting at the end of a five-year period or earlier if the common stock closing price equals or exceeds certain benchmarks as set forth in the forms of agreement. The Company recognized the following stock-based compensation expense (in thousands) which is included in general and administrative expense in the condensed consolidated statements of operations. Year Ended December 31, 2016 2015 2014 Restricted stock awards, directors $ $ $ Restricted stock awards, non-employees Phantom Stock awards — — Total stock-based compensation expense $ $ $ Based on the $9.03 per share closing price of the Company’s common stock on December 31, 2016, there was approximately $22.2 million of unrecognized compensation cost related to these non‑vested restricted shares (excluding the PARS shares) outstanding. The cost is expected to be recognized over a weighted average period of approximately 1.85 years. Based on the $9.03 per share closing price of the Company’s common stock on December 31, 2016, there was approximately $3.9 million of unrecognized compensation cost related to these non‑vested PARS restricted shares outstanding. The cost is expected to be recognized over a weighted average period of approximately 3.42 years. Based on the $9.03 per share closing price of the Company’s common stock on December 31, 2016, there was approximately $23.2 million of unrecognized compensation cost related to the non ‑ vested PAPS and Phantom Stock award shares outstanding. The cost is expected to be recognized over an average period of approximately 2.50 years. A summary of the status of the non‑vested restricted common shares and PARS as of December 31, 2016 is presented below (in thousands, except per share amounts): Aggregate Weighted Intrinsic Number of Average Value Shares Fair Value (in thousands) Non-vested common stock at December 31, 2015 $ $ Granted Vested Forfeited Non-vested common stock at December 31, 2016 $ $ As of December 31, 2016, approximately 6.7 million shares remain available for future issuance to participants under the LTIP. A summary of the status of the non‑vested Phantom Stock shares and PAPS as of December 31, 2016 is presented below (in thousands, except per share amounts): Aggregate Weighted Intrinsic Number of Average Value Shares Fair Value (in thousands) Non-vested common stock at December 31, 2015 — $ — $ — Granted Vested — — — Forfeited Non-vested common stock at December 31, 2016 $ $

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Taxes
Income Taxes	Note 8. Income Taxes The components of the federal income tax provision for the years ended December 31, 2016, 2015 and 2014 are (in thousands): Year Ended December 31, 2016 2015 2014 Current expense as a result of current operations $ $ $ — Deferred benefit as a result of current operations Increase 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 of (0.7)% is summarized as follows (in thousands): Year Ended December 31, 2016 2015 2014 Income tax benefit at the federal statutory rate $ $ $ Officers' compensation limitation — State Taxes (net of federal benefit) — Non-deductible general and administrative expenses Percentage depletion carryforward — Other — — 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, 2016 2015 Deferred tax assets (liabilities): Derivative assets (obligations) $ $ 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, 2016, the Company had NOLs of approximately $1,200.9 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, 2016. On the basis of this evaluation, as of December 31, 2016, a valuation allowance of approximately $601.0 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. 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 2013. State statues vary by jurisdiction. As of December 31, 2016, 2015 and 2014, the Company had no material uncertain tax positions.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
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. Salaries 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, 2016, 2015 and 2014 are as follows (in thousands): Year Ended December 31, 2016 2015 2014 Administrative fees $ $ $ Third-party expenses Total included in general and administrative expenses $ $ $ As of December 31, 2016 and December 31, 2015, the Company had a net receivable from SOG and other members of the Sanchez Group of $6.4 million and $3.7 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, 2016 and December 31, 2015 consists primarily of advances paid related to leasehold and other costs paid to SOG. In addition, the net receivable as of December 31, 2016 and December 31, 2015 includes approximately $0.7 million and $0.7 million, respectively, of net receivable from Sanchez Resources, LLC (“Sanchez Resources”). As of December 31, 2016, the Company had a net payable to SPP of approximately $9.0 million that consists primarily of the November and 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. Production Asset Transaction On November 22, 2016, we completed the Production Asset Transaction discussed above to SPP, which is a related party (see Note 3, “Acquisitions and Divestitures”). Carnero Processing Disposition On November 22, 2016, we sold our membership interests in Carnero Processing, LLC (“Carnero Processing”), to SPP, which is a related party (see Note 16, “Investments”). Carnero Gathering Disposition On July 5, 2016, we sold our membership interests in Carnero Gathering, LLC (“Carnero Gathering”) to SPP, which is a related party (see Note 16, “Investments”). 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, 2016
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 modify the future prices to be realized. The derivative contracts may include fixed-for-floating price swaps (whereby, on the settlement date, the Company will receive or pay an amount based on the difference between a pre-determined fixed price and a variable market price for a notional quantity of production), put options (whereby the Company pays a cash premium in order to establish a fixed floor price for a notional quantity of production and, on the settlement date, receives the excess, if any, of the fixed price floor over a variable market price), and costless collars (whereby, on the settlement date, the Company receives the excess, if any, of a variable market price over a fixed floor price up to a fixed ceiling price for a notional quantity of production). In addition, the Company periodically enters into call swaptions as a way to achieve greater downside price protection than offered under prevailing fixed-for-floating price swaps by agreeing to expand the notional quantity hedged under a fixed-for-floating price swap at the counterparty’s election on a designated date. These hedging activities, which are governed by the terms of our Second Amended and Restated Credit Agreement, are intended to support oil and natural gas prices at targeted levels and manage exposure to oil and natural gas price fluctuations. It is our policy to enter into derivative contracts only with counterparties that are creditworthy and competitive market makers. All of our derivatives with lenders, or affiliates of lenders, in our Second Amended and Restated Credit Agreement are collateralized by the assets securing our Second Amended and Restated Credit Agreement and, therefore, do not currently require the posting of cash collateral. Our existing derivatives with non-lender counterparties, as designated under the Second Amended and Restated Credit Agreement, are unsecured and do not require the posting of cash collateral. It is never the Company’s intention to enter into derivative contracts for speculative trading purposes. All of our derivatives are accounted for as mark-to-market activities. Under ASC Topic 815, “Derivatives and Hedging,” these instruments are recorded on the condensed consolidated balance sheets at fair value as either short term or long term assets or liabilities based on their anticipated settlement date. The Company nets derivative assets and liabilities by commodity for counterparties where a legal right to such offset exists. Changes in the derivatives’ fair values are recognized in current earnings since the Company has elected not to designate its current derivative contracts as cash flow hedges for accounting purposes. The following table presents derivative positions for the periods indicated as of December 31, 2016: January 1 - December 31, 2017 2018 2019 Oil positions: Fixed-for-floating price swaps (NYMEX WTI): Hedged volume (Bbls) - - Average price ($/Bbl) $ $ - $ - Collars (NYMEX WTI): Hedged volume (Bbls) - - Average long put price ($/Bbl) $ $ - $ - Average short call price ($/Bbl) $ $ - $ - Natural gas positions: Fixed-for-floating price swaps (NYMEX Henry Hub): Hedged volume (MMBtu) Average price ($/MMBtu) $ $ $ 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, 2016, 2015, and 2014 (in thousands): Year Ended December 31, 2016 2015 2014 Beginning fair value of commodity derivatives $ $ $ Net gains (losses) on crude oil derivatives Net gains (losses) 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, 2016 Gross Amounts Net Amounts Gross Amount Offset in the Presented in the of Recognized Consolidated Consolidated Assets and Liabilities 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, 2015 Gross Amounts Net Amounts Gross Amount Offset in the Presented in the of Recognized Consolidated Consolidated Assets and Liabilities 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, 2016
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, 2016 and 2015 (in thousands): As of December 31, 2016 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 $ $ — $ — $ Equity investment: Investment in SPP — — Oil derivative instruments: Swaps — — Collars — — Gas derivative instruments: Swaps — — Total $ $ $ — $ 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 $ $ $ — $ 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, 2016 and 2015. 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. In addition, the Level 1 instruments include the Company’s equity investment in common units of SPP as further discussed in Note 16, “Investments.” The investment in SPP is being accounting for under the fair value option, included in investments on the Company’s balance sheet as of December 31, 2016. The Company identified the common units in SPP as a Level 1 instruments due to the fact that SPP is a publicly traded company on the NYSE MKT with daily quoted prices that can be easily obtained. The Company’s derivative instruments, which consist of swaps, collars and puts, are classified as Level 2 as of December 31, 2016 and 2015, 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. Swaps and collars generally have no unobservable inputs and they are classified as Level 2. Puts and call swaption derivatives have inputs which are observable, either directly or indirectly, using market data. As of December 31, 2016 and 2015, the Company believes that substantially all of the inputs required to calculate the fair value of puts and call swaptions are 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, 2016 or December 31, 2015. The fair values of the Company’s derivative instruments classified as Level 3 as of December 31, 2014 were $75.5 million. 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, 2016 2015 2014 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, 2016, 2015, and 2014 $ — $ $ (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 Acquisition is 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 Preferred Stock and Series B 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 Preferred Stock exercised its right to convert 4,500 shares our Series B Preferred Stock, at the prescribed initial conversion rate of 2.337 shares of common stock per share of Series B 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. There were no conversions of Series A Preferred Stock or Series B Preferred Stock into shares of the Company’s common stock during the year ended December 31, 2016. 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 $612.0 million as of December 31, 2016, 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 $1,098.3 million as of December 31, 2016 .

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 were as follows (in thousands): December 31, 2016 2015 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, 2016
Accrued Liabilities
Accrued Liabilities	Note 13. Accrued Liabilities The following information summarizes accrued liabilities as of December 31, 2016 and 2015 (in thousands): As of December 31, 2016 2015 Capital expenditures $ $ Other: General and administrative costs Production taxes Ad valorem taxes Lease operating expenses Interest payable Preferred stock dividends and other — Total accrued liabilities $ $

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies
Commitments and Contingencies	Note 14. Commitments and Contingencies Litigation 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, 2013, and December 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 SR. 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 SR, 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. The Consolidated Derivative Actions are currently in the early stages of discovery. A mediation in connection with the matter was held on July 7, 2016. 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. 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. Catarina Drilling Obligation 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. Lease Payment Obligations As of December 31, 2016, the Company had $216.4 million in lease payment obligations that satisfy operating lease criteria. These obligations include: (i) $158.6 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) $45.7 million for a corporate office lease that commenced in the fourth quarter of 2014 and has an expiration date in March 2025, (iii) $6.2 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) $5.9 million for a 10 year acreage lease agreement for a promotional ranch managed by the Company in Kenedy County, Texas. The lease agreement for the acreage in Kenedy County, Texas 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 has the right to terminate the lease obligation without penalty at any time with nine months advanced written notice and payment of any accrued leasehold expenses. 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.

Subsidiary Guarantors

Subsidiary Guarantors	12 Months Ended
	Dec. 31, 2016
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 April 25, 2016 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, 2016, 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, 2016, 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. 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, 2016, 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. The rules of Regulation S-X Rule 3-10 require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is 100% owned by the registrant. See Note 18, “Condensed Consolidating Financial Information” for further discussion regarding the condensed consolidating financial information for guarantor and non-guarantor subsidiaries. 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, 2016
Investments
Investments	Note 16. Investments On November 22, 2016, a subsidiary of the Company purchased 2,272,727 common units of SPP for $25.0 million as part of a private equity issuance. As of December 31, 2016, this ownership represents approximately 16.9% of SPP’s common units outstanding. Rather than accounting for the investment under the equity method, the Company elected the fair value option to account for its interest in SPP. The Company records the equity investment in SPP at fair value at the end of each reporting period. Any gains or losses are recorded as a component of other income (expense) in the consolidated statement of operations. The Company recorded gains related to the investment in SPP for the twelve months ended December 31, 2016 of approximately $1.8 million. 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 is processing a firm quantity, 125,000 Mcf/d, until the in-service date of the Carnero Processing Plant discussed below. 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, 2016, the Company had invested capital of $12.5 million in the SOII Facility. The Company recorded earnings from the SOII Facility investment of approximately $1.2 million from equity investments during 2016. On November 22, 2016, SN Midstream sold its membership interests in Carnero Processing to SPP for an initial payment of $55.5 million and the assumption by SPP of remaining capital commitments to Carnero Processing, which are estimated at approximately $24.5 million (the “Carnero Processing Disposition”). The Company was accounting for this joint venture as an equity method investment 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. Prior to the sale, the Company had invested approximately $48.0 million in Carnero Processing joint venture. The membership interests disposed of constitute 50% of the outstanding membership interests in Carnero Processing. The remaining 50% membership interests of Carnero Processing are owned by an affiliate of Targa. Prior to the sale of Carnero Processing, the Company recorded losses of approximately $0.1 million from equity investments during 2016. The Company recorded a deferred gain of approximately $7.5 million included in “Other Liabilities” as a result of the firm gas processing agreement that remains between the Company and Targa. This deferred gain will be amortized periodically over the term of this firm gas processing agreement according to volumes processed through the Carnero Processing facility. On July 5, 2016, SN Midstream sold its membership interests in Carnero Gathering to SPP for an initial payment of approximately $37.0 million and the assumption by SPP of remaining capital commitments to Carnero Gathering, estimated at approximately $7.4 million (the “Carnero Gathering Disposition”). The Company was accounting for this joint venture as an equity method investment 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. Prior to the sale, the Company had invested approximately $26.0 million in Carnero Gathering joint venture. As part of the Carnero Gathering Disposition, SPP is required to pay SN Midstream a monthly earnout based on gas received at Carnero Gathering’s receipt points from SN Catarina and gas delivered and processed at the Processing Plant by other producers. The membership interests disposed of constitute 50% of the outstanding membership interests in Carnero Gathering. The remaining 50% membership interests of Carnero Gathering are owned by an affiliate of Targa. Prior to the sale of Carnero Gathering, the Company recorded earnings of approximately $2.3 million from equity investments during 2016. The Company recorded a deferred gain of approximately $8.7 million included in “Other Liabilities” as a result of the firm gas gathering agreement that remains between the Company and Targa and a transportation services agreement between Targa and Carnero Gathering. This deferred gain will be amortized periodically over the term of this firm gas gathering agreement according to volumes delivered through the Carnero Gathering pipelines.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2016
Variable Interest Entities
Variable Interest Entities	Note 17. Variable Interest Entities During the first quarter of 2016, the Company adopted ASU 2015-02, “Consolidation—Amendments to the Consolidation Analysis,” which introduces a separate analysis for determining if limited partnerships and similar entities are variable interest entities (“VIEs”) and clarifies the steps a reporting entity would have to take to determine whether the voting rights of stockholders in a corporation or similar entity are substantive. As noted above in Note 16, “Investments,” the Company, through SN Midstream, entered into joint venture agreements with an affiliate of Targa in October 2015 to, among other things, construct the Processing Plant and associated high pressure gathering pipelines near the Company’s Catarina asset in South Texas. In addition, the Company, via SN Catarina, purchased from a subsidiary of Targa a 10% undivided interest in the SOII Facility. As noted above in Note 16, “Investments,” on July 5, 2016 and November 22, 2016, the Company sold its interests, and any remaining commitment to invest in Carnero Gathering and Carnero Processing, respectively, to SPP. The Company determined that ownership in the SOII Facility are more similar to limited partnerships than corporations. Under the revised guidance of ASU 2015-02, a limited partnership or similar entity with equity at risk will not be a VIE if they are able to exercise kick-out rights over the general partner(s) or they are able to exercise substantive participating rights. We concluded that the investment in SOII Facility is a VIE under the revised guidance because we cannot remove Targa as operator and we do not have substantive participating rights. In addition, Targa has the discretion to direct activities of the VIEs regarding the risks associated with price, operations, and capital investment which have the most significant impact on the VIEs economic performance. The Company’s investment in the SOII Facility represents a VIE that could expose the Company to losses. The amount of losses the Company could be exposed to from the investment in the SOII Facility is limited to the equity in the investment at any point in time. As of December 31, 2016, the Company had invested capital of $12.5 million in the SOII Facility, and recorded earnings from the equity investment of $0.3 million. As of December 31, 2016, no debt has been incurred by the SOII Facility. The Company is accounting for the VIE as an equity method investment and determined that Targa is the primary beneficiary of the VIE as Targa is the operator of the SOII Facility and has the most influence with respect to the normal day-to-day operating decisions of the facility. We have included the VIE in the “Other Assets - Investments” long-term asset line on the balance sheet. As noted above in Note 16, “Investments,” in November 2016, the Company purchased common units of SPP for $25.0 million as part of a private equity issuance. Rather than accounting for the investment under the equity method, the Company elected the fair value option to account for its interest in SPP. The Company’s investment in SPP represents a VIE that could expose the Company to losses limited to the equity in the investment at any point in time. The carrying amounts of the investment in SPP and the Company’s maximum exposure to loss as of December 31, 2016, was approximately $26.8 million. Below is a tabular comparison of the carrying amounts of the assets and liabilities of the VIE and the Company’s maximum exposure to loss as of December 31, 2016 and December 31, 2015 (in thousands): December 31, December 31, 2016 2015 Capital investments $ $ Earnings in equity investments — Gain (loss) from change in fair value of investment in SPP — Equity in equity investments $ $ December 31, December 31, 2016 2015 Equity in equity investments $ $ Guarantees of capital investments — Maximum exposure to loss $ $

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2016
Condensed Consolidating Financial Information
Condensed Consolidating Financial Information	Note 18. Condensed Consolidating Financial Information As noted above, the rules of the SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is 100% owned by the registrant. The Company is, therefore, presenting condensed consolidating financial information on a parent company, combined guarantor subsidiaries, combined non-guarantor subsidiaries and consolidated basis (in thousands) and should be read in conjunction with the consolidated financial statements. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had such guarantor subsidiaries operated as independent entities. Investments in subsidiaries are accounted for by the respective parent company using the equity method for purposes of this presentation. Results of operations of subsidiaries are, therefore, reflected in the parent company’s investment accounts and earnings. The principal elimination entries set forth below eliminate investments in subsidiaries and intercompany balances and transactions. Typically, in a condensed consolidating financial statement, the net income and equity of the parent company equals the net income and equity of the consolidated entity. December 31, 2016 Assets Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total current assets $ $ $ $ $ Total oil and natural gas properties, net - - - Investment in subsidiaries - - - Other assets - Total Assets $ $ $ $ $ Liabilities and Shareholders' Equity Current liabilities $ $ $ $ $ Long-term liabilities Total shareholders' equity (deficit) Total Liabilities and Shareholders' Equity (deficit) $ $ $ $ $ December 31, 2015 Assets Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total current assets $ $ $ $ $ Total oil and natural gas properties, net - - - Investment in subsidiaries - - - Other assets - Total Assets $ $ $ $ $ Liabilities and Shareholders' Equity Current liabilities $ $ $ $ $ Long-term liabilities - - Total shareholders' equity (deficit) Total Liabilities and Shareholders' Equity (deficit) $ $ $ $ $ Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total revenues $ - $ $ - $ - $ Total operating costs and expenses - Other income (expense) - Income (loss) before income taxes - Income tax expense - - - Equity in income (loss) of subsidiaries - - - Net income (loss) $ $ $ $ $ Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total revenues $ - $ $ - $ - $ Total operating costs and expenses - Other income (expense) - - Loss before income taxes - Income tax expense - - - Equity in income (loss) of subsidiaries - - - Net income (loss) $ $ $ $ $ Year Ended December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total revenues $ - $ $ - $ - $ Total operating costs and expenses - Other income (expense) - - Loss before income taxes - Income tax benefit - - - Equity in income (loss) of subsidiaries - - - Net income (loss) $ $ $ $ $ Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ $ $ $ - $ Net cash provided by (used in) investing activities Net cash provided by (used in) financing activities Net increase (decrease) in cash and cash equivalents - - Cash and cash equivalents, beginning of period - - Cash and cash equivalents, end of period $ $ - $ $ - $ Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ $ $ $ - $ Net cash provided by (used in) investing activities Net cash provided by (used in) financing activities Net increase (decrease) in cash and cash equivalents - - Cash and cash equivalents, beginning of period - - - Cash and cash equivalents, end of period $ $ - $ $ - $ Year Ended December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ $ $ $ - $ Net cash provided by (used in) investing activities Net cash provided by (used in) financing activities Net increase (decrease) in cash and cash equivalents - - - Cash and cash equivalents, beginning of period - - - Cash and cash equivalents, end of period $ $ - $ - $ - $

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2016
Subsequent Events.
Subsequent Events	Note 19. Subsequent Events On January 12, 2017, the Company, through two of our subsidiaries, SN EF UnSub, LP (“SN UnSub”) and SN EF Maverick, LLC (“SN Maverick”), along with an entity controlled by The Blackstone Group, L.P., Gavilan Resources, LLC (“Blackstone”), signed a purchase and sale agreement (the “Comanche Purchase Agreement”) to acquire assets (the “Comanche Assets”) from Anadarko E&P Onshore LLC and Kerr-McGee Oil and Gas Onshore LP for $2,275 million in cash, subject to customary closing adjustments (the “Comanche Acquisition”). The Comanche Assets are primarily located in the Western Eagle Ford Shale and are expected to significantly expand our asset base and production. The Comanche Assets consist of approximately 318,000 gross (155,000 net) acres comprised of 252,000 gross (122,000 net) Eagle Ford Shale acres and 66,000 gross (33,000 net) Pearsall Shale acres, with an approximate 49% average working interest therein, contain approximately 300 MMBoe of proved reserves (70% liquids, 75% proved developed), and had production of approximately 67,000 Boe/d (70% liquids) as of December 31, 2016. The Comanche Purchase Agreement provides that SN UnSub will pay approximately 37% of the purchase price (including through a $100 million cash contribution from the Company) and SN Maverick will pay approximately 13% of the purchase price and SN UnSub and SN Maverick would acquire half of the 49% working interest in and to the Comanche Assets in the aggregate (and approximately 50% and 0%, respectively, of the estimated total proved developed producing reserves, 20% and 30%, respectively, of the estimated total proved developed non-producing reserves, and 20% and 30%, respectively, of the total proved undeveloped reserves), and Blackstone will pay 50% of the purchase price and would acquire the remaining half of the 49% working interest in and to the Comanche Assets (approximately 50% of the estimated total proved developed producing reserves, proved developed non-producing reserves and proved undeveloped reserves). We expect to close the Comanche Acquisition during the first quarter of 2017. The effective date of the transaction is July 1, 2016. On February 6, 2017, the Company completed an underwritten public offering of 10,000,000 shares of the Company's common stock at a price of $12.50 per share ($11.7902 per share, net of underwriting discounts). The Company granted the Underwriters a 30-day option to purchase up to an additional 1,500,000 shares of the Company’s common stock on the same terms, which was exercised in full and closed on February 6, 2017. The Company received net proceeds of approximately $135.9 million (after deducting underwriting discounts of approximately $7.8 million) from the sale of the shares of common stock. The Company intends to use the net proceeds of the offering for general corporate purposes, including working capital.

Basis of Presentation and Sum28

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Basis of Presentation and Summary of Significant Accounting Policies
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”).
Recent Accounting Pronouncements	Recent Accounting Pronouncements In January 2017, the FASB issued Accounting Standards Update (“ASU”) 2017-01 “Business Combinations (Topic 805) - Clarifying the Definition of a Business,” which provides a new framework for determining whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. Early adoption is permitted, and the Company is currently in the process of evaluating the impact of adoption of this guidance on its consolidated financial statements. In December 2016, the FASB issued Accounting Standards Update ASU 2016-19 “Technical Corrections and Improvements,” which amends a number of Topics in the FASB ASC. The ASU is part of an ongoing FASB project to facilitate Codification updates for non-substantive technical corrections, clarifications, and improvements that are not expected to have a significant effect on accounting practice or create a significant administrative cost to most entities. The ASU will apply to all reporting entities within the scope of the affected accounting guidance. Most amendments are effective upon issuance (December 2016). In November 2016, the FASB issued ASU 2016-18 “Statement of Cash Flows (Topic 230): Restricted Cash,” which requires companies to include cash and cash equivalents that have restrictions on withdrawal or use in total cash and cash equivalents on the statement of cash flows. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. Early adoption is permitted, and the Company is currently in the process of evaluating the impact of adoption of this guidance on its consolidated financial statements. In October 2016, the FASB issued ASU 2016-16 “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” which eliminates a current exception in U.S. GAAP to the recognition of the income tax effects of temporary differences that result from intra-entity transfers of non-inventory assets. The intra-entity exception is being eliminated under the ASU. The standard is required to be applied on a modified retrospective basis and will be effective beginning with the first quarter of 2018. Early adoption is permitted, and the Company is currently in the process of evaluating the impact of adoption of this guidance on its consolidated financial statements. In August 2016, the FASB issued ASU No. 2016-15 “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments”. This ASU is intended to clarify the presentation of cash receipts and payments in specific situations. The amendments in this ASU are effective for financial statements issued for annual periods beginning after December 15, 2017, including interim periods within those annual periods, and early application is permitted. The Company does not anticipate that ASU 2016-15 will have a material effect on its consolidated and condensed financial statements and related disclosures. In March 2016, the FASB issued ASU No. 2016-09 “Improvements to Employee Share-Based Payment Accounting,” effective for annual and interim periods for public companies beginning after December 15, 2016, with a cumulative-effect and prospective approach to be used for implementation. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions including accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, minimum statutory tax withholding requirements and classification of employee taxes paid on the statement of cash flows when an employer withholds shares for tax-withholding purposes. The Company is currently in the process of evaluating the impact of adoption of this guidance on its consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018, with a modified retrospective approach to be used for implementation. The standard updates the previous lease guidance by requiring the recognition of a right-to-use asset and lease liability on the statement of financial position for all leases with lease terms of more than 12 months. The lease liability represents the discounted obligation to make future minimum lease payments and corresponding right-of-use asset on the balance sheet for most leases. Recognition, measurement and presentation of expenses and cash flows arising from a lease will depend on classification as a finance or operating lease. The Company has several operating leases as further discussed in Note 16, “Commitments and Contingencies,” which will be impacted by the new rules under this standard. The Company will not early adopt this standard, and will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019. The Company is currently evaluating the impact of these rules on its financial statements and has started the assessment process by evaluating the population of leases under the revised definition. The adoption of this standard will result in an increase in the assets and liabilities on the Company’s consolidated balance sheets. The quantitative impacts of the new standard are dependent on the leases in force at the time of adoption. As a result, the evaluation of the effect of the new standards will extend over future 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 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. The Company is currently in the process of evaluating the impact of adoption of this guidance on its consolidated financial statements, but do not expect the impact to be material. May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” In March, April, and May of 2016, the FASB issued rules clarifying several aspects of the new revenue recognition standard. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. 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 standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The Company will not early adopt the standard although early adoption is permitted. The Company is currently evaluating whether to apply the retrospective approach or modified retrospective approach with the cumulative effect recognized as of the date of initial application. The Company is currently evaluating the impact the standard is expected to have on its consolidated financial statements by evaluating current revenue streams and evaluating contracts under the revised standards.
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.
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, 2016 and 2015, 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, 2016, the Company recorded a full cost ceiling test impairment after income taxes of $169.0 million. 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. 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, 5%, 8% and 25% of the unproved property balance at December 31, 2016 is expected to be added to the amortization base during the years 2017, 2018 and 2019, respectively. The remaining balances in unproved properties relate to project areas that will not be thoroughly evaluated until after 2019, and represent leasehold interests that have expiration dates beginning in 2020 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, 2016, and notes the year in which the associated costs were incurred (in thousands): Year of Acquisition Prior to 2014 2014 2015 2016 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, 2016, 2015 and 2014 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 2016, the Company capitalized approximately $0.1 million in costs associated with the filing of a Form S-3 Registration Statement, and capitalized approximately $1.6 million associated with amending our Second Amended and Restated Agreement (as defined in Note 5, “Long-Term Debt”). During 2015, the Company capitalized approximately $0.4 million in costs associated with amending our Second Amended and Restated Agreement. 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 Catarina Acquisition (as defined in Note 3, “Acquisitions and Divestitures”). At December 31, 2016 and December 31, 2015, the Company had approximately $35.0 million and $41.0 million, respectively, of debt issuance costs (net of accumulated amortization of $22.5 million and $14.7 million, respectively) remaining that are being amortized over the terms of the respective debt. In accordance with ASU 2015-03, “Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs,” the debt issuance costs related to the issuance of the 6.125% Notes and Second Amended and Restated Agreement are presented on the balance sheet as a direct deduction from the long-term 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, 2016 and 2015.
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. Stock-based compensation awards and phantom stock awards, including those awards with market performance acceleration conditions, 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. In accordance with the guidance, the inclusion of market performance acceleration conditions does not change the accounting classification as compared to those awards without market performance acceleration conditions. The phantom stock awards are required to be settled in cash by the Company and are classified as a liability. Compensation expense for the unvested awards is revalued at each period end and is amortized over the vesting period of the stock-based award.
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, 2016, 2015 and 2014 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, 2016, 2015 and 2014 as listed below: 2016 2015 2014 Customer A Customer B Customer C Customer D Customer E 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, 2016 or 2015.
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 Preferred Stock using the if‑converted method, if the effect is dilutive.

Basis of Presentation and Sum29

Basis of Presentation and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016, and notes the year in which the associated costs were incurred (in thousands): Year of Acquisition Prior to 2014 2014 2015 2016 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	2016 2015 2014 Customer A Customer B Customer C Customer D Customer E

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2016
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 $

Cash and Cash Equivalents (Tabl

Cash and Cash Equivalents (Tables)	12 Months Ended
	Dec. 31, 2016
Cash and Cash Equivalents
Schedule of cash and cash equivalents	As of December 31, 2016 and 2015, cash and cash equivalents consisted of the following (in thousands): December 31, 2016 2015 Cash at banks $ $ Money market funds Total cash and cash equivalents $ $

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Long-Term Debt
Schedule of long-term debt	Amount Outstanding (in thousands) as of December 31, December 31, Interest Rate Maturity date 2016 2015 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 Unamortized debt issuance costs Total long-term debt $ $
Schedule of interest expense	The components of interest expense are (in thousands): Year Ended December 31, 2016 2015 2014 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, 2016
Stockholders' Equity
Schedule of computation of basic and diluted net earnings (loss) per share	Earnings (Loss) Per Share —The following table shows the computation of basic and diluted net earnings (loss) per share for the years ended December 31, 2016, 2015, and 2014 (in thousands, except per share amounts): Year Ended December 31, 2016 2015 2014 Net loss $ $ $ Less: Preferred stock dividends Net loss allocable to participating securities (1)(2) — — — Net loss attributable to common stockholders $ $ $ Weighted average number of unrestricted outstanding common shares used to calculate basic net loss per share Dilutive shares (3)(4)(5) — — — Denominator for diluted loss per common share Net 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, 2016, 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, 2016 excludes 2,113,462 shares of weighted average restricted stock and 12,554,481 shares of common stock resulting from an assumed conversion of the Company's Series A Preferred Stock and Series B Preferred Stock from the calculation of the denominator for diluted earnings (loss) per common share as these shares were anti-dilutive. (4) The year ended December 31, 2015 excludes 2,663,010 shares of weighted average restricted stock and 12,529,314 shares of common stock resulting from an assumed conversion of the Company's Series A Preferred Stock and Series B Preferred Stock from the calculation of the denominator for diluted earnings (loss) per common share as these shares were anti-dilutive. 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 Preferred Stock and Series B Preferred Stock from the calculation of the denominator for diluted earnings (loss) per common share as these shares were anti-dilutive.

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
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 condensed consolidated statements of operations. Year Ended December 31, 2016 2015 2014 Restricted stock awards, directors $ $ $ Restricted stock awards, non-employees Phantom Stock awards — — Total stock-based compensation expense $ $ $
Restricted common shares and PARS
Summary of the status of the non-vested shares	A summary of the status of the non‑vested restricted common shares and PARS as of December 31, 2016 is presented below (in thousands, except per share amounts): Aggregate Weighted Intrinsic Number of Average Value Shares Fair Value (in thousands) Non-vested common stock at December 31, 2015 $ $ Granted Vested Forfeited Non-vested common stock at December 31, 2016 $ $
Phantom Stock shares and PAPS
Summary of the status of the non-vested shares	A summary of the status of the non‑vested Phantom Stock shares and PAPS as of December 31, 2016 is presented below (in thousands, except per share amounts): Aggregate Weighted Intrinsic Number of Average Value Shares Fair Value (in thousands) Non-vested common stock at December 31, 2015 — $ — $ — Granted Vested — — — Forfeited Non-vested common stock at December 31, 2016 $ $

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016, 2015 and 2014 are (in thousands): Year Ended December 31, 2016 2015 2014 Current expense as a result of current operations $ $ $ — Deferred benefit as a result of current operations Increase 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 of (0.7)% is summarized as follows (in thousands): Year Ended December 31, 2016 2015 2014 Income tax benefit at the federal statutory rate $ $ $ Officers' compensation limitation — State Taxes (net of federal benefit) — Non-deductible general and administrative expenses Percentage depletion carryforward — Other — — 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, 2016 2015 Deferred tax assets (liabilities): Derivative assets (obligations) $ $ 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, 2016
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, 2016, 2015 and 2014 are as follows (in thousands): Year Ended December 31, 2016 2015 2014 Administrative fees $ $ $ Third-party expenses Total included in general and administrative expenses $ $ $

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments
Schedule of derivative positions	January 1 - December 31, 2017 2018 2019 Oil positions: Fixed-for-floating price swaps (NYMEX WTI): Hedged volume (Bbls) - - Average price ($/Bbl) $ $ - $ - Collars (NYMEX WTI): Hedged volume (Bbls) - - Average long put price ($/Bbl) $ $ - $ - Average short call price ($/Bbl) $ $ - $ - Natural gas positions: Fixed-for-floating price swaps (NYMEX Henry Hub): Hedged volume (MMBtu) Average price ($/MMBtu) $ $ $
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, 2016, 2015, and 2014 (in thousands): Year Ended December 31, 2016 2015 2014 Beginning fair value of commodity derivatives $ $ $ Net gains (losses) on crude oil derivatives Net gains (losses) 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, 2016 Gross Amounts Net Amounts Gross Amount Offset in the Presented in the of Recognized Consolidated Consolidated Assets and Liabilities 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, 2015 Gross Amounts Net Amounts Gross Amount Offset in the Presented in the of Recognized Consolidated Consolidated Assets and Liabilities 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 Instr38

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015 (in thousands): As of December 31, 2016 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 $ $ — $ — $ Equity investment: Investment in SPP — — Oil derivative instruments: Swaps — — Collars — — Gas derivative instruments: Swaps — — Total $ $ $ — $ 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 $ $ $ — $
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, 2016 2015 2014 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, 2016, 2015, and 2014 $ — $ $ (1) Includes ($12,919) of net settlements in Level 2 that were transferred from Level 3 during 2015.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligations
Schedule of changes in asset retirement obligation	The changes in the asset retirement obligation for the years ended December 31, 2016 and 2015 were as follows (in thousands): December 31, 2016 2015 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, 2016
Accrued Liabilities
Summary of accrued liabilities	The following information summarizes accrued liabilities as of December 31, 2016 and 2015 (in thousands): As of December 31, 2016 2015 Capital expenditures $ $ Other: General and administrative costs Production taxes Ad valorem taxes Lease operating expenses Interest payable Preferred stock dividends and other — Total accrued liabilities $ $

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2016
Variable Interest Entities
Schedule of carrying amounts of assets and liabilities of VIE	Below is a tabular comparison of the carrying amounts of the assets and liabilities of the VIE and the Company’s maximum exposure to loss as of December 31, 2016 and December 31, 2015 (in thousands): December 31, December 31, 2016 2015 Capital investments $ $ Earnings in equity investments — Gain (loss) from change in fair value of investment in SPP — Equity in equity investments $ $ December 31, December 31, 2016 2015 Equity in equity investments $ $ Guarantees of capital investments — Maximum exposure to loss $ $

Condensed Consolidating Finan42

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2016
Condensed Consolidating Financial Information
Condensed balance sheet	December 31, 2016 Assets Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total current assets $ $ $ $ $ Total oil and natural gas properties, net - - - Investment in subsidiaries - - - Other assets - Total Assets $ $ $ $ $ Liabilities and Shareholders' Equity Current liabilities $ $ $ $ $ Long-term liabilities Total shareholders' equity (deficit) Total Liabilities and Shareholders' Equity (deficit) $ $ $ $ $ December 31, 2015 Assets Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total current assets $ $ $ $ $ Total oil and natural gas properties, net - - - Investment in subsidiaries - - - Other assets - Total Assets $ $ $ $ $ Liabilities and Shareholders' Equity Current liabilities $ $ $ $ $ Long-term liabilities - - Total shareholders' equity (deficit) Total Liabilities and Shareholders' Equity (deficit) $ $ $ $ $
Condensed income statement	Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total revenues $ - $ $ - $ - $ Total operating costs and expenses - Other income (expense) - Income (loss) before income taxes - Income tax expense - - - Equity in income (loss) of subsidiaries - - - Net income (loss) $ $ $ $ $ Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total revenues $ - $ $ - $ - $ Total operating costs and expenses - Other income (expense) - - Loss before income taxes - Income tax expense - - - Equity in income (loss) of subsidiaries - - - Net income (loss) $ $ $ $ $ Year Ended December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total revenues $ - $ $ - $ - $ Total operating costs and expenses - Other income (expense) - - Loss before income taxes - Income tax benefit - - - Equity in income (loss) of subsidiaries - - - Net income (loss) $ $ $ $ $
Condensed cash flow statement	Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ $ $ $ - $ Net cash provided by (used in) investing activities Net cash provided by (used in) financing activities Net increase (decrease) in cash and cash equivalents - - Cash and cash equivalents, beginning of period - - Cash and cash equivalents, end of period $ $ - $ $ - $ Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ $ $ $ - $ Net cash provided by (used in) investing activities Net cash provided by (used in) financing activities Net increase (decrease) in cash and cash equivalents - - Cash and cash equivalents, beginning of period - - - Cash and cash equivalents, end of period $ $ - $ $ - $ Year Ended December 31, 2014 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ $ $ $ - $ Net cash provided by (used in) investing activities Net cash provided by (used in) financing activities Net increase (decrease) in cash and cash equivalents - - - Cash and cash equivalents, beginning of period - - - Cash and cash equivalents, end of period $ $ - $ - $ - $

Organization and Business (Deta

Organization and Business (Details)	12 Months Ended
	Dec. 31, 2016a
The "Commanche Assets"
Accumulated area of property (in acres)	339,000
Area under agreement, net (in acres)	4,000
Area under agreement, gross (in acres)	7,000
Percentage of working interest owned	61.00%
Eagle Ford Shale
Accumulated area of property (in acres)	278,000
Percentage of working interest owned	94.00%

Basis of Presentation and Sum44

Basis of Presentation and Summary of Significant Accounting Policies (RecentAcctg) (Details) - New accounting pronouncement, early adoption, effect - ASU-Classification of deferred taxes $ in Thousands	Dec. 31, 2015USD ($)
New accounting pronouncement
Deferred tax liability, current	$ (33,242)
Deferred tax asset, non-current	$ (33,242)

Basis of Presentation and Sum45

Basis of Presentation and Summary of Significant Accounting Policies (Details) $ in Thousands	Sep. 12, 2014USD ($)	Sep. 18, 2013USD ($)	Dec. 31, 2016USD ($)item	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2012USD ($)	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			$ 169,046	1,365,000	$ 213,821
Percentage of the unproved property balance expected to be added to the amortization base during the year 2016			5.00%
Percentage of the unproved property balance expected to be added to the amortization base during the year 2017			8.00%
Percentage of the unproved property balance expected to be added to the amortization base during the year 2018			25.00%
Cost of unproved properties excluded from the amortization base
Leasehold acquisition costs			$ 44,053	16,587	93,505	$ 33,052
Exploration costs			342	343	479	2,680
Development costs			34,473	1,442	3,428	1,040
Total			78,868	18,372	97,412	$ 36,772
Cost of unproved properties excluded from the amortization base, cumulative
Total Leasehold acquisition cost			187,197
Total Exploration cost			3,844
Total development costs			40,383
Total cumulative costs of unproved properties			231,424
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			35,000	41,000
Debt issuance costs			7,840	7,529	9,002
Accumulated amortization			22,500	14,700
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
Second Amended And Restated Credit Agreement
Debt Issuance Costs
Amount of cost capitalized which is associated with issuance of debt and amendments to the agreement			$ 1,600
Catarina | Bridge Loan
Debt Issuance Costs
Debt issuance costs					$ 3,900
Form S-3 Registration Statement
Debt Issuance Costs
Amount of cost capitalized which is associated with issuance of debt and amendments to the agreement			$ 100
Senior Notes 6.125 Percent Due 2023
Debt Issuance Costs
Interest rate (as a percent)			6.125%					6.125%	6.125%
Debt issuance costs	$ 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 costs		$ 4,200

Basis of Presentation and Sum46

Basis of Presentation and Summary of Significant Accounting Policies (Concentrations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings per Share
Portion of loss allocated to participating securities	$ 0
Customer A
Sales to Major Customers
Concentration risk percentage	4.00%	7.00%	23.00%
Customer B
Sales to Major Customers
Concentration risk percentage	14.00%	14.00%	4.00%
Customer C
Sales to Major Customers
Concentration risk percentage	0.00%	4.00%	15.00%
Customer D
Sales to Major Customers
Concentration risk percentage	33.00%	38.00%	37.00%
Customer E
Sales to Major Customers
Concentration risk percentage	20.00%	0.00%	0.00%

Acquisitions and Divestitures47

Acquisitions and Divestitures (Details) - USD ($) $ in Thousands	Sep. 12, 2014	Jun. 30, 2014	Jun. 27, 2014	Aug. 31, 2013	Dec. 31, 2016	Dec. 31, 2014	May 12, 2014
Acquisitions
Proceeds from issuance of debt					$ 60,000	$ 100,000
Total purchase price allocated to assets purchased and liabilities assumed
Common stock issued in acquisition (in shares)				342,760
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
Catarina | Senior Notes 6.125 Percent Due 2023
Acquisitions
Proceeds from issuance of debt		$ 850,000
Interest rate (as a percent)		6.125%

Acquisitions and Divestitures48

Acquisitions and Divestitures (Divestitures) (Details)	Nov. 22, 2016USD ($)item	Jul. 05, 2016USD ($)	Oct. 14, 2015USD ($)aitemshares	Mar. 31, 2015USD ($)itemshares	Mar. 31, 2017USD ($)	Dec. 31, 2017item	Dec. 31, 2016USD ($)	Dec. 14, 2016USD ($)	Dec. 31, 2015USD ($)
Divestitures
Gain on disposition							$ 112,294,000
Investments							$ 39,656,000		$ 49,985,000
Production Asset Transaction
Divestitures
Percentage of working interest to be retained per wellbore	2.50%
Palmetto | Disposed of by sale, not discontinued operations
Divestitures
Consideration				$ 83,400,000
Consideration in cash				$ 83,000,000
Number of wellbores having partial interest | item				59
Percentage of working interest to be retained per wellbore				2.50%
Adjusted consideration in cash				$ 81,400,000
Western Catarina Midstream Divestiture | Disposed of by sale, not discontinued operations
Divestitures
Consideration			$ 345,800,000
Common units (in shares) | shares			105,263
Term of agreement			15 years
Area under agreement, gross (in acres) | a			35,000
Term of gas gathering agreement			5 years
Deferred gain			$ 74,100,000
Cotulla Assets, LLC | Carrizo LLC
Divestitures
Consideration								$ 153,500,000
Cotulla Assets, LLC | Carrizo LLC | Subsequent Events
Divestitures
Consideration in cash					$ 7,100,000
SPP | Production Asset Transaction
Divestitures
Consideration	$ 25,600,000
Number of wellbores having partial interest | item	23
Percentage of working interest initially conveyed per wellbore	17.92%
Percentage of working interest owned	47.50%
SPP | Carnero Gathering LLC Joint Venture
Divestitures
Consideration in cash		$ 37,000,000
Assumption of capital commitments in joint venture		$ 7,400,000
SPP | Palmetto | Disposed of by sale, not discontinued operations
Divestitures
Percentage of working interest initially conveyed per wellbore				18.25%
Forecast | SPP | Production Asset Transaction
Divestitures
Number of wellbores having partial interest | item						11
SPP | Palmetto | Disposed of by sale, not discontinued operations
Divestitures
Percentage of working interest owned				47.50%
Common units (in shares) | shares				1,052,632
Investments				$ 2,000,000
Crude oil | Western Catarina Midstream Divestiture | Disposed of by sale, not discontinued operations
Divestitures
Daily delivery commitment (in units) | item			10,200
Gathering and processing fees			$ 0.96
Natural gas | Western Catarina Midstream Divestiture | Disposed of by sale, not discontinued operations
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, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash and cash equivalents
Total cash and cash equivalents	$ 501,917	$ 435,048	$ 473,714	$ 153,531
Cash at banks
Cash and cash equivalents
Total cash and cash equivalents	58,269	35,600
Money market funds
Cash and cash equivalents
Total cash and cash equivalents	$ 443,648	$ 399,448

Long-Term Debt (Summary) (Detai

Long-Term Debt (Summary) (Details) - USD ($) $ in Thousands	Sep. 12, 2014	Sep. 18, 2013	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Feb. 27, 2015	Jul. 18, 2014	Jun. 27, 2014	May 12, 2014	Jun. 13, 2013
Long-Term Debt
Face value of debt			$ 1,750,000	$ 1,750,000
Unamortized debt issuance costs			(34,832)	(41,039)
Total long-term debt			1,712,767	1,705,927
Debt issuance costs			7,840	7,529	$ 9,002
Interest expense
Interest on Senior Notes			(116,938)	(116,938)	(78,479)
Interest expense and commitment fees on credit agreement			(1,561)	(1,229)	(1,564)
Amortization of debt issuance costs			(7,840)	(7,529)	(9,002)
Amortization of (discount) premium			(633)	(703)	(755)
Total interest expense			$ (126,973)	(126,399)	(89,800)
Senior Notes 7.75 Percent Due 2021
Long-Term Debt
Interest rate (as a percent)			7.75%							7.75%
Face value of debt		$ 200,000	$ 600,000	600,000			$ 600,000			$ 400,000
Unamortized discount on Additional 7.75% Notes		(7,000)	(4,030)	(4,933)
Debt issuance costs		4,200
Interest expense
Amortization of debt issuance costs		$ (4,200)
Amortization of (discount) premium			$ (904)	(904)	(905)
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	$ 300,000		$ 1,150,000	1,150,000				$ 850,000
Unamortized premium on Additional 6.125% Notes	2,300		1,629	1,899
Debt issuance costs	6,400
Interest expense
Amortization of debt issuance costs	$ (6,400)
Amortization of (discount) premium			$ 270	201	$ 150
Senior Unsecured Notes
Long-Term Debt
Face value of debt						$ 1,150,000
Scenario, Adjustment | ASU-Imputation of interest
Long-Term Debt
Total long-term debt				(41,039)
Debt issuance costs				(41,039)
Interest expense
Amortization of debt issuance costs				$ 41,039

Long-Term Debt (Detail) (Detail

Long-Term Debt (Detail) (Details) $ in Thousands	Sep. 12, 2014USD ($)	Jun. 27, 2014USD ($)	Sep. 18, 2013USD ($)	Jun. 13, 2013USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2013USD ($)	Sep. 30, 2013USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jul. 18, 2014USD ($)	Jun. 30, 2014USD ($)	May 12, 2014USD ($)	May 31, 2013USD ($)
Long-Term Debt
Face value of debt								$ 1,750,000	$ 1,750,000
Interest expense								126,973	126,399	$ 89,800
Amortization of debt issuance costs								7,840	7,529	9,002
Proceeds from issuance of debt								60,000		$ 100,000
Senior Notes 7.75 Percent Due 2021
Long-Term Debt
Face value of debt			$ 200,000	$ 400,000				$ 600,000	600,000		$ 600,000
Interest rate (as a percent)				7.75%				7.75%
Proceeds for issuance of notes, net of discount/premium and related offering expenses			$ 188,800	$ 388,000		$ 192,900
Percentage value of Additional Notes at which they are offered in private offering			96.50%
Amortization of debt issuance costs			$ 4,200
Proceeds from Interest Received							$ 4,100
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%
Senior Notes 6.125 Percent Due 2023
Long-Term Debt
Face value of debt	$ 300,000	$ 850,000						$ 1,150,000	1,150,000
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
Percentage value of Additional Notes at which they are offered in private offering	100.75%
Amortization of debt issuance costs	$ 6,400
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	$ 829,000
Accrued interest					$ 3,800
Previous First Lien Credit Agreement
Long-Term Debt
Maximum borrowing capacity														$ 500,000
Face value of debt													$ 100,000
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											$ 100,000
Second Amended And Restated Credit Agreement
Long-Term Debt
Maximum borrowing capacity												$ 1,500,000
Borrowing base								$ 350,000
Face value of debt								10,000
Aggregate elected commitment amount								$ 300,000
Percentage of increased net debt used to calculate reduction in borrowing base								25.00%
Permitted cash in excess of credit exposure, aggregate amount								$ 298,500
Permitted capital utilization towards formation and capitalization of subsidiaries								150,000
Permitted capital utilization by subsidiaries								150,000
Accelerated repayment clause, usage of unrestricted cash in excess of threshold amount								$ 35,000
Second Amended And Restated Credit Agreement | Minimum
Long-Term Debt
Percentage of value of asset sales and swaps terminations								10.00%
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
Second Amended And Restated Credit Agreement | Alternate base rate | Minimum
Long-Term Debt
Variable rate basis, spread percentage								1.00%
Second Amended And Restated Credit Agreement | Alternate base rate | Maximum
Long-Term Debt
Variable rate basis, spread percentage								2.00%
Second Amended And Restated Credit Agreement | Eurodollar rate | Minimum
Long-Term Debt
Variable rate basis, spread percentage								2.00%
Second Amended And Restated Credit Agreement | Eurodollar rate | Maximum
Long-Term Debt
Variable rate basis, spread percentage								3.00%
Letters of credit
Long-Term Debt
Maximum borrowing capacity												$ 80,000

Stockholders' Equity (Details)

Stockholders' Equity (Details) $ / shares in Units, $ in Thousands	Feb. 06, 2017USD ($)$ / sharesshares	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, 2016USD ($)item$ / sharesshares	Dec. 31, 2015$ / shares	Dec. 31, 2014USD ($)
Common stock, par value (in dollars per share) | $ / shares												$ 0.01	$ 0.01
Common shares issued, net of offering costs of $8,731 | $														$ 167,519
Payments for offering costs | $														$ 8,731
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
Dividends accrued or accumulated | $												$ 4,360
Common Stock
Number of shares issued (in shares)					5,000,000				11,040,000
Shares issued, price per share (in dollars per share) | $ / shares					$ 35.25				$ 23
Common shares issued, net of offering costs of $8,731 | $					$ 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 (in shares)											3,000,000
Shares issued, price per share (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				0
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 (in shares)										4,500,000
Shares issued, price per share (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										8,244,539
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				0
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%
Subsequent Events
Number of shares issued (in shares)	11,500,000
Shares issued, price per share (in dollars per share) | $ / shares	$ 12.50
Common shares issued, net of offering costs of $8,731 | $	$ 135,900
Underwriting discounts and estimated offering expenses | $	$ 7,800
Over-allotment option | Common Stock
Number of shares issued (in shares)									1,440,000
Over-allotment option | Subsequent Events
Number of shares issued (in shares)	1,500,000

Stockholders' Equity (EPS) (Det

Stockholders' Equity (EPS) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings (Loss) Per Share
Net loss	$ (256,958)	$ (1,454,627)	$ (21,791)
Preferred stock dividends	(15,948)	(16,008)	(33,590)
Net loss attributable to common stockholders	$ (272,906)	$ (1,470,635)	$ (55,381)
Weighted average number of unrestricted outstanding common shares used to calculate basic net loss per share	58,900,000	57,229,000	52,338,000
Denominator for diluted loss per common share	58,900,000	57,229,000	52,338,000
Net loss per common share - basic and diluted (in dollars per share)	$ (4.63)	$ (25.70)	$ (1.06)
Restricted stock
Earnings (Loss) Per Share
Anti-dilutive common stock	2,113,462	2,663,010	1,732,888
Non-vested common stock (in shares)	0	0	0
Common Stock
Earnings (Loss) Per Share
Anti-dilutive common stock	12,554,481	12,529,314	13,527,738

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)director$ / sharesshares	Dec. 31, 2015USD ($)item$ / sharesshares	Dec. 31, 2014USD ($)director$ / sharesshares
Stock-Based Compensation
Maximum number of shares of common stock	17,239,790
Common stock available for incentive awards, as a percentage of the issued and outstanding shares of common stock	15.00%
Total stock-based compensation expense | $	$ 37,090	$ 14,831	$ 12,843
Additional disclosure related to compensation cost
Closing price of common stock (in dollars per share) | $ / shares	$ 9.03
Restricted stock
Additional disclosure related to compensation cost
Unrecognized compensation costs related to non-vested restricted shares outstanding | $	$ 22,200
Expected average period for recognition of unrecognized compensation costs related to non-vested shares	1 year 10 months 6 days
Number of Non-Vested Shares
Shares available for future issuance to participants	6,700,000
Restricted stock | Employees and consultants of SOG, with whom the company has a services agreement
Number of Non-Vested Shares
Granted (in shares)	4,400,000	3,400,000	2,000,000
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
Number of Non-Vested Shares
Granted (in shares)			700,000
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	3,300,000	1,300,000
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	5 years
Number of Non-Vested Shares
Granted (in shares)	1,100,000	100,000
Restricted stock | Directors
Stock-Based Compensation
Number of directors to whom awards are issued	5	5	4
Vesting period	1 year	1 year	1 year
Granted (in dollars per share) | $ / shares	$ 8	$ 12.65	$ 33.05
Total stock-based compensation expense | $	$ 1,000	$ 917	$ 802
Additional disclosure related to compensation cost
Closing price of common stock (in dollars per share) | $ / shares	$ 5.81	$ 9.80	$ 14.90
Number of Non-Vested Shares
Granted (in shares)	156,126	95,237	35,769
Weighted Average Fair Value
Granted (in dollars per share) | $ / shares	$ 8	$ 12.65	$ 33.05
Restricted stock | Non-employees
Stock-Based Compensation
Total stock-based compensation expense | $	$ 18,145	$ 13,914	$ 12,041
PARS
Additional disclosure related to compensation cost
Unrecognized compensation costs related to non-vested restricted shares outstanding | $	$ 3,900
Expected average period for recognition of unrecognized compensation costs related to non-vested shares	3 years 5 months 1 day
PARS | Employees of SOG, with whom the company has a services agreement | Cliff vesting after five years
Stock-Based Compensation
Vesting period	5 years
PARS | Employees of SOG, with whom the company has a services agreement | Five-year vesting period
Number of Non-Vested Shares
Granted (in shares)	1,100,000
PARS, PAPS, and Phantom Stock award shares
Stock-Based Compensation
Total stock-based compensation expense | $	$ 17,945
Additional disclosure related to compensation cost
Unrecognized compensation costs related to non-vested restricted shares outstanding | $	$ 23,200
Expected average period for recognition of unrecognized compensation costs related to non-vested shares	2 years 6 months
PARS, PAPS, and Phantom Stock award shares | Vesting in equal annual increments over three year period
Stock-Based Compensation
Vesting period	3 years
PARS, PAPS, and Phantom Stock award shares | Cliff vesting after five years
Stock-Based Compensation
Vesting period	5 years
Restricted common shares and PARS
Stock-Based Compensation
Granted (in dollars per share) | $ / shares	$ 4.59
Number of Non-Vested Shares
Non-vested common stock, beginning of period (in shares)	4,425,767
Granted (in shares)	4,558,640
Vested (in shares)	(1,991,025)
Forfeited (in shares)	(466,407)
Non-vested common stock, end of the period (in shares)	6,526,975	4,425,767
Weighted Average Fair Value
Non-vested common stock at the beginning of the period (in dollars per share) | $ / shares	$ 12.21
Granted (in dollars per share) | $ / shares	4.59
Vested (in dollars per share) | $ / shares	5.04
Forfeited (in dollars per share) | $ / shares	10.85
Non-vested common stock at the end of the period (in dollars per share) | $ / shares	$ 9.18	$ 12.21
Aggregate Intrinsic Value
Non-vested common stock, beginning of period (in dollars) | $	$ 54,053
Granted (in dollars) | $	20,930
Vested (in dollars) | $	(10,036)
Forfeited (in dollars) | $	(5,061)
Non-vested common stock, end of period (in dollars) | $	$ 59,886	$ 54,053
Phantom Stock shares and PAPS
Stock-Based Compensation
Granted (in dollars per share) | $ / shares	$ 4.87
Number of Non-Vested Shares
Non-vested common stock, beginning of period (in shares)
Granted (in shares)	3,990,413
Forfeited (in shares)	(78,000)
Non-vested common stock, end of the period (in shares)	3,912,413
Weighted Average Fair Value
Non-vested common stock at the beginning of the period (in dollars per share) | $ / shares
Granted (in dollars per share) | $ / shares	4.87
Forfeited (in dollars per share) | $ / shares	6.62
Non-vested common stock at the end of the period (in dollars per share) | $ / shares	$ 4.84
Aggregate Intrinsic Value
Non-vested common stock, beginning of period (in dollars) | $
Granted (in dollars) | $	19,451
Forfeited (in dollars) | $	(516)
Non-vested common stock, end of period (in dollars) | $	$ 18,935
Phantom Stock shares and PAPS | Employees of SOG, with whom the company has a services agreement
Number of Non-Vested Shares
Granted (in shares)	4,000,000
Phantom Stock shares and PAPS | Employees of SOG, with whom the company has a services agreement | Cliff vesting after five years
Stock-Based Compensation
Vesting period	5 years
Number of Non-Vested Shares
Granted (in shares)	1,200,000
Phantom Stock shares and PAPS | Employees of SOG, with whom the company has a services agreement | Three-year vesting period
Stock-Based Compensation
Vesting period	3 years
Number of Non-Vested Shares
Granted (in shares)	2,800,000

Income Taxes - (Details)

Income Taxes - (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Components of income tax provision
Current expense as a result of current operations	$ 1,825	$ 158
Deferred benefit as a result of current operations	(86,606)	(506,943)	$ (11,429)
Increase in valuation allowance	86,606	514,385
Net income tax expense (benefit)	$ 1,825	7,600	(11,429)
Reconciliation of the statutory federal income tax with the income tax provision
Effective tax rate (as a percent)	(0.70%)
Federal statutory corporate income tax rate (as a percent)	35.00%
Income tax expense (benefit) at the federal statutory rate	$ (89,297)	(506,460)	(11,627)
Officers' compensation limitation	3,115	1,328
State Taxes (net of federal benefit)	(232)	(5,463)
Non-deductible general and administrative expenses	743	309	231
Percentage depletion carry forward	(144)		(107)
Other	39
Differences between actual income taxes and amounts estimated in prior years	995	3,501	74
Income tax expense (benefit)	(84,781)	(506,785)	(11,429)
Valuation allowance	86,606	514,385
Net income tax expense (benefit)	1,825	7,600	$ (11,429)
Deferred tax assets (liabilities):
Derivative assets	12,516
Derivative (obligations)		(54,638)
Depreciable, depletable property, plant and equipment	144,348	288,736
Share based compensation	12,408	2,897
Revenue Recognition	7,077	8,417
Other	1,085
Other		(535)
Federal net operating loss carryforward	420,302	268,068
State net operating loss carryforward	3,256	1,440
Deferred tax assets	600,992	514,385
Valuation allowance	(600,992)	$ (514,385)
Current:
Derivative assets	12,516
Noncurrent:
Other	1,085
Net operating loss carryforwards	$ 1,200,900

Related Party Transactions (Det

Related Party Transactions (Details) $ in Thousands	Nov. 22, 2016USD ($)	Aug. 31, 2013USD ($)aitemshares	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jul. 05, 2016
Related Party Transactions
Accounts receivable - related entities			$ 6,401	$ 3,697
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			40,901	30,430	$ 33,610
Third-party expenses			5,001	5,427	4,515
Total included in general and administrative expenses			45,902	35,857	$ 38,125
SR
Related Party Transactions
Accounts receivable - related entities			700	$ 700
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			$ 9,000
Carnero Gathering LLC Joint Venture | SPP
Related Party Transactions
Ownership of investment (as a percent)	50.00%					50.00%
Consideration in cash	$ 55,500
Assumption of capital commitments in joint venture	$ 24,500

Derivative Instruments (Details

Derivative Instruments (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)MMBTU$ / MMBTU$ / bblbbl	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Derivative contract covering anticipated future production
Deferred payment of premiums	$ 31,778
Not designated as hedges | Commodity derivative contract
Reconciliation of the changes in fair value of the commodity derivatives
Beginning fair value of commodity derivatives	178,283	$ 123,316	$ (3,397)
Ending fair value of commodity derivatives	(35,014)	178,283	123,316
Not designated as hedges | Commodity derivative contract | Crude oil
Reconciliation of the changes in fair value of the commodity derivatives
Net gains (losses) on derivatives	(47,389)	170,592	115,602
Net settlements on derivative contracts	(135,491)	(123,946)	(4,503)
Net premiums on derivative contracts	24,547		(4,892)
Not designated as hedges | Commodity derivative contract | Natural gas
Reconciliation of the changes in fair value of the commodity derivatives
Net gains (losses) on derivatives	(30,307)	26,843	21,603
Net settlements on derivative contracts	$ (24,657)	$ (18,522)	$ (1,097)
Not designated as hedges | Swaps | January 1 - December 31, 2017 | Crude oil
Derivative contract covering anticipated future production
Notional amount (in barrels) | bbl	1,825,000
Average swap price per unit | $ / bbl	51.70
Not designated as hedges | Swaps | January 1 - December 31, 2017 | Natural gas
Derivative contract covering anticipated future production
Notional amount (in MMBtu) | MMBTU	40,805,000
Average swap price per unit | $ / MMBTU	3.07
Not designated as hedges | Swaps | 2018 | Natural gas
Derivative contract covering anticipated future production
Notional amount (in MMBtu) | MMBTU	29,532,500
Average swap price per unit | $ / MMBTU	3.02
Not designated as hedges | Swaps | 2019 | Natural gas
Derivative contract covering anticipated future production
Notional amount (in MMBtu) | MMBTU	7,300,000
Average swap price per unit | $ / MMBTU	3.02
Not designated as hedges | Collars | January 1 - December 31, 2017 | Crude oil
Derivative contract covering anticipated future production
Notional amount (in barrels) | bbl	730,000
Not designated as hedges | Collars | Puts | Long | January 1 - December 31, 2017 | Crude oil
Derivative contract covering anticipated future production
Average price per unit | $ / bbl	45
Not designated as hedges | Collars | Call | Short | January 1 - December 31, 2017 | Crude oil
Derivative contract covering anticipated future production
Average price per unit | $ / bbl	62

Derivative Instruments (Balance

Derivative Instruments (BalanceSheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	$ 2,270	$ 178,339
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(2,270)	(56)
Net Amounts Presented in the Condensed Consolidated Balance Sheets		178,283
Offsetting Derivative Liabilities:
Gross Amount of Recognized Liabilities	37,284	56
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(2,270)	(56)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	35,014
Current asset
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	844	172,518
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(844)	(24)
Net Amounts Presented in the Condensed Consolidated Balance Sheets		172,494
Long-term asset
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	1,426	5,821
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(1,426)	(32)
Net Amounts Presented in the Condensed Consolidated Balance Sheets		5,789
Current liability
Offsetting Derivative Liabilities:
Gross Amount of Recognized Liabilities	32,622	24
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(844)	(24)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	31,778
Long-term liability
Offsetting Derivative Liabilities:
Gross Amount of Recognized Liabilities	4,662	32
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(1,426)	$ (32)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	$ 3,236

Fair Value of Financial Instr59

Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Unobservable Inputs (Level 3)
Fair Value of Financial Instruments
Derivative instruments	$ 0	$ 0
Recurring basis
Fair Value of Financial Instruments
Investment in SPP	26,818	0
Total	435,452	577,731
Recurring basis | Money market funds
Fair Value of Financial Instruments
Cash and cash equivalents	443,648	399,448
Recurring basis | Active Market for Identical Assets (Level 1)
Fair Value of Financial Instruments
Investment in SPP	26,818
Total	470,466	399,448
Recurring basis | Active Market for Identical Assets (Level 1) | Money market funds
Fair Value of Financial Instruments
Cash and cash equivalents	443,648	399,448
Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Total		178,283
Total	(35,014)
Swaps | Crude oil | Recurring basis
Fair Value of Financial Instruments
Derivative instruments		72,887
Derivative instruments	(8,291)
Swaps | Crude oil | Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments		72,887
Derivative instruments	(8,291)
Swaps | Natural gas | Recurring basis
Fair Value of Financial Instruments
Derivative instruments		28,813
Derivative instruments	(26,151)
Swaps | Natural gas | Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments		28,813
Derivative instruments	(26,151)
Collars | Crude oil | Recurring basis
Fair Value of Financial Instruments
Derivative instruments	(572)
Collars | Crude oil | Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments	$ (572)
Puts | Crude oil | Recurring basis
Fair Value of Financial Instruments
Derivative instruments		76,583
Puts | Crude oil | Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments		$ 76,583

Fair Value of Financial Instr60

Fair Value of Financial Instruments (Other) (Details) - USD ($) $ in Thousands	Nov. 20, 2015	Aug. 28, 2014	May 29, 2014	Feb. 13, 2014	Feb. 12, 2014	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Jun. 27, 2014	May 12, 2014	Jun. 13, 2013	Mar. 26, 2013	Sep. 17, 2012
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)
Total gains (losses) included in earnings							418	81,404
Net settlements on derivative contracts							(14,277)	(5,362)
Derivative contracts transferred to Level 2							(61,664)
Ending balance								75,523
Gains (losses) included in earnings related to derivatives still held as of December 31, 2016, 2015, and 2014							(940)	$ 76,760
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 | Senior Notes 7.75 Percent Due 2021 | Estimated Fair Value
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Debt fair value						$ 612,000
Recurring basis | Senior Notes 6.125 Percent Due 2023 | Estimated Fair Value
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Debt fair value						$ 1,098,300
Preferred Class A
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		47,500	166,025	947,490	947,490	0
Conversion ratio (in shares)				2.325	2.325								2.3250
Shares of common stock issued upon conversion of preferred stock		119,320	418,715	2,425,574	2,425,574
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	0
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, 2016	Dec. 31, 2015
Changes in the asset retirement obligation
Abandonment liability, beginning of period	$ 25,907	$ 25,694
Liabilities incurred during period	1,492	6,021
Acquisitions	219
Divestitures	(4,433)	(379)
Revisions	(172)	(7,623)
Accretion expense	2,074	2,194
Abandonment liability, end of period	$ 25,087	$ 25,907

Accrued Liabilities (Details)

Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Accrued Liabilities
Capital expenditures	$ 35,154	$ 51,983
General and administrative costs	14,738	5,214
Production taxes	2,396	2,532
Ad valorem taxes	2,756	886
Lease operating expenses	23,942	27,077
Interest payable	34,266	34,265
Preferred stock dividends and other	4,360
Total accrued liabilities	$ 117,612	$ 121,957

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	Nov. 22, 2016USD ($)	Dec. 16, 2013item	Dec. 31, 2016USD ($)aitem	Oct. 06, 2016USD ($)	Jul. 05, 2016USD ($)
Operating leases
Lease payment obligation			$ 216.4
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
Corporate office Lease
Operating leases
Lease payment obligation			$ 45.7
Land Lease
Operating leases
Lease payment obligation			$ 6.2
Advanced written notice required to terminate lease obligation			180 days
Lease termination penalty			$ 1
Acreage Lease
Operating leases
Lease payment obligation			$ 5.9
Term of lease			10 years
Permanent improvements
Operating leases
Lease payment obligation			$ 4
Western Catarina Midstream Divestiture
Operating leases
Lease payment obligation			$ 158.6
Carnero Gathering LLC Joint Venture
Investment
Equity method investment cost				$ 48	$ 26
Carnero Gathering LLC Joint Venture | SPP
Investment
Consideration in cash	$ 55.5
Ownership of investment (as a percent)	50.00%				50.00%

Subsidiary Guarantors (Details)

Subsidiary Guarantors (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	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 Thousands	Nov. 22, 2016USD ($)shares	Oct. 06, 2016USD ($)	Jul. 05, 2016USD ($)	Oct. 02, 2015USD ($)Mcf	Dec. 31, 2016USD ($)
Investments in marketable securities
Investment gains (losses) recorded					$ 1,818
Equity method gains (losses)					3,466
SOII Facility
Investments in marketable securities
Gas processing plant capacity per day (in MMcf) | Mcf				125,000
Amount committed				$ 12,500
Ownership of investment (as a percent)				10.00%
Equity method investment cost					12,500
Equity method gains (losses)					$ 1,200
Carnero Gathering LLC Joint Venture
Investments in marketable securities
Equity method investment cost		$ 48,000	$ 26,000
Equity method gains (losses)		$ (100)	2,300
Deferred gain	$ 7,500		$ 8,700
Targa | SOII Facility
Investments in marketable securities
Ownership of investment (as a percent)				90.00%
Targa | Carnero Gathering LLC Joint Venture
Investments in marketable securities
Ownership of investment (as a percent)	50.00%		50.00%
SPP | Carnero Gathering LLC Joint Venture
Investments in marketable securities
Ownership of investment (as a percent)	50.00%		50.00%
Consideration in cash	$ 55,500
Assumption of capital commitments in joint venture	$ 24,500
Carnero Gathering LLC Joint Venture | SPP
Investments in marketable securities
Consideration in cash			$ 37,000
Assumption of capital commitments in joint venture			$ 7,400
Common Stock | SPP
Investments in marketable securities
Investments (in units) | shares	2,272,727
Investments	$ 25,000
Investment, ownership (as a percent)					16.90%
Investment gains (losses) recorded					$ 1,800

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Nov. 22, 2016	Oct. 06, 2016	Jul. 05, 2016	Dec. 31, 2015	Oct. 02, 2015
SOII Facility
Variable Interest Entity [Line Items]
Ownership of investment (as a percent)						10.00%
Amount committed						$ 12,500
Equity method investment cost	$ 12,500
Debt	0
Carnero Gathering LLC Joint Venture
Variable Interest Entity [Line Items]
Equity method investment cost			$ 48,000	$ 26,000
Targa | SOII Facility
Variable Interest Entity [Line Items]
Ownership of investment (as a percent)						90.00%
Targa | Carnero Gathering LLC Joint Venture
Variable Interest Entity [Line Items]
Ownership of investment (as a percent)		50.00%		50.00%
SPP | Carnero Gathering LLC Joint Venture
Variable Interest Entity [Line Items]
Ownership of investment (as a percent)		50.00%		50.00%
Common Stock | SPP
Variable Interest Entity [Line Items]
Investments		$ 25,000
Recurring basis
Variable Interest Entity [Line Items]
Investment in SPP measured at fair value	$ 26,818				$ 0

Variable Interest Entities (Car

Variable Interest Entities (Carrying Amounts) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Variable Interest Entities
Capital investments	$ 37,527	$ 49,985
Earnings in equity investments	311
Gain (loss) from change in fair value of investment in SPP	1,818
Equity in equity investments	39,656	49,985
Guarantees of capital investments		65,526
Maximum exposure to loss	$ 39,656	$ 115,511

Condensed Consolidating Finan68

Condensed Consolidating Financial Information (Details)	Dec. 31, 2016
Condensed Consolidating Financial Information
Ownership interest in Subsidiaries (as a percent)	100.00%

Condensed Consolidating Finan69

Condensed Consolidating Financial Information (BalanceSheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Assets
Total current assets	$ 562,805	$ 666,618
Total oil and natural gas properties, net	658,588	756,103
Other assets	64,887	78,583
Total assets	1,286,280	1,501,304
Liabilities and Shareholders' Equity
Current liabilities	176,997	167,506
Long-term liabilities	1,805,423	1,789,967
Total shareholders' equity (deficit)	(696,140)	(456,169)	$ 999,587	$ 857,309
Total liabilities and stockholders’ (equity) deficit	1,286,280	1,501,304
Eliminations
Assets
Total current assets	(181,322)	(42,369)
Investment in subsidiaries	(734,704)	(700,053)
Total assets	(916,026)	(742,422)
Liabilities and Shareholders' Equity
Current liabilities	(181,321)	(42,369)
Long-term liabilities	(1)
Total shareholders' equity (deficit)	(734,704)	(700,053)
Total liabilities and stockholders’ (equity) deficit	(916,026)	(742,422)
Parent Company
Assets
Total current assets	428,384	671,278
Investment in subsidiaries	734,704	700,053
Other assets	14,376	14,481
Total assets	1,177,464	1,385,812
Liabilities and Shareholders' Equity
Current liabilities	109,539	78,840
Long-term liabilities	1,764,064	1,764,060
Total shareholders' equity (deficit)	(696,139)	(457,088)
Total liabilities and stockholders’ (equity) deficit	1,177,464	1,385,812
Combined Guarantor Subsidiaries
Assets
Total current assets	157,154	37,005
Total oil and natural gas properties, net	658,588	756,103
Other assets	15,221	17,737
Total assets	830,963	810,845
Liabilities and Shareholders' Equity
Current liabilities	78,344	88,666
Long-term liabilities	25,087	25,907
Total shareholders' equity (deficit)	727,532	696,272
Total liabilities and stockholders’ (equity) deficit	830,963	810,845
Combined Non-Guarantor Subsidiaries
Assets
Total current assets	158,589	704
Other assets	35,290	46,365
Total assets	193,879	47,069
Liabilities and Shareholders' Equity
Current liabilities	170,435	42,369
Long-term liabilities	16,273
Total shareholders' equity (deficit)	7,171	4,700
Total liabilities and stockholders’ (equity) deficit	$ 193,879	$ 47,069

Condensed Consolidating Finan70

Condensed Consolidating Financial Information (IncomeStatement) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Condensed Income Statements, Captions [Line Items]
Total revenues	$ 431,326	$ 475,779	$ 666,064
Total operating costs and expenses	623,087	1,967,130	746,978
Other income (expense)	(63,372)	44,324	47,694
Loss before income taxes	(255,133)	(1,447,027)	(33,220)
Income tax expense (benefit)	1,825	7,600	(11,429)
Net loss	(256,958)	(1,454,627)	(21,791)
Eliminations
Condensed Income Statements, Captions [Line Items]
Equity in income (loss) of subsidiaries	(33,730)	1,416,657	16,443
Net loss	(33,730)	1,416,657	16,443
Parent Company
Condensed Income Statements, Captions [Line Items]
Total operating costs and expenses	111,155	75,096	64,454
Other income (expense)	(177,710)	44,726	47,678
Loss before income taxes	(288,865)	(30,370)	(16,776)
Income tax expense (benefit)	1,825	7,600	(11,429)
Equity in income (loss) of subsidiaries	33,730	(1,416,657)	(16,443)
Net loss	(256,960)	(1,454,627)	(21,790)
Combined Guarantor Subsidiaries
Condensed Income Statements, Captions [Line Items]
Total revenues	431,326	475,779	666,064
Total operating costs and expenses	509,985	1,890,342	681,876
Other income (expense)	109,920	(402)	16
Loss before income taxes	31,261	(1,414,965)	(15,796)
Net loss	31,261	(1,414,965)	(15,796)
Combined Non-Guarantor Subsidiaries
Condensed Income Statements, Captions [Line Items]
Total operating costs and expenses	1,947	1,692	648
Other income (expense)	4,418
Loss before income taxes	2,471	(1,692)	(648)
Net loss	$ 2,471	$ (1,692)	$ (648)

Condensed Consolidating Finan71

Condensed Consolidating Financial Information (CashFlows) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	$ 181,251	$ 272,025	$ 415,335
Net cash provided by (used in) investing activities	(108,637)	(294,331)	(1,361,264)
Net cash provided by (used in) financing activities	(5,745)	(16,360)	1,266,112
Increase (decrease) in cash and cash equivalents	66,869	(38,666)	320,183
Cash and cash equivalents, beginning of period	435,048	473,714	153,531
Cash and cash equivalents, end of period	501,917	435,048	473,714
Eliminations
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) investing activities	16,208	(26,489)	838,526
Net cash provided by (used in) financing activities	(16,208)	26,489	(838,526)
Parent Company
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	(38,646)	(44,090)	(100,047)
Net cash provided by (used in) investing activities	(46,602)	21,670	(845,882)
Net cash provided by (used in) financing activities	(5,745)	(16,360)	1,266,112
Increase (decrease) in cash and cash equivalents	(90,993)	(38,780)	320,183
Cash and cash equivalents, beginning of period	434,934	473,714	153,531
Cash and cash equivalents, end of period	343,941	434,934	473,714
Combined Guarantor Subsidiaries
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	219,266	317,499	516,474
Net cash provided by (used in) investing activities	(133,814)	(249,185)	(1,347,416)
Net cash provided by (used in) financing activities	(85,452)	(68,314)	830,942
Combined Non-Guarantor Subsidiaries
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	631	(1,384)	(1,092)
Net cash provided by (used in) investing activities	55,571	(40,327)	(6,492)
Net cash provided by (used in) financing activities	101,660	41,825	$ 7,584
Increase (decrease) in cash and cash equivalents	157,862	114
Cash and cash equivalents, beginning of period	114
Cash and cash equivalents, end of period	$ 157,976	$ 114

Subsequent Events (Details)

Subsequent Events (Details) $ / shares in Units, $ in Thousands	Feb. 06, 2017USD ($)$ / sharesshares	Jan. 12, 2017USD ($)aMMBoesubsidiary	Dec. 31, 2016aBoeshares	Dec. 31, 2014USD ($)	Dec. 31, 2015shares
Subsequent Events
Common shares issued, net of offering costs of $8,731 | $				$ 167,519
Additional shares available for issuance | shares			150,000,000		150,000,000
Subsequent Events
Subsequent Events
Common shares issued, net of offering costs of $8,731 (in shares) | shares	11,500,000
Shares issued, price per share (in dollars per share) | $ / shares	$ 12.50
Common shares issued, net of offering costs of $8,731 | $	$ 135,900
Underwriting discounts and estimated offering expenses | $	$ 7,800
Underwriters' option to purchase additional shares (in days)	30 days
Subsequent Events | Public offering
Subsequent Events
Common shares issued, net of offering costs of $8,731 (in shares) | shares	10,000,000
Subsequent Events | Over-allotment option
Subsequent Events
Common shares issued, net of offering costs of $8,731 (in shares) | shares	1,500,000
Additional shares available for issuance | shares	1,500,000
Subsequent Events | Net of underwriting discounts
Subsequent Events
Shares issued, price per share (in dollars per share) | $ / shares	$ 11.7902
SN EF UnSub, LP (“SN UnSub”) and SN EF Maverick, LLC (“SN Maverick”) | Subsequent Events
Subsequent Events
Number of subsidiaries | subsidiary		2
The "Commanche Assets"
Subsequent Events
Gross acres			7,000
Net acres			4,000
The "Commanche Assets" | Subsequent Events
Subsequent Events
Gross acres		318,000
Net acres		155,000
The "Commanche Assets" | Blackstone | Subsequent Events
Subsequent Events
Ownership interest acquired (as a percentage)		49.00%
Purchase price (as a percentage)		50.00%
The "Commanche Assets" | Blackstone | Subsequent Events | Proved developed producing reserves
Subsequent Events
Proved reserves (as a percentage)		50.00%
The "Commanche Assets" | SN EF UnSub, LP (“SN UnSub”) and SN EF Maverick, LLC (“SN Maverick”) | Liquids
Subsequent Events
Proved reserves production (boe/d energy) | Boe			67,000
The "Commanche Assets" | SN EF UnSub, LP (“SN UnSub”) and SN EF Maverick, LLC (“SN Maverick”) | Subsequent Events
Subsequent Events
Ownership interest acquired (as a percentage)		49.00%
Proved reserves (energy) | MMBoe		300
Proved reserves (as a percentage)		75.00%
The "Commanche Assets" | SN EF UnSub, LP (“SN UnSub”) and SN EF Maverick, LLC (“SN Maverick”) | Subsequent Events | Liquids
Subsequent Events
Proved reserves (as a percentage)		70.00%
The "Commanche Assets" | SN EF UnSub, LP (“SN UnSub”) and SN EF Maverick, LLC (“SN Maverick”) | Anadarko E&P Onshore LLC and Kerr-McGee Oil and Gas Onshore LP (together, “Anadarko”) | Subsequent Events
Subsequent Events
Cash consideration | $		$ 2,275,000
The "Commanche Assets" | SN EF UnSub, LP (“SN UnSub”) | Subsequent Events
Subsequent Events
Cash consideration | $		$ 100,000
Ownership interest acquired (as a percentage)		37.00%
The "Commanche Assets" | SN EF UnSub, LP (“SN UnSub”) | Subsequent Events | Proved developed producing reserves
Subsequent Events
Proved reserves (as a percentage)		50.00%
The "Commanche Assets" | SN EF UnSub, LP (“SN UnSub”) | Subsequent Events | Proved developed non-producing reserves
Subsequent Events
Proved reserves (as a percentage)		20.00%
The "Commanche Assets" | SN EF UnSub, LP (“SN UnSub”) | Subsequent Events | Proved undeveloped reserves
Subsequent Events
Proved reserves (as a percentage)		20.00%
The "Commanche Assets" | SN EF Maverick, LLC (“SN Maverick”) | Subsequent Events
Subsequent Events
Ownership interest acquired (as a percentage)		13.00%
The "Commanche Assets" | SN EF Maverick, LLC (“SN Maverick”) | Subsequent Events | Proved developed producing reserves
Subsequent Events
Proved reserves (as a percentage)		0.00%
The "Commanche Assets" | SN EF Maverick, LLC (“SN Maverick”) | Subsequent Events | Proved developed non-producing reserves
Subsequent Events
Proved reserves (as a percentage)		30.00%
The "Commanche Assets" | SN EF Maverick, LLC (“SN Maverick”) | Subsequent Events | Proved undeveloped reserves
Subsequent Events
Proved reserves (as a percentage)		30.00%
Eagle Ford Shale | The "Commanche Assets" | Subsequent Events
Subsequent Events
Gross acres		252,000
Net acres		122,000
Pearsall Shale | The "Commanche Assets" | Subsequent Events
Subsequent Events
Gross acres		66,000
Net acres		33,000