Sanchez Energy (SNECQ) 10-K 1 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 23, 2018	Jun. 30, 2017
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, 2017
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			$ 435,460,057
Entity Common Stock, Shares Outstanding		84,839,847
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands		Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents		$ 184,434	$ 501,917	[1],[2]
Oil and natural gas receivables		101,396	41,077	[1]
Joint interest billings receivables		22,569	476	[1]
Accounts receivable - related entities		4,491	6,401	[1]
Fair value of derivative instruments		16,430
Other current assets		21,478	12,934	[1]
Total current assets		350,798	562,805	[1]
Oil and natural gas properties, on the basis of successful efforts accounting:
Proved oil and natural gas properties		3,130,407	1,849,732	[1]
Unproved oil and natural gas properties		398,605	225,023	[1]
Total oil and natural gas properties		3,529,012	2,074,755	[1]
Less: Accumulated depreciation, depletion, amortization and impairment		(1,501,553)	(1,370,236)	[1]
Total oil and natural gas properties, net		2,027,459	704,519	[1]
Other assets:
Fair value of derivative instruments		1,428
Investments (Investment in SNMP measured at fair value of $25.2 million and $26.8 million as of December 31, 2017 and 2016, respectively)		38,462	39,656	[1]
Other assets		52,488	25,231	[1]
Total assets		2,470,635	1,332,211	[1]
Current liabilities:
Accounts payable		14,994	1,076	[1]
Other payables		81,970	2,251	[1]
Accrued liabilities:
Capital expenditures		85,340	35,154	[1]
Other		84,794	82,458	[1]
Deferred premium liability	[1]		2,079
Fair value of derivative instruments		56,190	31,778	[1]
Short term debt		23,996
Other current liabilities		115,244	31,108	[1]
Total current liabilities		462,528	185,904	[1]
Long term debt, net of premium, discount and debt issuance costs		1,930,683	1,712,767	[1]
Asset retirement obligations		36,098	25,087	[1]
Fair value of derivative instruments		17,474	3,236	[1]
Other liabilities		65,480	89,199	[1]
Total liabilities		2,512,263	2,016,193	[1]
Commitments and contingencies (Note 15)				[1]
Mezzanine equity:
Preferred units ($1,000 liquidation preference, 500,000 units authorized; 500,000 and zero units issued and outstanding as of December 31, 2017 and December 31, 2016, respectively)		427,512		[1]
Stockholders' equity:
Preferred stock ($0.01 par value, 15,000,000 shares authorized; 1,838,985 shares issued and outstanding as of December 31, 2017 and 2016 of 4.875% Convertible Perpetual Preferred Stock, Series A; 3,527,830 shares issued and outstanding as of December 31, 2017 and 2016 of 6.500% Convertible Perpetual Preferred Stock, Series B, respectively)		53	53	[1]
Common stock ($0.01 par value, 150,000,000 shares authorized; 83,984,827 and 66,622,624 shares issued and outstanding as of December 31, 2017 and 2016, respectively)		845	670	[1]
Additional paid-in capital		1,362,118	1,112,397	[1]
Accumulated deficit		(1,832,156)	(1,797,102)	[1]
Total stockholders' equity (deficit)		(469,140)	(683,982)	[1],[3]
Total liabilities and stockholders' equity (deficit)		$ 2,470,635	$ 1,332,211	[1]
[1]	* Financial information for 2016 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.
[2]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.
[3]	Financial information for 2016, 2015, and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Liquidation preference	$ 1,000	$ 1,000
Preferred units, shares authorized	500,000	500,000
Preferred units, shares issued	500,000	0
Preferred units, shares outstanding	500,000	0
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	83,984,827	66,622,624
Common stock, shares outstanding	83,984,827	66,622,624
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	3,527,830
Preferred stock, shares outstanding	3,527,830	3,527,830
Dividend rate (as a percent)	6.50%	6.50%
Recurring basis
Investment in SNMP measured at fair value	$ 25,200	$ 26,800

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	[1]	Dec. 31, 2015	[1]
REVENUES:
Oil sales	$ 400,045	$ 241,766		$ 307,971
Natural gas liquid sales	171,139	81,744		69,011
Natural gas sales	169,147	107,816		98,797
Total revenues	740,331	431,326		475,779
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses	244,461	155,660		154,672
Production and ad valorem taxes	36,615	19,633		26,870
Exploration expenses	5,755	403		1,982
Depreciation, depletion, amortization and accretion	177,078	147,485		264,379
Impairment of oil and natural gas properties	39,574	47,381		723,971
General and administrative (inclusive of non-cash stock-based compensation expense of $22,909, $24,961, and $14,831, for 2017, 2016, and 2015, respectively)	144,401	110,081		74,160
Total operating costs and expenses	647,884	480,643		1,246,034
Operating income (loss)	92,447	(49,317)		(770,255)
Other income (expense):
Interest income	836	856		442
Other income (expense)	11,102	134		(2,605)
Gain on sale of oil and natural gas properties	81,955	85,322
Interest expense	(140,163)	(126,973)		(126,399)
Earnings from equity investments	779	3,466
Net gains (losses) on commodity derivatives	(6,100)	(53,149)		172,886
Total other income (expense)	(51,591)	(90,344)		44,324
Loss before income taxes	40,856	(139,661)		(725,931)
Income tax benefit (expense)	2,336	(1,825)		(158)
Net income (loss)	43,192	(141,486)		(726,089)
Less:
Preferred stock dividends	(15,948)	(15,948)		(16,008)
Preferred unit dividends and distributions	(44,259)
Preferred unit amortization	(18,039)
Net loss attributable to common stockholders	$ (35,054)	$ (157,434)		$ (742,097)
Net loss per common share - basic and diluted (in dollars per share)	$ (0.46)	$ (2.67)		$ (12.97)
Weighted average number of shares used to calculate net loss attributable to common stockholders - basic and diluted (in shares)	75,608	58,900		57,229
[1]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Consolidated Statements of Ope5

Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
General and administrative, stock-based compensation expense (in dollars)	$ 40,298	$ 37,090	[1]	$ 14,830	[1]
General and Administrative
General and administrative, stock-based compensation expense (in dollars)	$ 22,909	$ 24,961		$ 14,831
[1]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) shares in Thousands, $ in Thousands		Preferred Class A	Preferred Class B	Common Stock	Additional Paid-in Capital	Accumulated Deficit	Total
Increase (Decrease) in Stockholders' Equity (Deficit)
Effect of change in accounting principle | Accounting principle						$ (831,852)	$ (831,852)
Balance (Under Full Cost) at Dec. 31, 2014		$ 18	$ 35	$ 586	$ 1,064,667	(65,719)	999,587
Balance at Dec. 31, 2014	[1]	$ 18	$ 35	$ 586	1,064,667	(897,571)	167,735
Balance (in shares) (Under Full Cost) at Dec. 31, 2014		1,839	3,532	58,581
Balance (in shares) at Dec. 31, 2014	[1]	1,839	3,532	58,581
Increase (Decrease) in Stockholders' Equity (Deficit)
Dividends on Series A and Series B Preferred stock						(15,960)	(15,960)
Restricted stock awards, net of forfeitures				$ 33	(33)
Restricted stock awards, net of forfeitures (in shares)				3,337
Exchange of preferred stock for common stock					48	(48)
Exchange of preferred stock for common stock (in shares)			(4)	10
Stock-based compensation					14,831		14,831
Net income (loss) | Under Full Cost							(1,454,627)
Net income (loss)						(726,089)	(726,089)	[2]
Balance at Dec. 31, 2015	[1]	$ 18	$ 35	$ 619	1,079,513	(1,639,668)	(559,483)
Balance (in shares) at Dec. 31, 2015	[1]	1,839	3,528	61,928
Increase (Decrease) in Stockholders' Equity (Deficit)
Dividends on Series A and Series B Preferred stock				$ 10	7,964	(15,948)	(7,974)
Dividends on Series A and Series B Preferred stock (in shares)				967
Restricted stock awards, net of forfeitures				$ 41	(41)
Restricted stock awards, net of forfeitures (in shares)				3,728
Stock-based compensation					24,961		24,961
Net income (loss) | Under Full Cost							(256,958)
Net income (loss)						(141,486)	(141,486)	[2]
Balance (Under Full Cost) at Dec. 31, 2016							(696,140)
Balance at Dec. 31, 2016	[1]	$ 18	$ 35	$ 670	1,112,397	(1,797,102)	(683,982)	[3]
Balance (in shares) at Dec. 31, 2016	[1]	1,839	3,528	66,623
Increase (Decrease) in Stockholders' Equity (Deficit)
Issuance of warrants					58,958		58,958
Issuance of common shares to holders of Preferred Units				$ 15	17,940		17,955
Issuance of common shares to holders of Preferred Units (in shares)				1,500
Issuance of common stock, net of offering costs				$ 115	134,748		134,863
Issuance of common stock, net of offering costs (in shares)				11,500
Dividends on Series A and Series B Preferred stock				$ 24	15,924	(15,948)
Dividends on Series A and Series B Preferred stock (in shares)				2,437
Dividends on SN UnSub preferred units						(41,667)	(41,667)
Distributions - SN UnSub preferred units						(2,592)	(2,592)
Accretion of discount on SN UnSub preferred units						(18,039)	(18,039)
Restricted stock awards, net of forfeitures				$ 21	(21)
Restricted stock awards, net of forfeitures (in shares)				1,925
Stock-based compensation					22,909		22,909
Deferred tax benefit - current period retained earnings impact					(737)		(737)
Net income (loss) | Under Full Cost							(17,899)
Net income (loss)						43,192	43,192
Balance (Under Full Cost) at Dec. 31, 2017							(542,388)
Balance at Dec. 31, 2017		$ 18	$ 35	$ 845	$ 1,362,118	$ (1,832,156)	$ (469,140)
Balance (in shares) at Dec. 31, 2017		1,839	3,528	83,985
[1]	Financial information for 2016, 2015, and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.
[2]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.
[3]	* Financial information for 2016 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Consolidated Statements of Sto7

Consolidated Statements of Stockholders' Equity (Deficit) (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Offering costs	$ 7.8
Common Stock
Offering costs	$ 7.8

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$ 43,192		$ (141,486)	[1]	$ (726,089)	[1]
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		177,078		147,485	[2]	264,379	[2]
Impairment of oil and natural gas properties		39,574		47,381	[2]	723,971	[2]
Gain on sale of oil and natural gas properties		(81,955)		(85,322)	[2]
Stock-based and phantom unit compensation expense		40,298		37,090	[1]	14,830	[1]
Net (gains) losses on commodity derivative contracts		6,100		53,149	[2]	(172,886)	[2]
Net cash settlement received on commodity derivative contracts		17,628		122,145	[1]	131,123	[1]
Losses incurred on premiums for derivative contracts	[1]			24,548		(121)
Loss on embedded derivative		1,551
Cash reimbursements received for operating leasehold improvements	[1]					2,649
(Gain) loss on investments		871		(1,818)	[1]	935	[1]
Amortization of deferred gain on Western Catarina Midstream Divestiture		(23,720)		(23,720)	[1]	(4,943)	[1]
Amortization of debt issuance costs		12,647		7,840	[1]	7,529	[1]
Accretion of debt discount, net		634		633	[1]	703	[1]
Deferred taxes		(737)				1	[1]
(Gain) loss on inventory market adjustment		(9)		649	[1]
Distributions from equity investments		1,191		930	[1]
Earnings from equity investments		(779)		(3,466)	[2]
Changes in operating assets and liabilities:
Accounts receivable		(86,604)		(9,626)	[1]	60,480	[1]
Accounts receivable - related entities		1,957		(2,704)	[1]	(3,311)	[1]
Other current assets		(15,222)		1,504	[1]	(450)	[1]
Other assets		(946)
Accounts payable		13,918		(3,108)	[1]	(25,303)	[1]
Other payables		76,304		247	[1]	(2,290)	[1]
Accrued liabilities		2,435		10,404	[1]	3,347	[1]
Other current liabilities		66,683				(5,166)	[1]
Other long-term liabilities	[1]					1,188
Net cash provided by operating activities		292,089		182,754	[1]	270,576	[1]
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for oil and natural gas properties		(500,334)		(312,939)	[1]	(654,154)	[1]
Payments for other property and equipment		(18,566)		(5,394)	[1]	(8,123)	[1]
Proceeds from sale of oil and natural gas properties		162,801		179,143	[1]	427,571	[1]
Acquisition of oil and natural gas properties		(1,039,127)				(7,658)	[1]
Investment in SMNP	[1]			(25,000)
Purchases of investments		(74)		(36,502)	[1]	(49,985)	[1]
Sale of investments		12,500		92,458	[1]
Net cash used in investing activities		(1,382,800)		(108,234)	[1]	(292,349)	[1]
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		373,250		60,000	[1]
Repayment of borrowings		(143,586)		(60,000)	[1]
Issuance of common stock (net of underwriting discounts of $7.8 million)		135,942
Issuance of preferred units		500,000
Issuance costs related to preferred units		(20,894)
Financing costs		(25,788)		(1,758)	[1]	(400)	[1]
Preferred dividends paid	[1]			(3,987)		(15,960)
Cash paid to tax authority for employee stock-based compensation awards		(1,437)		(1,906)	[1]	(533)	[1]
Preferred unit distribution		(44,259)
Net cash provided by (used in) financing activities		773,228		(7,651)	[1]	(16,893)	[1]
Increase (decrease) in cash and cash equivalents		(317,483)		66,869	[1]	(38,666)	[1]
Cash and cash equivalents, beginning of period	[1]	501,917	[3]	435,048		473,714
Cash and cash equivalents, end of period		184,434		501,917	[1],[3]	435,048	[1]
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in asset retirement obligations		8,376		(2,895)	[1]	(1,877)	[1]
Change in accrued capital expenditures		50,613		(16,829)	[1]	(110,744)	[1]
Debt assumed in exchange for equity interest in SR		23,996
SUPPLEMENTAL DISCLOSURE:
Cash paid for taxes	[1]			1,996		158
Cash paid for interest		$ 126,516		$ 118,498	[1]	$ 121,644	[1]
[1]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.
[2]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.
[3]	* Financial information for 2016 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Consolidated Statements of Cas9

Consolidated Statements of Cash Flows (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Consolidated Statements of Cash Flows
Underwriting discounts	$ 7.8

Organization and Business

Organization and Business	12 Months Ended
	Dec. 31, 2017
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 potential future development opportunities. As of December 31, 2017, we have assembled approximately 487,000 gross leasehold acres (285,000 net acres) in the Eagle Ford Shale. In addition, we continually evaluate opportunities to grow our acreage and our producing assets through acquisitions. Our successful acquisition of such assets will depend on the opportunities and the financing alternatives available to us at the time we consider such opportunities.

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
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 August 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities,” which changes the recognition and presentation requirements of hedge accounting, including eliminating the requirement to separately measure and report hedge ineffectiveness, and presenting all items that affect earnings in the same income statement line item as the hedged item. The ASU also provides new alternatives for applying hedge accounting. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 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 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 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. The Company does not anticipate that ASU 2016-18 will have a material effect on its consolidated and condensed financial statements and related disclosures. 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. 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 adopted ASU 2016-09 as of the quarter ended March 31, 2017 on a retrospective basis. Adoption of this guidance affected the statement of cash flows as of December 31, 2016 as follows (in thousands): Increase in net cash provided by operating activities of approximately $1,906 Increase in net cash used in financing activities of approximately $1,906 Adoption of this guidance affected the statement of cash flows as of December 31, 2015 as follows (in thousands): Increase in net cash provided by operating activities of approximately $533 Increase in net cash used in financing activities of approximately $533 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 15, “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. 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 apply the modified retrospective approach. As part of the assessment, the Company formed an implementation work team, completed trainings on the new revenue recognition model and gathered our material revenue contracts covering current revenue streams for which we evaluated the impacts to the consolidated financial statements under the revised standards. In addition, the Company is evaluating the impacts of significant historical transactions under the new standard. As of December 31, 2017, the Company determined that the deferred gains recorded under the Carnero Gathering Disposition and Carnero Processing Disposition (defined below in Note 10, “Related Party Transactions”) will be de-recognized under the new standard and a derivative asset could be recorded for the value of the earnout provision owed to us by SNMP. Under the modified retrospective approach, the balance of accumulated deficit will be adjusted on January 1, 2018. Change in Accounting Principle During the fourth quarter of 2017, we changed our method of accounting for oil and gas exploration and development activities from full cost to the successful efforts method of accounting. Financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 932 “Extractive Activities – Oil and Gas.” Although the full cost method of accounting for oil and gas exploration and development activities continues to be an acceptable alternative, the successful efforts method of accounting is the generally preferred method under U.S. GAAP and is more widely used in the industry such that the change improves the comparability of the Company’s financial statements to its peers. Changing to the successful efforts method of accounting is expected to provide greater transparency in results of our assets, enhance operating decision making and capital allocation processes and eliminate proved property impairments based on historical prices, which are not indicative of fair value of our assets. In general, under successful efforts, exploration expenditures such as exploratory dry holes, exploratory geological and geophysical costs, delay rentals, unproved impairments, and exploration overhead are charged against earnings as incurred, versus being capitalized under the full cost method of accounting. Successful efforts also provides for the assessment of potential property impairments under Accounting Standards Codification (ASC) 360 “Property, Plant, and Equipment” by comparing the net carrying value of oil and gas properties with associated projected undiscounted pre-tax future net cash flows. If the expected undiscounted pre-tax future net cash flows are lower than the unamortized capitalized costs, the capitalized cost is reduced to fair value. Under the full cost method of accounting, a write-down would be required if the net carrying value of oil and gas properties exceeded a full cost “ceiling,” using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. In addition, gains or losses, if applicable, are generally recognized on the dispositions of oil and gas property and equipment under the successful efforts method, as opposed to an adjustment to the net carrying value of the remaining assets under the full cost method. 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, embedded derivatives 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, 2017 and 2016, 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 successful efforts method of accounting. All direct costs and certain indirect costs associated with the acquisition, successful 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. Depreciation, depletion and amortization— Depreciation, depletion and amortization (“DD&A”) is provided using the units-of-production method based upon estimates of proved reserves of oil, natural gas and NGLs with production of the same converted to a common unit of measure based upon the relative energy content of the hydrocarbons. The Company groups its oil and gas properties with a common geological structure or stratigraphic condition (“common operating field”) in accordance with ASC 932 “Extractive Activities – Oil and Gas” for purposes of computing DD&A, assessing proved property impairments and accounting for asset dispositions. All capitalized costs of oil and natural gas properties are amortized using the units-of-production method based on proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined. Once the assessment of unproved properties is complete and when major development projects are evaluated, the costs previously excluded from amortization are transferred to proved oil and natural gas properties amortization begins. All other properties are stated at historical cost, net of impairments, and are depreciated using the straight-line method over their respective useful lives. 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. In addition, considerable judgment is necessary 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 expense. Impairment of Oil and Natural Gas Properties —Capitalized costs (net of accumulated depreciation, depletion and amortization and impairment) of proved oil and natural gas properties are subjected to an impairment test when facts and circumstances indicate that their carrying value may not be recoverable. Net capitalized costs of proved oil and natural gas properties are compared to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows. The estimated future cash flows used to determine whether an impairment is present and the related fair value calculations are typically based on judgmental assessments of future production, commodity prices, operating expenses, and capital expenditures, utilizing the available information. The underlying commodity prices embedded in the estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that are expected to impact the realizable price. We did not record a proved property impairment during the year ended December 31, 2017. During the year ended December 31, 2016, we recorded a proved property impairment of $3.7 million due to the decline of oil and natural gas prices during the first half of the year. We recorded impairment of $700.3 million to our proved oil and natural gas properties due to the significant decline in oil and natural gas prices during the year ended December 31, 2015. Unproved Properties —Costs associated with unproved properties and properties under development are excluded from the amortization base until the properties have been evaluated. Additionally, the costs associated with 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 amortization base when management determines that a project area has been evaluated through drilling operations or a thorough geologic evaluation. If the results of an assessment indicate that the properties are impaired, the carrying amount of the identified unproved properties are reduced to their fair value. We recorded impairment of $39.6 million to our unproved oil and natural gas properties for the year ended December 31, 2017 due to a write-down of our TMS acreage to fair value. We recorded impairments of $43.6 million and $23.7 million to our unproved oil and natural gas properties due to acreage abandonment from changes in development plan for the years ended December 31, 2016 and December 31, 2015, respectively. The costs of retaining unproved properties and the impairment of unsuccessful leases, are included in “Impairment expense” in the Company’s Consolidated Statements of Operations. Based on management’s review and current operating plans, approximately 4%, 4% and 2% of the unproved property balance at December 31, 2017 is expected to be developed and added to the amortization base during the years 2018, 2019 and 2020, respectively. The remaining balances in unproved properties relate to project areas that will not be thoroughly evaluated until after 2020, and represent leasehold interests that have expiration dates beginning in 2020 or leasehold interests that are currently held by production and/or continuous operations. 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, 2017, 2016 and 2015 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 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 2017, the Company capitalized approximately $18.7 million in costs associated with the incurrence of the SN UnSub Credit Agreement (as defined in “Note 6. Debt”). 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 6. Debt”). During 2015, the Company capitalized approximately $0.4 million in costs associated with amending our Second Amended and Restated Agreement. At December 31, 2017 and December 31, 2016, the Company had approximately $47.2 million and $35.0 million, respectively, of debt issuance costs (net of accumulated amortization of $34.5 million and $22.5. 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 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, 2017 and 2016. 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 and is included in “Depreciation, depletion, amortization and accretion” in the Company’s Consolidated Statements of Operations. 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 8, “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 Sales of oil, natural gas and NGLs 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 entitlement method of accounting is used for the sale of oil, natural gas and NGLs. 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, 2017, 2016 and 2015 there were no material oil and natural gas imbalances. Sales to Major Customers The Company’s oil, natural gas and NGLs were sold to certain customers representing 10% or more of its total revenues for the years ended December 31, 2017, 2016 and 2015 as listed below: 2017 2016 2015 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 (the “Services Agreement”). See detailed discussion of the Company’s relationship with SOG in Note 10, “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 re

Change in Accounting Principle

Change in Accounting Principle	12 Months Ended
	Dec. 31, 2017
Change in Accounting Principle
Change in Accounting Principle	Note 3. Change in Accounting Principle During the fourth quarter of 2017, the Company voluntarily changed its method of accounting for oil and gas exploration and development activities from the full cost method to the successful efforts method. Accordingly, financial information for prior periods has been recast to reflect retrospective application of the successful efforts method. In general, under successful efforts, exploration expenditures such as exploratory dry holes, exploratory geological and geophysical costs, delay rentals, unproved impairments, and exploration overhead are charged against earnings as incurred, versus being capitalized under the full cost method of accounting. The successful efforts method also provides for the assessment of potential property impairments under FASB Accounting Standards Codification 360 “Property, Plant and Equipment” by comparing the net carrying value of oil and gas properties with associated projected undiscounted pre-tax future net cash flows. If the expected undiscounted pre-tax future net cash flows are lower than the unamortized capitalized costs, the capitalized cost is reduced to fair value. Under the full cost method of accounting, a write-down would be required if the net carrying value of oil and gas properties exceeds a full cost “ceiling,” using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. In addition, gains or losses, if applicable, are generally recognized on the dispositions of oil and gas property and equipment under the successful efforts method, as opposed to an adjustment to the net carrying value of the remaining assets under the full cost method. Our consolidated financial statements have been recast to reflect these differences for all periods presented, including the Consolidated Balance Sheets, Consolidated Statements of Operations, Consolidated Statements of Stockholders’ Equity, Consolidated Statements of Cash Flows and related information in Notes 2, 3, 4, 7, 9, 10, 12, 14, and 19. The following tables present the effects of the change to the successful efforts method in the statement of consolidated operations: Changes to the Consolidated Statement of Operations For the Year Ended December 31, 2017 Under Full Cost Changes As Reported Under Successful Efforts (In thousands, except per share data) Oil and natural gas production expenses $ 253,368 $ (8,907) $ 244,461 Exploration expenses — 5,755 5,755 Depreciation, depletion, amortization and accretion 199,087 (22,009) 177,078 Impairment of oil and natural gas properties — 39,574 39,574 Other income (expense) 7,351 3,751 11,102 Gain on disposal of assets 10,202 71,753 81,955 Income tax benefit (expense) 2,336 — 2,336 Net loss (17,899) 61,091 43,192 Net income allocable to participating securities — — — Net loss attributable to common stockholders $ (96,145) $ 61,091 $ (35,054) — Net loss per common share - basic and diluted $ (1.27) $ 0.81 $ (0.46) Changes to the Consolidated Statement of Operations For the Year Ended December 31, 2016 Under Full Cost Changes As Reported Under Successful Efforts (In thousands, except per share data) Oil and natural gas production expenses $ 164,567 $ (8,907) $ 155,660 Exploration expenses — 403 403 Depreciation, depletion, amortization and accretion 159,760 (12,275) 147,485 Impairment of oil and natural gas properties 169,046 (121,665) 47,381 Gain on disposal of assets 112,294 (26,972) 85,322 Income tax benefit (expense) (1,825) — (1,825) Net loss (256,958) 115,472 (141,486) Net income allocable to participating securities — — — Net loss attributable to common stockholders $ (272,906) $ 115,472 $ (157,434) — Net loss per common share - basic and diluted $ (4.63) $ 1.96 $ (2.67) Changes to the Consolidated Statement of Operations For the Year Ended December 31, 2015 Under Full Cost Changes As Reported Under Successful Efforts (In thousands, except per share data) Oil and natural gas production expenses 156,528 (1,856) 154,672 Exploration expenses — 1,982 1,982 Depreciation, depletion, amortization and accretion 344,572 (80,193) 264,379 Impairment of oil and natural gas properties 1,365,000 (641,029) 723,971 Gain on disposal of assets — — — Income tax benefit (expense) (7,600) 7,442 (158) Net loss (1,454,627) 728,538 (726,089) Net income allocable to participating securities — — — Net loss attributable to common stockholders $ (1,470,635) $ 728,538 $ (742,097) — Net loss per common share - basic and diluted $ (25.70) $ 12.73 $ (12.97) The following tables present the effects of the change to the successful efforts method in the statement of consolidated cash flows: Changes to the Consolidated Statement of Cash Flows For the Year Ended December 31, 2017 Under Full Cost Change As reported Under Successful Efforts (In thousands) Net loss $ (17,899) $ 61,091 $ 43,192 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 199,087 (22,009) 177,078 Impairment of oil and natural gas properties — 39,574 39,574 Gain on sale of oil and natural gas properties (10,202) (71,753) (81,955) Amortization of deferred gain on Catarina Midstream Sale (14,813) (8,907) (23,720) Deferred taxes (737) — (737) Net cash provided by operating activities 294,093 (2,004) 292,089 Payments for oil and natural gas properties (502,338) 2,004 (500,334) Net cash used in investing activities (1,384,804) 2,004 (1,382,800) Net cash provided by (used in) financing activities 773,228 — 773,228 Increase (decrease) in cash and cash equivalents (317,483) — (317,483) Cash and cash equivalents, beginning of period 501,917 — 501,917 Cash and cash equivalents, end of period $ 184,434 $ — $ 184,434 Changes to the Consolidated Statement of Cash Flows For the Year Ended December 31, 2016 Under Full Cost Change As reported Under Successful Efforts (In thousands) Net loss $ (256,958) $ 115,472 $ (141,486) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 159,760 (12,275) 147,485 Impairment of oil and natural gas properties 169,046 (121,665) 47,381 Gain on sale of oil and natural gas properties (112,294) 26,972 (85,322) Amortization of deferred gain on Catarina Midstream Sale (14,813) (8,907) (23,720) Deferred taxes — — — Net cash provided by operating activities 183,157 (403) 182,754 Payments for oil and natural gas properties (313,342) 403 (312,939) Net cash used in investing activities (108,637) 403 (108,234) Net cash provided by (used in) financing activities (7,651) — (7,651) Increase (decrease) in cash and cash equivalents 66,869 — 66,869 Cash and cash equivalents, beginning of period 435,048 — 435,048 Cash and cash equivalents, end of period $ 501,917 $ — $ 501,917 Changes to the Consolidated Statement of Cash Flows For the Year Ended December 31, 2015 Under Full Cost Change As reported Under Successful Efforts (In thousands) Net income (loss) $ (1,454,627) $ 728,538 $ (726,089) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 344,572 (80,193) 264,379 Impairment of oil and natural gas properties 1,365,000 (641,029) 723,971 Amortization of deferred gain on Catarina Midstream Sale (3,086) (1,856) (4,942) Deferred Taxes 7,443 (7,442) 1 Net cash provided by operating activities 272,558 (1,982) 270,576 Payments for oil and natural gas properties (656,136) 1,982 (654,154) Net cash used in investing activities (294,331) 1,982 (292,349) Net cash provided by (used in) financing activities (16,893) — (16,893) Increase (decrease) in cash and cash equivalents (38,666) — (38,666) Cash and cash equivalents, beginning of period 473,714 — 473,714 Cash and cash equivalents, end of period $ 435,048 $ — $ 435,048 The following tables present the effects of the change to the successful efforts method in the consolidated balance sheet: Changes to Consolidated Balance Sheet December 31, 2017 Under Full Cost Changes As Reported Under Successful Efforts (In thousands) Oil and natural gas properties: Unproved oil and natural gas properties 398,212 393 398,605 Proved oil and natural gas properties 4,462,171 (1,331,764) 3,130,407 Total oil and natural gas properties 4,860,383 (1,331,371) 3,529,012 Less: Accumulated depreciation, depletion, amortization and impairment (2,931,039) 1,429,486 (1,501,553) Total oil and natural gas properties, net 1,929,344 98,115 2,027,459 Total assets $ 2,372,520 $ 98,115 $ 2,470,635 Current liabilities: Other 106,337 8,907 115,244 Total current liabilities 453,621 8,907 462,528 Other liabilities 49,520 15,960 65,480 Total liabilities 2,487,396 24,867 2,512,263 Accumulated deficit (1,905,404) 73,248 (1,832,156) Total stockholders' equity (deficit) (542,388) 73,248 (469,140) Total liabilities and stockholders' equity (deficit) $ 2,372,520 $ 98,115 $ 2,470,635 Changes to Consolidated Balance Sheet December 31, 2016 Under Full Cost Changes As Reported Under Successful Efforts (In thousands) Oil and natural gas properties: Unproved oil and natural gas properties 231,424 (6,401) 225,023 Proved oil and natural gas properties 3,164,115 (1,314,383) 1,849,732 Total oil and natural gas properties 3,395,539 (1,320,784) 2,074,755 Less: Accumulated depreciation, depletion, amortization and impairment (2,736,951) 1,366,715 (1,370,236) Total oil and natural gas properties, net 658,588 45,931 704,519 Total assets $ 1,286,280 $ 45,931 $ 1,332,211 Current liabilities: Other 22,201 8,907 31,108 Total current liabilities 176,997 8,907 185,904 Other liabilities 64,333 24,866 89,199 Total liabilities 1,982,420 33,773 2,016,193 Accumulated deficit (1,809,260) 12,158 (1,797,102) Total stockholders' equity (deficit) (696,140) 12,158 (683,982) Total liabilities and stockholders' equity (deficit) $ 1,286,280 $ 45,931 $ 1,332,211

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2017
Acquisitions and Divestitures
Acquisitions and Divestitures	Note 4. 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. Javelina Disposition On September 19, 2017, the Company, through its wholly owned subsidiary, SN Cotulla Assets, LLC (“SN Cotulla”), sold approximately 68,000 undeveloped net acres located in the Eagle Ford Shale in LaSalle and Webb Counties, Texas to Vitruvian Exploration IV, LLC for approximately $105 million in cash, after preliminary closing adjustments (“the Javelina Disposition”). Consideration received from the Javelina Disposition was based on an August 1, 2017 effective date and is subject to normal and customary post-closing adjustments. The Company recorded a gain of approximately $73.7 million on the Javelina Disposition. Marquis Disposition On June 15, 2017, the Company, through its wholly owned subsidiary, SN Marquis LLC, sold approximately 21,000 net acres primarily located in the Eagle Ford Shale in Fayette and Lavaca Counties, Texas to Lonestar Resources US, Inc. (“Lonestar”) for approximately $44 million in cash, after preliminary closing adjustments, and Lonestar’s Series B Convertible Preferred Stock which subsequently converted into 1.5 million shares of Lonestar’s Class A Common Stock (the “Marquis Disposition”). Consideration received from the Marquis Disposition was based on a January 1, 2017 effective date and is subject to other normal and customary post-closing adjustments. Assets conveyed pursuant to the Marquis Disposition consist of net proved reserves of approximately 2.7 MMBoe (100% developed) and net production of approximately 1,750 Boe per day from 104 gross (65 net) wells. The Company did not record any gains or losses as a result of the Marquis Disposition. Comanche Acquisition On March 1, 2017, the Company, through two of its subsidiaries, SN EF UnSub, LP (“SN UnSub”) and SN EF Maverick, LLC (“SN Maverick”), along with Gavilan Resources, LLC (“Gavilan”), an entity controlled by The Blackstone Group, L.P., completed the acquisition 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) acres of deep rights only, which includes the Pearsall Shale, representing an approximate 49% average working interest therein (the “Comanche Assets”) from Anadarko E&P Onshore LLC and Kerr-McGee Oil and Gas Onshore LP (together, “Anadarko”) for approximately $2.1 billion in cash, after preliminary closing adjustments (the “Comanche Acquisition”). Pursuant to the purchase and sale agreement entered into in connection with the Comanche Acquisition, (i) SN UnSub paid approximately 37% of the purchase price (including through a $100 million cash contribution from other Company entities) and (ii) SN Maverick paid approximately 13% of the purchase price. In the aggregate, SN UnSub and SN Maverick acquired half of the 49% working interest in the Comanche Assets (approximately 50% and 0%, respectively, of the estimated total proved developed producing reserves (PDPs), 20% and 30%, respectively, of the estimated total proved developed non-producing reserves (PDNPs), and 20% and 30%, respectively, of the total proved undeveloped reserves (PUDs)). Pursuant to the purchase and sale agreement, Gavilan paid 50% of the purchase price and acquired the remaining half of the 49% working interest in and to the Comanche Assets (and approximately 50% of the estimated total PDPs, PDNPs and PUDs) (the “SN Comanche Assets”). The Comanche Assets are primarily located in the Western Eagle Ford and significantly expanded the Company’s asset base and production. The effective date of the Comanche Acquisition was July 1, 2016. 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 $ 781,789 Unproved properties 263,471 Other assets acquired 6,702 Fair value of assets acquired 1,051,962 Asset retirement obligations (8,289) Fair value of net assets acquired $ 1,043,673 In addition, as is common in our industry, we are party to certain gathering agreements that obligate us to deliver a specified volume of production over a defined time horizon. In particular, with respect to the Comanche Assets, we, as the operator, on behalf of ourselves and the other working interest partners, are party to two gathering agreements that require us to deliver variable monthly quantities through 2034. Gross volumes under these contracts peak at approximately 63,000 Bbl per day (approximately 14,800 Bbl per day net) of crude oil and condensate in 2020 and 430,000 Mcf per day (approximately 101,400 Mcf per day net) of natural gas in 2022, and then decrease annually thereafter through the end of the contracts. We are currently meeting our minimum volume commitments under these contracts and expect to continue to fulfill these obligations based on our anticipated development plan for the Comanche Assets. 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 by and among SN Cotulla, the Company for the limited purposes set forth therein, Carrizo Eagle Ford and Carrizo Oil and Gas for the limited purposes set forth therein, for an adjusted purchase price of approximately $153.5 million, subject to normal and customary post-closing adjustments (the “Cotulla Disposition”). The assets sold included estimated net proved reserves as of the effective date of June 1, 2016 of approximately 6.9 MMBoe. Proved developed reserves are estimated to account for approximately 90% of the total net proved reserves. As of the effective date, the Cotulla Assets consisted of approximately 15,000 net acres with 112 gross (93 net) wells producing approximately 3,000 Boe/d. During 2017, two additional closings occurred and final settlement adjustments were made resulting in total aggregate consideration of approximately $167.4 million. Typically, proceeds from the sale or disposition of oil and natural gas properties are applied to reduce net capitalized costs with no gain or loss recognized, unless the sale or disposition causes a significant change in the relationship between costs and the estimated quantities of proved reserves. However, in circumstances where treating a sale like a normal retirement would result in a significant change in the relationship between costs and the estimated quantities of proved reserves, judgment should be applied. The Company determined that adjustments to capitalized costs for the Cotulla Disposition would cause a significant change in the relationship between costs and the estimated quantities of proved reserves. Upon the initial closing of the Cotulla Disposition, the Company recorded a gain of approximately $85.3 million. As a result of subsequent closings of the Cotulla Disposition, the Company has recorded additional gains totaling $10.4 million during the twelve months ended December 31, 2017. 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 SNMP for an adjusted purchase price of approximately $24.2 million in cash (the “Production Asset Transaction”). The Production Asset Transaction includes working interests in 23 producing Eagle Ford wellbores located in Dimmit, LaSalle 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. For the escalating working interests conveyed in the 11 producing wellbores, 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 has automatically increased in incremental amounts according to the purchase agreement through 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 SNMP common units to SNMP 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 Bbl 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 $116.8 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 of five years as an offset to the transportation fees paid to SNMP under the Gathering Agreement. Palmetto Disposition On March 31, 2015, we completed our disposition to a subsidiary of SNMP of escalating amounts of partial working interests in 59 wellbores located in Gonzales County, Texas (the “Palmetto Disposition”) for an adjusted purchase 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 $81.4 million in cash, after purchase price adjustments, and 1,052,632 common units of SNMP (the “SNMP Common Units”) valued at approximately $2.0 million as of the date of the closing. The SNMP Common Units were later sold back to SNMP in October 2015 as part of the Western Catarina Midstream Divestiture described above. The Company did not record any gains or losses related to the Palmetto Disposition. Results of Operations and Pro Forma Operating Results The following unaudited pro forma combined financial information for the years ended December 31, 2017 and 2016 is based on the historical consolidated financial statements of the Company adjusted to reflect as if the Comanche Acquisition and related financing had occurred on January 1, 2016. The unaudited pro forma combined financial information includes adjustments primarily for revenues and expenses for the acquired properties, depreciation, depletion, amortization and accretion, interest expense and debt issuance cost amortization for acquisition debt, and issuance cost amortization of the acquisition preferred financing. The unaudited pro forma combined financial statements give effect to the events set forth below: · The Comanche Acquisition completed March 1, 2017. · The issuance of 500,000 SN UnSub Preferred Units for $500 million to finance a portion of the Comanche Acquisition. · The borrowing of $173.5 million on a $330 million senior secured reserve based revolving credit facility of SN UnSub to finance a portion of the Comanche Acquisition. · Issuance of 1,455,000 shares of the Company’s common stock to certain funds managed or advised by GSO Capital Partners LP (“GSO”), which is an investor in SN UnSub. · Issuance of 45,000 shares of the Company’s common stock to Intrepid Private Equity V-A, LLC (“Intrepid”), which is an investor in SN UnSub. · Issuance of warrants to certain funds managed or advised by GSO (the “GSO Funds”) to purchase 1,940,000 shares of the Company’s common stock at an exercise price of $10 per share. · Issuance of warrants to Intrepid to purchase 60,000 shares of the Company’s common stock at an exercise price of $10 per share. · Issuance of warrants to the Blackstone Warrantholders (as defined below) to purchase 6,500,000 shares of the Company’s common stock at an exercise price of $10 per share. · Issuance of 100 Class A Units in Gavilan Holdco (as defined below) to SN Comanche Manager, LLC (“SN Comanche Manager” or the “Manager”). Year Ended December 31, 2017 2016 Revenues $ 784,360 $ 693,843 Net income (loss) attributable to common stockholders $ (6,458) $ (242,847) Net income (loss) per common share, basic and diluted $ (0.09) $ (3.38) The unaudited pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the Comanche Acquisition and related financings been completed as of the dates set forth in this unaudited pro forma combined financial information and should not be taken as indicative of the Company’s future combined results of operations. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma combined financial information and actual results. Post-Acquisition Operating Results The amounts of revenue and excess of revenues over direct operating expenses included in the Company’s condensed consolidated statements of operations for the year ended December 31, 2017 for the Comanche Acquisition are shown in the table that follows. Direct operating expenses include lease operating expenses and production and ad valorem taxes (in thousands): Year Ended December 31, 2017 Revenues $ 255,282 Excess of revenues over direct operating expenses $ 138,046

Cash and Cash Equivalents

Cash and Cash Equivalents	12 Months Ended
	Dec. 31, 2017
Cash and Cash Equivalents
Cash and Cash Equivalents	Note 5. Cash and Cash Equivalents As of December 31, 2017 and 2016, cash and cash equivalents consisted of the following (in thousands): As of December 31, 2017 2016 Cash at banks $ 135,363 $ 58,269 Money market funds 49,071 443,648 Total cash and cash equivalents $ 184,434 $ 501,917

Debt

Debt	12 Months Ended
	Dec. 31, 2017
Debt
Debt	Note 6. Debt Debt as of December 31, 2017 consisted of $1.15 billion face value of 6.125% Notes (defined below) maturing on January 15, 2023, $600 million principal amount of 7.75% Notes (defined below) maturing on June 15, 2021, $50.0 million related to the Second Amended and Restated Credit Agreement, $175.5 million related to the SN UnSub Credit Agreement, which is non-recourse to Sanchez Energy Corporation (“SN”) and the other obligors on the 6.125% Notes, 7.75% Notes and the Second Amended and Restated Credit Agreement (“Non-Recourse to the Company”), as well as to the obligors under the SR Credit Agreement (defined below) and the Non-Recourse Subsidiary Term Loan (defined below), approximately $24.0 million related to the SR Credit Agreement (defined below), which is Non-Recourse to the Company and to the obligors under the SN UnSub Credit Agreement and the Non-Recourse Subsidiary Term Loan, and approximately $4.2 million related to a 4.59% non-recourse subsidiary term loan due 2022 (the “Non-Recourse Subsidiary Term Loan”), which is Non-Recourse to the Company and to the obligors under the SN UnSub Credit Agreement and the SR Credit Agreement. As of December 31, 2017 and 2016 the Company’s debt consisted of the following: Amount Outstanding (in thousands) as of December 31, December 31, Interest Rate Original Maturity Date 2017 2016 Short-Term Debt SR Credit Agreement (1)(2) Variable August 8, 2018 $ 23,996 $ — Total short-term debt $ 23,996 $ — Long-Term Debt Second Amended and Restated Credit Agreement Variable June 30, 2019 $ 50,000 $ — SN UnSub Credit Agreement (1) Variable March 1, 2022 175,500 — 7.75% Notes 7.75% June 15, 2021 600,000 600,000 4.59% Non-Recourse Subsidiary Term Loan (1) 4.59% August 31, 2022 4,164 — 6.125% Notes 6.125% January 15, 2023 1,150,000 1,150,000 1,979,664 1,750,000 Unamortized discount on Additional 7.75% Notes (3,126) (4,030) Unamortized premium on Additional 6.125% Notes 1,360 1,629 Unamortized debt issuance costs (47,215) (34,832) Total long-term debt $ 1,930,683 $ 1,712,767 (1) These debt instruments are Non-Recourse to the Company. (2) Bears a weighted-average interest rate of 5.122%. The components of interest expense are (in thousands): Year Ended December 31, 2017 2016 2015 Interest on Senior Notes $ (116,938) $ (116,938) $ (116,938) Interest on SN UnSub Credit Agreement (7,639) — — Interest on SR Credit Agreement (105) — — Interest on Non-Recourse Subsidiary Term Loan (65) — — Interest expense and commitment fees on Second Amended and Restated Credit Agreement (2,135) (1,561) (1,229) Amortization of debt issuance costs (12,647) (7,840) (7,529) Amortization of discount on Additional 7.75% Notes (904) (904) (904) Amortization of premium on Additional 6.125% Notes 270 270 201 Total interest expense $ (140,163) $ (126,973) $ (126,399) Credit Facilities Second Amended and Restated Credit Agreement On June 30, 2014, the Company, as borrower, and certain of its operating subsidiaries, 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 the lenders party thereto (together with all subsequent amendments prior to January 1, 2018, the ‘‘Second Amended and Restated Credit Agreement’’). The Second Amended and Restated Credit Agreement provided 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, 2017, there were $50 million in 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 was at all times subject to customary conditions and the then-applicable borrowing base and aggregate elected commitment amount. As of December 31, 2017, $250 million of the $300 million aggregate elected commitment amount was available for future revolver borrowings. The Second Amended and Restated Credit Agreement was scheduled to mature on June 30, 2019. The borrowing base under the Second Amended and Restated Credit Agreement was 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 generally occurred on or before April 1 and October 1 of each year. The borrowing base was also subject to, among other things, (i) automatic reduction by 25% of the amount of certain issuances of high yield debt and second lien debt, (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 directed, 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 sold assets and liquidated swaps. The Company’s obligations under the Second Amended and Restated Credit Agreement were guaranteed by certain of the Company’s existing and future subsidiaries and were secured by a first priority lien on substantially all of the Company’s assets and the assets of its existing and future subsidiaries, including a first priority lien on all ownership interests in existing and future subsidiaries, in each case, subject to customary exceptions; provided, however, that the guarantee and first priority lien requirements did not extend to existing and future subsidiaries designated as “unrestricted subsidiaries,” including SN UnSub. At the Company’s election, interest on borrowings under the Second Amended and Restated Credit Agreement was calculated based on an alternate base rate (“ABR”) or an adjusted Eurodollar (LIBOR) rate, in each case, plus an applicable margin. The applicable margin varied from 1.00% to 2.00% for ABR 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 was also required to pay a commitment fee of 0.50% per annum on any unused aggregate elected commitment amount. Interest on ABR borrowings and the commitment fee were generally payable quarterly. Interest on Eurodollar (LIBOR) borrowings were generally payable at the applicable maturity date, or at three-month intervals for Eurodollar (LIBOR) borrowings with an interest period of more than three months’ duration. The Second Amended and Restated Credit Agreement contained various affirmative and negative covenants and events of default that limited 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 provided 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 contained financial covenants that required 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 as of the last day of each fiscal quarter, 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 2.0 to 1.0 as of the last day of any fiscal quarter. As of December 31, 2017, the Company was in compliance with the covenants of the Second Amended and Restated Credit Agreement. From time to time, the entities that were 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. On February 14, 2018, we refinanced the outstanding loans under the Second Amended and Restated Credit Agreement through the issuance of $500 million in aggregate principal amount of the 7.25% Senior Secured Notes and we concurrently amended and restated the Second Amended and Restated Credit Agreement into the $25 million Third Amended and Restated Credit Agreement. See “ – Note 20, Subsequent Events.” SN UnSub Credit Agreement On March 1, 2017, SN UnSub, as borrower, entered into a credit agreement for a $500 million revolving credit facility with JP Morgan Chase Bank, N.A. as the administrative agent and the lenders party thereto with a maturity date of March 1, 2022 (the “SN UnSub Credit Agreement”). The initial borrowing base amount under the SN UnSub Credit Agreement was $330 million. Additionally, the SN UnSub Credit Agreement provides for the issuance of letters of credit, generally limited in the aggregate to the lesser of $50 million and the total availability under the borrowing base. Availability under the SN UnSub Credit Agreement is at all times subject to customary conditions and the then applicable borrowing base, which is subject to periodic redetermination. As of December 31, 2017, there were approximately $175.5 million of borrowings and no letters of credit outstanding under the SN UnSub Credit Agreement. Semi-annual redeterminations of the borrowing base are generally scheduled to occur in April and October of each year. On November 6, 2017, the borrowing base of the SN UnSub Credit Agreement was reaffirmed at $330 million in conjunction with the fall redetermination. The next regularly scheduled borrowing base redetermination is expected in the second quarter 2018. In addition, the borrowing base is subject to interim redetermination at the request of SN UnSub or the lenders based on, among other things, the lenders’ evaluation of SN UnSub’s and its subsidiaries’ oil and natural gas reserves. The borrowing base is also subject to reduction by 25% of the amount of certain junior debt issuances other than the first $200 million of such debt and by reductions as a result of hedge terminations and asset dispositions that exceed 5% of the then-effective borrowing base, in addition to other customary adjustments. The obligations under the SN UnSub Credit Agreement are guaranteed by all of SN UnSub’s existing and future subsidiaries and secured by a first priority lien on substantially all of SN UnSub’s assets and the assets of SN UnSub’s existing and future subsidiaries, including a first priority lien on all ownership interests in existing and future subsidiaries as well as a pledge of equity interests in SN UnSub held by SN EF UnSub Holdings, LLC (“SN UnSub Holdings”) and SN EF UnSub GP, LLC, the general partner of SN UnSub (the “SN UnSub General Partner”), in each case, subject to customary exceptions; provided, however, that the guarantee and first priority lien requirements do not extend to existing and future subsidiaries of SN UnSub designated as “unrestricted subsidiaries.” As of December 31, 2017, SN UnSub had no subsidiaries. At SN UnSub’s election, borrowings under the SN UnSub Credit Agreement may be made on an ABR or a Eurodollar rate basis, plus an applicable margin. The applicable margin varies from 1.75% to 2.75% for ABR borrowings and from 2.75% to 3.75% for Eurodollar borrowings, depending on the utilization of the borrowing base. In addition, SN UnSub is also required to pay a commitment fee on the amount of any unused commitments at a rate of 0.50% per annum. Interest on ABR borrowings and the commitment fee are generally payable quarterly. Interest on Eurodollar borrowings are generally payable at the applicable maturity date. The SN UnSub Credit Agreement contains various affirmative and negative covenants and events of default that limit SN UnSub’s ability to, among other things, incur indebtedness, make restricted payments, grant liens, consolidate or merge, dispose of certain assets, make certain investments, engage in transactions with affiliates, enter into and maintain hedge transactions and make certain acquisitions. The SN UnSub Credit Agreement provides for an event of default upon a change of control and cross default between the SN UnSub Credit Agreement and other indebtedness of SN UnSub in an aggregate principal amount exceeding $25 million. Additionally, the SN UnSub Credit Agreement contains “separateness” covenants that require SN UnSub to comply with certain corporate formalities and transact with affiliates on an arm’s length basis. Furthermore, the SN UnSub Credit Agreement contains financial covenants that require SN UnSub to satisfy certain specified financial ratios, including the following tests: (i) a current assets plus undrawn borrowing capacity on the SN UnSub Credit Agreement to current liabilities ratio of at least 1.0 to 1.0 as of the last day of each fiscal quarter and (ii) a net debt to consolidated EBITDA ratio of not greater than 4.0 to 1.0 for each test period, in each case commencing with the fiscal quarter ending June 30, 2017. As of December 31, 2017, the Company was in compliance with the covenants of the SN UnSub Credit Agreement. From time to time, the agents, arrangers, book runners and lenders under the SN UnSub Credit Agreement and their affiliates have provided, and may provide in the future, investment banking, commercial lending, hedging and financial advisory services to SN UnSub 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. SR Credit Agreement As of December 31, 2017, we had approximately $24 million in additional past due borrowings under an existing credit facility of an unrestricted subsidiary acquired as part of the SR legal settlement (the “SR Credit Agreement”), which debt is Non-Recourse to the Company and to the obligors on the SN UnSub Credit Agreement and the Non-Recourse Subsidiary Term Loan. Although the original maturity date of the SR Credit Agreement was August 7, 2018, on April 18, 2017, prior to the Company’s acquisition of Sanchez Resources, the administrative agent and the lenders thereunder accelerated the obligations due under the SR Credit Agreement as a result of various defaults thereunder. If we do not repay the approximately $24 million in borrowings due under the SR Credit Agreement or successfully renegotiate the terms of such facility, then the administrative agent or the lenders under that facility could proceed against the collateral securing that debt, consisting of substantially all of Sanchez Resources’ TMS assets (approximately 12,500 net acres). See “Item 8. Financial Statements and Supplementary Data – Note 10. Related Party Transactions”. Senior Notes 7.75% Senior Notes Due 2021 On June 13, 2013, we completed a private offering of $400 million in aggregate principal amount of the 7.75% senior notes that will mature on June 15, 2021 (the “Original 7.75% Notes”). Interest on the notes is payable on June 15 and December 15 of each year. We received net proceeds from this offering of approximately $388 million, after deducting initial purchasers’ discounts and offering expenses, which we used to repay our then-outstanding indebtedness. 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 with 13 gross producing wells 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 governing such notes plus accrued and unpaid interest. In addition, we may be required to make an offer 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 previous credit facility 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 governing such notes 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. The Company may also be required to make an offer 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, Registrar 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' and Mezzanine Equ

Stockholders' and Mezzanine Equity	12 Months Ended
	Dec. 31, 2017
Stockholders' and Mezzanine Equity
Stockholders' and Mezzanine Equity	Note 7. Stockholders’ and Mezzanine Equity Common Stock Offerings — On May 25, 2017, the Company entered into an equity distribution agreement with Citigroup Global Markets, Inc., BMO Capital Markets Corp., Capital One Securities, Inc., RBC Capital Markets, LLC and SunTrust Robinson Humphrey, Inc. and filed with the SEC a prospectus supplement to our shelf registration statement that allows us to issue from time to time shares of our common stock up to an aggregate gross amount of $75 million (the “2017 ATM”). Sales of our common stock, if any, under the 2017 ATM will be made by any method permitted by law deemed to be an “at the market” offering as defined under the Securities Act, including, without limitation, sales made directly on the New York Stock Exchange, on any other existing trading market for our shares of common stock or to or through a market maker or as otherwise agreed by the Company and the sales agent. As of December 31, 2017, we had not issued any shares of our common stock under the 2017 ATM. 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 to the public 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 from this offering of $135.9 million (after deducting underwriters’ discounts fees of approximately $7.8 million) from the sale of the shares of common stock. The Company used the net proceeds of the offering for general corporate purposes, including working capital. 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, 2017, 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, 2017, all dividends accumulated through that date had been paid. The dividends accrued for the period from October 1 to December 31, 2017, were declared by the Board and paid with the Company’s common stock on January 2, 2018. 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 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. The Company used the net proceeds from this offering to fund a portion of the purchase price for the acquisition of certain assets in Dimmit, Frio, LaSalle, and Zavala Counties, Texas in the Eagle Ford Shale. 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 $21.40 per share of common stock) and is subject to specified adjustments. As of December 31, 2017, 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, 2017, all dividends accumulated through that date had been paid. The dividends accrued for the period from October 1 to December 31, 2017, were declared by the Board and paid with the Company’s common stock on January 2, 2018. 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. NOL Rights Plan — On July 28, 2015, the Company entered into a net operating loss carryforwards rights plan (as amended, the “Rights Plan”) with Continental Stock Transfer & Trust Company, as rights agent. In connection therewith, our 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. On March 1, 2017, the Company amended the Rights Plan to, among other things, amend certain defined terms to account for the issuance of warrants and grant of shares of common stock to the GSO Funds (as defined below) and the issuance of warrants to the Blackstone Warrantholders (as defined below) in connection with the closing of the Comanche Acquisition. Common Stock and Stock Warrants Issuance— At the closing of the Comanche Acquisition pursuant to the Amended and Restated Securities Purchase Agreement (the “SPA”), and subject to the other terms and conditions provided therein, (i) the GSO Funds received 1,455,000 shares of the Company’s common stock and warrants to purchase 1,940,000 shares of the Company’s common stock at an exercise price of $10 per share, subject to customary anti-dilution adjustments; and (ii) Intrepid received 45,000 shares of the Company’s common stock and warrants to purchase 60,000 shares of the Company’s common stock at an exercise price of $10 per share, subject to customary anti-dilution adjustments. The warrants issued to the GSO Funds and Intrepid expire on March 1, 2032, in each case in accordance with the terms and conditions of the applicable warrant agreement. Also, at the closing of the Comanche Acquisition, the Company entered into (i) three separate warrant agreements to purchase an aggregate of 6,500,000 shares of the Company’s common stock with each of Gavilan Resources Holdings—A, LLC, Gavilan Resources Holdings —B, LLC, and Gavilan Resources Holdings—C, LLC (collectively, the “Blackstone Warrantholders”), that provide for a $10 exercise price per share to purchase the Company’s common stock, subject to customary anti-dilution adjustments. The warrants issued to the Blackstone Warrantholders expire on March 1, 2022 in accordance with the terms and conditions of the applicable warrant agreement. The exercise price and the number of shares of the Company’s common stock for which a warrant is exercisable are subject to adjustment from time to time upon the occurrence of certain events including: (i) payment of a dividend or distribution to holders of shares of the Company’s common stock payable in the Company’s common stock, (ii) a subdivision, combination, or reclassification of the Company’s common stock, (iii) the distribution of any rights, options or warrants (excluding rights issued under the Rights Plan) to all holders of the Company’s common stock entitling them for a certain period of time to purchase shares of the Company’s common stock at a price per share less than the fair market value per share, and (iv) payment of a cash distribution to all holders of the Company’s common stock or a distribution to all holders of the Company’s common stock any shares of the Company’s capital stock, evidences of indebtedness, or any of assets or any rights, warrants or other securities of the Company. The warrant agreements also provide that, if the Company proposes a voluntary or involuntary dissolution, liquidation or winding up of the affairs of the Company, the holders of the warrants will receive the kind and number of other securities or assets which the holder would have been entitled to receive if the holder had exercised the warrant in full immediately prior to the time of such dissolution, liquidation or winding up and the right to exercise the warrant will terminate on the date on which the holders of record of the shares of common stock are entitled to exchange their shares for securities or assets deliverable upon such dissolution, liquidation or winding up. In addition, the Company entered into separate registration rights agreements with the Blackstone Warrantholders, the GSO Funds, and Intrepid (collectively, the “Registration Rights Agreements”). The Registration Rights Agreements grant the parties certain registration rights for the shares of our common stock acquired by the parties, including the shares issuable upon the exercise of the warrants to purchase the Company’s common stock. The Registration Rights Agreements with the Blackstone Warrantholders and the GSO Funds provide that the Company will use its reasonable best efforts to prepare and file a shelf registration statement with the SEC to permit the public resale of all registrable securities covered by the applicable Registration Rights Agreement within 18 months of the date of the agreement and to cause such shelf registration statement to be declared effective no later than two years after the date of the agreement. The Registration Rights Agreements include piggyback rights for the applicable holders, which provide that, if the Company proposes to file certain registration statements or supplements to certain effective registration statements for the sale of shares of the Company’s common stock in an underwritten offering for its own account or that of another person or both, then the Company is required to offer the holders the opportunity to include in such underwritten offering such number of registrable securities as each such holder may request, subject to certain cutback rights if the Company has been advised by the managing underwriter that the inclusion of registrable securities for sale for the benefit of the holders will have an adverse effect on the price, timing or distribution of the shares of common stock in the underwritten offering. SN Comanche Manager, LLC Class A Preferred Unit Member– On March 1, 2017 (the “Effective Date”), pursuant to the Amended and Restated LLC Agreement (the “LLC Agreement”) of Gavilan Resources Holdco, LLC (“GRHL” or “Gavilan Holdco”), GRHL authorized and issued a total of 100 Class A Units (“Class A Units”) to SN Comanche Manager, a wholly owned unrestricted subsidiary of the Company. GRHL is the parent of Gavilan. SN Comanche Manager, as holder of the Class A Units, does not have voting rights under the LLC Agreement except with respect to amendments to the LLC Agreement that adversely affect the holders of Class A Units, approval of affiliate transactions, or as required by law. Twenty percent of the Class A Units vest on each of the first five anniversaries of the Effective Date. The holders of Class A Units are entitled to distributions from Available Cash (as defined in the LLC Agreement) subject to the provisions of the LLC Agreement. SN UnSub Preferred Unit Issuance— At the closing of the Comanche Acquisition, pursuant to the SPA and subject to the other terms and conditions provided therein, the GSO Funds purchased 485,000 preferred units of SN UnSub (“SN UnSub Preferred Units”) for $485,000,000 and Intrepid purchased 15,000 SN UnSub Preferred Units for $15,000,000. The applicable parties entered into an amended and restated partnership agreement of SN UnSub (the “Partnership Agreement”) and an amended and restated limited liability company agreement of SN UnSub General Partner (the “GP LLC Agreement”). Under the terms of the Partnership Agreement, holders of the SN UnSub Preferred Units are entitled to receive distributions of 10.0% per annum, payable quarterly in cash, unless a cash payment is then prohibited by certain of SN UnSub’s debt agreements, in which case such distribution will be deemed to have been paid in kind. SN UnSub may not make distributions on the SN UnSub common units until the preferred units are redeemed in full. The SN UnSub Preferred Units have priority over the common units, to the extent of the Base Return (as defined below), upon a liquidation, sale of all or substantially all assets, certain change of control and exit transactions. SN UnSub may, from time to time and subject to the conditions set forth in the Partnership Agreement and the SN UnSub Credit Agreement, redeem SN UnSub Preferred Units at a purchase price per unit sufficient to achieve the greater of (i) the amount required to cause the return on investment with respect to each such SN UnSub Preferred Unit to be equal to the product of (x) 1.5 multiplied by (y) the purchase price per unit and (ii) the amount required to cause the internal rate of return with respect to each SN UnSub Preferred Unit to be equal to 14.0%, in each case inclusive of previous distributions made in cash (the “Base Return”). Partners holding a majority of the SN UnSub Preferred Units will have the option to request SN UnSub to redeem all of the preferred units for the Base Return at any time following the seventh anniversary of issuance or upon the occurrence of certain change of control transactions, as further described in the Partnership Agreement. If (i) the SN UnSub Preferred Units are not timely redeemed by SN UnSub when required, (ii) SN UnSub fails, after March 1, 2018, to pay the holders of the SN UnSub Preferred Units a cash distribution in any two quarters, regardless of whether consecutive, and such failure is continuing, (iii) SN UnSub takes certain material actions without the consent of the holders of the SN UnSub Preferred Units, when required, (iv) certain events of default under SN UnSub and the Company’s debt agreements have occurred or (v) SN Maverick is removed as operator under the JDA under certain circumstances, then a controlled affiliate of GSO will be entitled to appoint a majority of the members of the board of directors of SN UnSub General Partner and may cause a sale of the assets or equity of SN UnSub in order to redeem the SN UnSub Preferred Units. The SN UnSub Preferred Units issued in March 2017 are accounted for as mezzanine equity in the consolidated balance sheet consisting of the following as of December 31, 2017 (in thousands): December 31, 2017 Mezzanine equity beginning balance $ — Private placement of SN UnSub Preferred Units 500,000 Discount (90,527) Accretion of discount 18,039 Dividends accrued (1) 41,667 Dividends paid (2) (41,667) Total mezzanine equity $ 427,512 (1) In accordance with the Partnership Agreement and SN UnSub Credit Agreement, cash distributions for the 10% dividend on the SN UnSub Preferred Units are prohibited through February 28, 2018, and thus, the dividends for the periods presented are deemed to have been paid in kind and accrued. (2) Dividends paid in 2017 represent tax distributions from available cash to holders of the SN UnSub Preferred Units. The Partnership Agreement provides that tax distributions shall be treated as advances of any amounts holders of the SN UnSub Preferred Units are entitled to receive, and shall be offset against any amounts holders of SN UnSub Preferred Units are entitled to receive. 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, 2017, 2016 and 2015 (in thousands, except per share amounts): Year Ended December 31, 2017 2016 2015 Net income (loss) $ 43,192 $ (141,486) $ (726,089) Less: Preferred stock dividends (15,948) (15,948) (16,008) Preferred unit dividends and distributions (44,259) — — Preferred unit amortization (18,039) — — Net loss allocable to participating securities (1)(2) — — — Net loss attributable to common stockholders $ (35,054) $ (157,434) $ (742,097) Weighted average number of unrestricted outstanding common shares used to calculate basic net loss per share 75,608 58,900 57,229 Dilutive shares (3)(4)(5) — — — Denominator for diluted loss per common share 75,608 58,900 57,229 Net loss per common share - basic and diluted $ (0.46) $ (2.67) $ (12.97) (1) The Company's restricted shares of common stock are participating securities. (2) For the years ended December 31, 2017, 2016 and 2015, 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, 2017 excludes 2,755,893 shares of weighted average restricted stock and 12,520,179 shares of common stock resulting from an assumed conversion of the Company's Series A Preferred Stock and Series B Preferred Stock and 100,000 contingently issuable shares from the calculation of the denominator for diluted loss per common share as these shares were anti-dilutive. (4) 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. (5) 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.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2017
Stock-Based Compensation
Stock-Based Compensation	Note 8. 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 our Board or Compensation Committee; provided, however, that shares 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 our Board or Compensation Committee in its discretion. The LTIP is administered by the Compensation Committee of the Board as appointed by our Board. Our Board may terminate or amend the LTIP at any time with respect to any shares for which a grant has not yet been made. Our 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 our 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. Forfeitures of restricted stock awards granted to non-employees are accounted for as they are incurred. During the year ended December 31, 2017, the Company issued 200,334 shares of restricted common stock pursuant to the LTIP to six 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 $6.32 per share (the closing sales price of the Company’s common stock on the grant date) and is being amortized over the vesting period. The Company also issued approximately 2.1 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. The majority of these shares of restricted common stock vest in equal annual amounts over a three-year period. 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 (referred to below as PARS) cliff vest 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. 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 on the PARS 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 using the straight-line method. During the year ended December 31, 2017, no shares of PARS were issued by the Company. 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 cliff vest 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, 2017, the Company issued approximately 2.2 million shares of Phantom Stock pursuant to the LTIP to certain employees of SOG (including the Company’s officers), with whom the Company has a Services Agreement. The majority of these shares of Phantom Stock vest in equal annual amounts over a three-year period. No PAPS were issued during the year ended December 31, 2017. 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. On March 1, 2017, the Company’s Chief Executive Officer, Executive Chairman of the Board, President, and Chief Operating Officer entered into a new form of agreement for use in equity awards pursuant to the LTIP, for 245,234 target shares of the Company’s common stock, 245,234 target shares of the Company’s common stock, 245,234 target shares of the Company’s common stock, and 81,745 target shares of the Company’s common stock, respectively. The new form of agreement is a performance phantom stock agreement payable in shares of common stock (the “Performance Phantom Stock Agreement”). The shares granted pursuant to the Performance Phantom Stock Agreement (the “Performance Awards”) will vest (if any) in equal annual increments over a five-year period ranging from 0% to 200% of the target shares granted based on the Company’s share price appreciation relative to the share price appreciation of the S&P Oil & Gas Exploration & Production Select Industry Index for each year in the five-year performance period beginning on January 1, 2017 and ending on December 31, 2021, subject to each officer’s continuous service with the Company through each vesting date. For the 2017 performance period applicable to these awards, 0% of the target shares will be awarded. The Performance Awards 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 Performance Awards are classified as equity within the Company’s balance sheet, as they are settled in shares of the Company’s common stock. The Performance Awards have graded-vesting features and as such, the compensation expense for the unvested awards is calculated using the graded-vesting method whereby the Company recognizes compensation expense over the requisite service period for each separately vesting tranche of the award as though they were, in substance, multiple awards. In addition, the estimated value of each tranche will be revalued at each period end and amortized over the vesting period. 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, 2017 2016 2015 Restricted stock awards, directors $ 6,726 $ 1,000 $ 917 Restricted stock awards, non-employees 15,455 23,961 13,914 Performance awards 728 — — Phantom Stock awards 17,389 12,129 — Total stock-based compensation expense $ 40,298 $ 37,090 $ 14,831 Based on the $5.31 per share closing price of the Company’s common stock on December 29, 2017, there was approximately $17.5 million of unrecognized compensation cost related to the non‑vested restricted shares outstanding. The cost is expected to be recognized over a weighted average period of approximately 2.13 years. Based on the $5.31 per share closing price of the Company’s common stock on December 31, 2017, there was approximately $0.6 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 3.29 years. Based on the $5.31 per share closing price of the Company’s common stock on December 31, 2017, there was approximately $11.8 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 2.54 years. Based on the estimated per share price of the Performance Awards on December 31, 2017, there was approximately $2.2 million of unrecognized compensation cost related to the Performance Awards. The cost is estimated to be recognized over a weighted average period of approximately 3.01 years. A summary of the status of the non‑vested restricted common shares and PARS as of December 31, 2017 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, 2016 6,891,261 $ 9.18 $ 63,262 Granted 2,138,674 11.08 23,697 Vested (4,022,495) 8.71 (35,036) Forfeited (110,712) 8.15 (902) Non-vested common stock at December 31, 2017 4,896,728 $ 10.42 $ 51,021 As of December 31, 2017, approximately 8.3 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 for the year ended December 31, 2017 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, 2016 4,012,413 $ 4.87 $ 19,540 Granted 2,163,240 11.07 23,947 Vested (2,533,534) 8.81 (22,320) Forfeited (53,475) 10.49 (561) Non-vested common stock at December 31, 2017 3,588,644 $ 5.74 $ 20,606

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Taxes
Income Taxes	Note 9. Income Taxes The components of the federal income tax provision for the years ended December 31, 2017, 2016 and 2015 are (in thousands): Year Ended December 31, 2017 2016 2015 Current expense (benefit) as a result of current operations $ (1,599) $ 1,825 $ 158 Deferred expense (benefit) as a result of current operations 257,358 (46,191) (254,560) Increase (Decrease) in valuation allowance (258,095) 46,191 254,560 Net income tax expense (benefit) $ (2,336) $ 1,825 $ 158 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 (5.7)% is summarized as follows (in thousands): Year Ended December 31, 2017 2016 2015 Income tax expense (benefit) at the federal statutory rate $ 14,300 $ (48,882) $ (254,077) Officers' compensation limitation 9,570 3,115 1,328 State taxes (net of federal benefit) 2,607 (232) (5,463) Non-deductible general and administrative expenses 841 743 309 Percentage depletion carryforward (86) (144) — Other (52) 39 — Minimum Tax Credit Recoverability (1,599) US Tax Reform - Impact to Deferreds 227,392 — — Differences between actual income taxes and amounts estimated in prior years 2,786 995 3,501 Income tax expense (benefit) 255,759 (44,366) (254,402) US Tax Reform - One-Time Valuation Allowance Change (227,392) — — Other Valuation Allowance Change (30,703) 46,191 254,560 Net income tax expense (benefit) $ (2,336) $ 1,825 $ 158 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, 2017 2016 Deferred tax assets (liabilities): Derivative assets (obligations) $ 9,536 $ 12,516 Depreciable, depletable property, plant and equipment (22,351) 138,120 Share-based compensation 936 12,408 Revenue recognition 3,593 7,077 Investments in joint ventures (22,561) 5,064 Other 321 (2,007) Federal net operating loss carryforward 364,922 420,302 State net operating loss carryforward 4,246 3,256 Deferred tax assets: 338,642 596,736 Valuation allowance (338,642) (596,736) Total Deferred tax assets $ — $ — As of December 31, 2017, the Company had NOLs of approximately $1,737.7 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, 2017. On the basis of this evaluation, as of December 31, 2017, a valuation allowance of approximately $338.6 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 2014. State statutes vary by jurisdiction. As of December 31, 2017, 2016 and 2015, the Company had no material uncertain tax positions. On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act (the “Tax Act”) that significantly reforms the Internal Revenue Code of 1986, as amended (the “Code”). Among the many provisions included in the Tax Act is a provision to reduce the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018. We recognized the income tax effects of the Tax Act in accordance with Staff Accounting Bulletin No. 118, which provides SEC staff guidance for the application of ASC Topic 740, Income Taxes. The guidance allows for a measurement period of up to one year after the enactment date to finalize the recording of the related tax impacts. As such, our 2017 financial results reflect the provisional income tax effects of the Tax Act for which the accounting under ASC Topic 740 is incomplete, but a reasonable estimate could be determined. We did not identify any items for which the income tax effects of the Tax Act could not be reasonably estimated as of December 31, 2017. As of December 31, 2017, we had deferred tax assets primarily related to our net operating loss carryforwards. Prior to the Tax Act, the value of these deferred tax assets was recorded at the previous income tax rate of 35%, which represented their expected future benefit to us. As a result of the Tax Act, the future benefit of these deferred tax assets was re-measured at the new income tax rate of 21% and we recorded an approximate $227.4 million provisional non-cash adjustment (exclusive of a valuation allowance) for the year ended December 31, 2017. We determined the effects of the rate change using our best estimate of temporary book-to-tax differences. Upon final analysis and remeasurement of our deferred tax balances, the adjustment we recorded during the fourth quarter of 2017 to reflect the change in corporate income tax rates may need to be adjusted in subsequent periods. We continue to assess the impact of the Tax Act on our business. Our provisional amounts may be adjusted due to changes in interpretations of the Tax Act, legislative action to address questions that arise because of the Tax Act, or changes in accounting standards for income taxes or related interpretations. Any updates or changes to provisional estimates will be reported in the reporting period in which any such adjustments are determined, which will be no later than the fourth quarter of 2018.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions
Related Party Transactions	Note 10. Related Party Transactions SOG, headquartered in Houston, Texas, is a privately owned full service oil and natural gas company engaged in the exploration and development of oil and natural gas primarily in the South Texas, Louisiana and onshore Gulf Coast areas on behalf of certain of its affiliates, including the Company, pursuant to existing management service agreements. The Company refers to SOG and its affiliates (but excluding the Company) collectively as the “Sanchez Group.” Mr. Eduardo A. Sanchez and Ms. Ana Lee Sanchez Jacobs, immediate family members of the Executive Chairman of the Board, our Chief Executive Officer and an Executive Vice President of the Company, collectively with such individuals, either directly or indirectly, own 100% the equity interests of SOG; these individuals, as well as Mr. Eduardo A. Sanchez and Ms. Ana Lee Sanchez Jacobs, are officers of SOG. In addition, Antonio R. Sanchez, Jr. is the sole member of the board of directors of SOG. The Company does not have any employees. On December 19, 2011 the Company 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 are allocated to the Company at a fixed rate that is reviewed at least annually 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 fixed rate as the SOG employee salaries. Expenses allocated to the Company for general and administrative expenses and oil and natural gas production expenses for the years ended December 31, 2017, 2016 and 2015 are as follows (in thousands): Year Ended December 31, 2017 2016 2015 Administrative fees $ 67,381 $ 40,901 $ 30,430 Third-party expenses 5,881 5,001 5,427 Total included in general and administrative expenses and oil and natural gas production expenses $ 73,262 $ 45,902 $ 35,857 As of December 31, 2017 and 2016, the Company had a net receivable from SOG and other members of the Sanchez Group of $4.5 million and a net receivable of $6.4 million, respectively, which is reflected as “Accounts receivable—related entities” in the consolidated balance sheets. The net receivable as of December 31, 2017 and 2016 consists primarily of advances paid related to leasehold and other costs paid to SOG. As of December 31, 2017 and 2016, the Company had a net payable to SNMP of approximately $9.8 million and $9.0 million, respectively, that consists primarily of the accrual for fees associated with the Gathering Agreement related to the Western Catarina Midstream Divestiture, which is reflected in the “Accrued Liabilities – Other” account on the consolidated balance sheets. On June 30, 2017, the Gathering Agreement was amended to, among other things, provide for an additional, incremental infrastructure fee payable to SNMP of $1.00 per barrel of water delivered by SNMP on or after April 1, 2017 through and including March 31, 2018, with no such fee being payable thereafter, and to eliminate certain late payment fees from SN Catarina to SNMP. On September 1, 2017, SN Catarina entered into an agreement with Seco Pipeline, LLC, (“Seco Pipeline”) a wholly owned subsidiary of SNMP, whereby Seco Pipeline transports certain quantities of natural gas on a firm basis for $0.22 per MMBtu delivered on or after September 1, 2017. This agreement had an initial term of one month that expired on September 30, 2017, but the agreement continues month-to-month thereafter unless terminated by either party. Antonio R. Sanchez, III, the son of Antonio R. Sanchez, Jr. and brother of Patricio D. Sanchez, is the Company’s Chief Executive Officer and is a member of the board of directors of both the Company and of the general partner of SNMP (“SNMP GP”). Patricio D. Sanchez, an Executive Vice President of the Company, is the President and Chief Operating Officer of SNMP GP and a director of SNMP GP. Eduardo A. Sanchez, the brother of Antonio R. Sanchez, III and Patricio D. Sanchez, and the son of Antonio R. Sanchez, Jr. is a director of SNMP GP. Antonio R. Sanchez, Jr., the Executive Chairman of the Board of the Company, Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez all directly or indirectly own certain equity interests in the Company, SNMP and SNMP GP. Antonio R. Sanchez, Jr., Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez beneficially own approximately 0.67%, 2.06%, 2.04% and 2.42%, respectively, of the SNMP common units outstanding as of December 31, 2017. Production Asset Transaction On November 22, 2016, we completed the Production Asset Transaction previously discussed with SNMP, which is a related party (see Note 4, “Acquisitions and Divestitures”). Carnero Processing Disposition On November 22, 2016, we sold our membership interests in Carnero Processing, LLC (“Carnero Processing”) to SNMP, which is a related party (see Note 17, “Investments”). SNMP Unit Acquisition On November 22, 2016, a subsidiary of the Company purchased 2,272,727 common units of SNMP, which is a related party, for $25.0 million in a private placement (see Note 17, “Investments”). SNMP Lease Option On October 6, 2016, the Company and SN Terminal, LLC (“SNT”), a wholly owned subsidiary of the Company, on the one hand, and SNMP, on the other hand, entered into a Purchase and Sale Agreement (the “Lease Option Purchase Agreement”) pursuant to which SNT sold and conveyed to SNMP an option to acquire a ground lease (the “Lease Option”) to which SNT is a party for a tract of land leased from the Calhoun Port Authority in Point Comfort, Texas. In addition, if the Company or any of its affiliates entered into an option to engage in the construction of or participation in a Project (as defined below) and/or received the benefit of an acreage dedication from an affiliate of the Company relating to a Project, then such option and/or acreage dedication would have also been assigned to SNMP, if SNMP exercised the Lease Option. SNMP would have paid SNT $1.00 if the Lease Option was exercised, along with $250,000 if SNMP or any other person affiliated with SNMP elected to construct, own or operate a marine crude storage terminal on or within five miles of the Port Comfort lease or participated as an investor in the same, within five miles thereof (a “Project”), or the Company or its affiliates conveyed an acreage dedication to or an option regarding a Project. On September 11, 2017, the Company, SNT and SNMP entered into an agreement that terminated the Lease Option. Carnero Gathering Disposition On July 5, 2016, we sold our membership interests in Carnero Gathering, LLC (“Carnero Gathering”) to SNMP, which is a related party (see Note 17, “Investments”). Palmetto Disposition On March 31, 2015, we completed the Palmetto Disposition previously discussed with a subsidiary of SNMP, which is a related party (see Note 4, “Acquisitions and Divestitures”). Western Catarina Midstream Divestiture On October 14, 2015, we completed the Western Catarina Midstream Divestiture previously discussed with SNMP, which is a related party (see Note 4, “Acquisitions and Divestitures”). SR Settlement On August 11, 2017, the Company, the plaintiffs and all named defendants entered into a Stipulation of Settlement (the “Stipulation”) reflecting the terms of the settlement of the derivative stockholder litigation entitled In re Sanchez Energy Derivative Litigation , Consolidated C.A. No. 9132-VCG in the Court of Chancery of the State of Delaware (the “Court”), relating to the Company’s August 2013 purchase of working interests in the TMS from Sanchez Resources. On November 6, 2017, the Stipulation was approved by the Court and became final on December 20, 2017, pursuant to which, among other things: (i) the defendants (or their insurance companies) made a payment to the Company of an aggregate of $11.75 million ($5.2 million, net of fees, expenses and other amounts); (ii) the sole member of Sanchez Resources transferred the equity of Sanchez Resources to us; (iii) Sanchez Resources transferred certain royalty interests in the TMS acreage held by Sanchez Resources to us, and (iv) Alan Jackson and Greg Colvin were removed from the Company’s compensation committee. Sanchez Resources and one of its subsidiaries is party to the SR Credit Agreement of which approximately $24.0 million is outstanding. See Note 6, “Debt” for additional discussion of the SR Credit Agreement. The credit facility is solely secured by substantially all of the assets of Sanchez Resources and/or its subsidiary, without recourse to SN or any of its other subsidiaries, consisting of approximately 12,500 net acres in the TMS. Proved oil and natural gas properties $ 17,719 Unproved properties 5,227 Other assets acquired 3,952 Fair value of assets acquired 26,898 Asset retirement obligations (2,902) Fair value of net assets acquired $ 23,996 Comanche Acquisition On March 1, 2017, we closed the Comanche Acquisition previously discussed and, in connection with the closing, entered into a number of transactions with Gavilan, GSO and the Blackstone Warrantholders, or their affiliates, which are related parties (see Note 4, “Acquisitions and Divestitures”), including (i) the SPA with an investment vehicle owned by the GSO Funds and a controlled affiliate of GSO, (ii) warrant agreements with the Blackstone Warrantholders, (iii) Registration Rights Agreements with the Blackstone Warrantholders and GSO, (iv) the Partnership Agreement with an entity controlled by an affiliate of GSO, and (v) the GP LLC Agreement with a controlled affiliate of GSO (see Note 7, “Stockholders’ and Mezzanine Equity”). In addition, in connection with the closing of the Comanche Acquisition, we also entered into (i) separate standstill and voting agreements (the “Standstill Agreements”) with the Blackstone Funds (as defined below) and the GSO Funds, respectively, (ii) an eight-year (subject to earlier termination as provided for therein) joint development agreement (the “JDA”) with Gavilan, (iii) a shareholders agreement (the “Shareholders Agreement”) with Gavilan Holdco, (iv) a management services agreement (the “Management Services Agreement”) with Gavilan Holdco and SN Comanche Manager, a wholly owned subsidiary of the Company, and (v) certain marketing agreements with Gavilan. Each Standstill Agreement (i) restricts the ability of each of Blackstone Capital Partners VII L.P. and Blackstone Energy Partners II L.P. (together, the “Blackstone Funds”) and the GSO Funds (and indirectly certain of their affiliates) to take certain actions relating to the acquisition of our securities or assets or participation in our management, (ii) contains a two year lock-up restricting dispositions of the Company’s common stock or the warrants to purchase the Company’s common stock, and (iii) contains an agreement to vote any voting securities of the Company in the same manner as recommended by our Board. Pursuant to the Shareholders Agreement, Gavilan Holdco has the right, but not the obligation, to appoint one observer representative to be present at all regularly scheduled meetings of the full board of directors of the Company. The JDA provides for the administration, operation and transfer of the jointly owned Comanche Assets, and further provides for the (i) establishment of an operating committee to control the timing, scope and budgeting of operations on the Comanche Assets (subject to certain exceptions) and (ii) designation of SN Maverick as operator of the Comanche Assets and certain other interests (subject to forfeiture in the event of certain default events); the JDA also provides for mechanics relating to division of assets and operatorship among the parties, contains restrictions on the indirect or direct transfer of the parties’ interests in the Comanche Assets, including certain tag-along rights and rights of first offer provisions, and provides Gavilan with certain drag-along rights in the event of certain sale transactions, subject to certain exceptions and potential alternative structures or asset divisions. Pursuant to the Management Services Agreement, the Manager serves as manager of Gavilan Holdco’s business and provides comprehensive general, administrative, business and financial services at a price equal to Manager’s actual cost of providing such services (including an “administrative fee” equal to 2% of SOG’s total G&A costs), continuing until the occurrence of one or more events giving Manager or Gavilan Holdco the right to terminate the agreement. At the closing of the Comanche Acquisition, Gavilan Holdco paid $1.0 million to Manager under the agreement. The Management Services Agreement provides that Manager may not bill more than $500,000 of G&A costs per month to Gavilan Holdco (subject to reasonable adjustments that are consistent with market terms as a result of an increase in actual G&A costs incurred, and based upon a reasonable allocation of such costs). We also entered into a back-to-back management arrangement between Manager and SOG, on substantially the same terms and conditions as the Management Services Agreement, pursuant to which Manager delegated to SOG, and SOG agreed to perform for and on behalf of Manager, Manager’s duties and obligations under such services agreement; Manager is required to remit amounts received directly from Gavilan Holdco to Manager, including the $1.0 million paid at closing to Manager, and to pay SOG the 2% administrative fee referred to above. In addition, we entered into a management services agreement between SOG and SN UnSub pursuant to which SOG serves as manager of SN UnSub’s oil and gas properties and provides comprehensive general, administrative, business and financial services at a price equal to SOG’s actual cost of providing such services (including an “administrative fee” equal to 2% of SOG’s total G&A costs), with an initial term expiring on March 1, 2024 (subject to earlier termination as provided therein), renewing automatically for additional one-year terms thereafter unless either SN UnSub or SOG delivers written notice to the other of its desire not to renew the term at least 180 days prior to such anniversary date. SOG may not bill G&A costs to SN UnSub in excess of $5 million per calendar year until March 1, 2019, or in excess of $10 million per calendar year thereafter. Pursuant to a crude oil production marketing agreement, a residue gas marketing agreement and a marketing agreement for NGLs between Gavilan and SN Maverick, Gavilan sells all of its production from the Comanche Assets to SN Maverick and SN Maverick purchases all such production from Gavilan, transports and sells such production and remits to Gavilan its proportionate share of the sale proceeds Pursuant to the LLC Agreement of GRHL, GRHL authorized and issued a total of 100 Class A Units to SN Comanche Manager. SN Comanche Manager, as holder of the Class A Units, does not have voting rights with respect to GRHL except regarding amendments to the LLC Agreement that adversely affect the holders of Class A Units, approval of affiliate transactions, or as required by law. Twenty percent of the Class A Units vest on each of the first five anniversaries of the effective date of March 1, 2017. The holders of Class A Units are entitled to distributions from Available Cash, as defined in and subject to the provisions of the LLC Agreement.

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments
Derivative Instruments	Note 11. Derivative Instruments To reduce the impact of fluctuations in the price of oil, natural gas and NGLs on the Company’s business and results of operations, and to protect the economics of property acquisitions at the time of execution, 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 or extend the notional quantity settlement period 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 Credit Agreement (as defined in Note 20, “Subsequent Events”), the SN UnSub Credit Agreement and the terms of SN UnSub’s organizational documents, or were governed by our prior revolving credit facility, as applicable, 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 participants. Any derivatives that are with (x) lenders, or affiliates of lenders, to our prior revolving credit facility or SN UnSub Credit Agreement, or (y) counterparties designated as secured with and under the Credit Agreement are, in each case, collateralized by the assets securing the applicable facility, and, therefore, do not currently require the posting of cash collateral. Any derivatives that are with (x) non-lender counterparties, as designated under the SN UnSub Credit Agreement, or (y) counterparties that are not designated as secured under the Credit Agreement are, in each case, unsecured and do not require the posting of cash or other collateral. It is never the Company’s intention to enter into derivative contracts for speculative trading purposes. In connection with the closing of the Comanche Acquisition, we hedged a portion of projected future production attributable to the SN Comanche Assets, using hedge transactions that are consistent with our current hedging strategy. All of our derivatives are accounted for as mark-to-market activities. Under ASC 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, 2017: 2018 2019 2020 Oil positions: Fixed-for-floating price swaps (NYMEX WTI): Hedged volume (Bbls) 8,121,124 3,149,000 381,000 Average price ($/Bbl) $ 52.45 $ 51.91 $ 53.52 Call swaptions (NYMEX WTI): Option volume (Bbls) - 730,000 - Average price ($/Bbl) $ - $ 55.00 $ - Natural gas positions: Fixed-for-floating price swaps (NYMEX Henry Hub): Hedged volume (MMBtu) 68,818,146 17,644,000 2,361,000 Average price ($/MMBtu) $ 3.04 $ 2.90 $ 2.82 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, 2017, 2016, and 2015 (in thousands): Year Ended December 31, 2017 2016 2015 Beginning fair value of commodity derivatives $ (35,014) $ 178,283 $ 123,316 Net gains (losses) on crude oil derivatives (48,966) (47,389) 170,592 Net gains (losses) on natural gas derivatives 42,764 (30,307) 26,843 Net settlements on derivative contracts: Crude oil (11,807) (135,491) (123,946) Natural gas (1,232) (24,657) (18,522) Net premiums on derivative contracts: Crude oil — 24,547 — Ending fair value of commodity derivatives $ (54,255) $ (35,014) $ 178,283 Embedded Derivatives In 2017, the Company has entered into contracts for the purchase of sand and coiled tubing that contain provisions that must be bifurcated from the contract and valued as derivatives. The embedded derivatives are valued using a Monte Carlo model which utilizes observable inputs, including the NYMEX WTI oil price and NYMEX Henry Hub natural gas price at various points in time. The Company has marked these derivatives to market as of December 31, 2017, and incurred an approximate $1.6 million loss for the year ended December 31, 2017 as a result. Any gains or losses related to embedded derivatives are recorded as a component of other income (expense) in the consolidated statement of operations. The following table sets forth a reconciliation of the changes in fair value of the Company’s embedded derivatives for the year ended December 31, 2017 (in thousands): December 31, 2017 Beginning fair value of embedded derivatives $ — Initial fair value of embedded derivatives — Loss on embedded derivatives (1,551) Ending fair value of embedded derivatives $ (1,551) Balance Sheet Presentation The Company nets derivative assets and liabilities by commodity for counterparties where legal right to such netting exists. Therefore, the Company’s derivatives are presented on a net basis as “Fair value of derivative instruments” on the condensed consolidated balance sheets. The following information summarizes the gross fair values of derivative instruments, presenting the impact of netting the derivative assets and liabilities on the Company’s condensed consolidated balance sheets (in thousands): December 31, 2017 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 $ 16,510 $ (80) $ 16,430 Long-term asset 2,100 (672) 1,428 Total asset $ 18,610 $ (752) $ 17,858 Offsetting Derivative Liabilities: Current liability $ 56,269 $ (80) $ 56,190 Long-term liability 18,145 (672) 17,474 Total liability $ 74,415 $ (752) $ 73,664 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 $ 844 $ (844) $ — Long-term asset 1,426 (1,426) — Total asset $ 2,270 $ (2,270) $ — Offsetting Derivative Liabilities: Current liability $ 32,622 $ (844) $ 31,778 Long-term liability 4,662 (1,426) 3,236 Total liability $ 37,284 $ (2,270) $ 35,014

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2017
Fair Value of Financial Instruments
Fair Value of Financial Instruments	Note 12. 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, 2017 and 2016 (in thousands): As of December 31, 2017 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 $ 49,071 $ — $ — $ 49,071 Equity investment: Investment in SNMP 25,227 — — 25,227 Investment in Lonestar 5,955 — — 5,955 Oil derivative instruments: Swaps — (66,204) — (66,204) Call Swaptions — (3,431) — (3,431) Gas derivative instruments: Swaps — 15,380 — 15,380 Embedded derivative instruments: Sand and coiled tubing contracts — (1,551) — (1,551) Total $ 80,253 $ (55,806) $ — $ 24,447 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 $ 443,648 $ — $ — $ 443,648 Equity investment: Investment in SNMP 26,818 — — 26,818 Oil derivative instruments: Swaps — (8,291) — (8,291) Enhanced Swaps — — — — Three-way collars — — — — Collars — (572) — (572) Puts — — — — Gas derivative instruments: Swaps — (26,151) — (26,151) Total $ 470,466 $ (35,014) $ — $ 435,452 Financial Instruments: The Level 1 instruments presented in the tables above consist of money market funds and time deposits included in cash and cash equivalents on the Company’s consolidated balance sheets as of December 31, 2017 and 2016. The Company’s money market funds and time deposits represent cash equivalents backed by the assets of high‑quality banks and financial institutions. The Company identified the money market funds and time deposits 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 SNMP as further discussed in Note 17, “Investments.” The investment in SNMP is being accounting for under the fair value option, included in investments on the Company’s balance sheet as of December 31, 2017. The Company identified the common units in SNMP as a Level 1 instruments due to the fact that SNMP is a publicly traded company on the NYSE American with daily quoted prices that can be easily obtained. The Level 1 instruments also include the Company’s investment in the common shares of Lonestar as further discussed in Note 17, “Investments.” The investment in the Lonestar common shares is being accounted for at fair value and included in investments on the Company’s balance sheet as of December 31, 2017. The Company identified the Lonestar common shares as Level 1 instruments due to the fact that Lonestar is a publicly traded company on the Nasdaq Global Market exchange, with daily quoted prices that can be readily obtained. The Company’s derivative instruments consist of swaps, call swaptions, and collars as of December 31, 2017 and 2016. 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 observable inputs and they are classified as Level 2. Call swaption derivatives have inputs which are observable, either directly or indirectly, using market data. As of December 31, 2017, the Company believes that substantially all of the inputs required to calculate the fair value of swaps, call swaptions, and collars 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. As of December 31, 2016, the Company believed that substantially all of the inputs required to calculate the fair value of swaps 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, 2017 or December 31, 2016. Embedded Derivatives : The Company consummated contracts for the purchase of sand and coiled tubing that contain provisions that must be bifurcated from the contract and valued as a derivative. The embedded derivatives are valued using a Monte Carlo model which utilizes observable inputs, including the NYMEX WTI oil price and the NYMEX Henry Hub natural gas price at various points in time. The Company believes that substantially all of the inputs required to calculate the embedded derivatives 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 inputs. The Company has marked these derivatives to market as of December 31, 2017, and incurred an approximate $1.6 million loss as a result. The loss is the result of the decrease in fair value of the embedded derivatives due to the forecasted increase in product costs per terms of the contracts based on an increase in future forecasted oil and natural gas commodity prices. The fair value of the Company’s embedded derivatives classified as Level 2 as of December 31, 2017 was $1.6 million. Changes in the inputs will impact the fair value measurement of the Company's embedded derivative contracts. 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, 2017 2016 2015 Beginning balance $ — $ — $ 75,523 Total gains (losses) included in earnings — — 418 Net settlements on derivative contracts (1) — — (14,277) Derivative contracts transferred to Level 2 — — (61,664) Ending balance $ — $ — $ — Gains (losses) included in earnings related to derivatives still held as of December 31, 2017, 2016, and 2015 $ — $ — $ (940) (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 allocation for the Comanche Acquisition is presented in Note 4, “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 13, “Asset Retirement Obligations.” As previously stated, the Company follows the provisions of ASC 820‑10 for nonfinancial assets and liabilities measured at fair value on a non‑recurring basis. The fair value measurements of assets acquired and liabilities assumed in the SR legal settlement 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. The allocation of fair value to the assets and liabilities assumed as part of the SR legal settlement is presented in Note 10, “Related Party Transactions.” Liabilities assumed include asset retirement obligations existing and short-term debt held by Sanchez Resources at the date of transfer. 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. Additional discussion of the SR legal settlement can be found in Note 10, “Related Party Transactions.” A reconciliation of the beginning and ending balances of the Company’s asset retirement obligations is presented in Note 13, “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, 2017. 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 7, ‘‘Stockholders’ and Mezzanine Equity.’’ The Company did not record a proved property impairment during the year ended December 31, 2017. For the year ended December 31, 2016, the Company recorded a proved property impairment of $3.7 million to impair the value of our proved oil and natural gas properties in the TMS. The carrying values of the impaired proved properties were reduced to a fair value of $3.3 million, estimated using inputs characteristic of a Level 3 fair value measurement. Fair Value of Other Financial Instruments The carrying amounts of our oil and natural gas receivables, accounts payable and accrued liabilities approximate fair value due to their highly liquid nature. 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 $567.0 million as of December 31, 2017, and was calculated using quoted market prices based on trades of such debt as of that date. The registered 6.125% Notes are traded in an active market, and as such, are classified as Level 1 financial instruments. The estimated fair value of the 6.125% Notes was $974.6 million as of December 31, 2017 and was calculated using quoted market prices based on trades of such debt as of that date .

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligations
Asset Retirement Obligations	Note 13. 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, 2017 and 2016 (in thousands) were as follows: As of December 31, 2017 2016 Abandonment liability as of January 1, $ 25,087 $ 25,907 Liabilities incurred during period 4,968 1,492 Acquisitions 8,289 219 Divestitures (3,538) (4,433) Revisions (1,343) (172) Accretion expense 2,635 2,074 Abandonment liability as of December 31, $ 36,098 $ 25,087

Accrued Liabilities and Other C

Accrued Liabilities and Other Current Liabilities	12 Months Ended
	Dec. 31, 2017
Accrued Liabilities and Other Current Liabilities.
Accrued Liabilities and Other Current Liabilities	Note 14. Accrued Liabilities and Other Current Liabilities The following information summarizes accrued liabilities as of December 31, 2017 and 2016 (in thousands): As of December 31, 2017 2016 Capital expenditures $ 85,340 $ 35,154 Other: General and administrative costs 8,855 14,738 Production taxes 5,084 2,396 Ad valorem taxes 84 2,756 Lease operating expenses 32,152 23,942 Interest payable 34,632 34,266 Preferred stock dividends and other 3,987 4,360 Total accrued liabilities $ 170,134 $ 117,612 The following information summarizes the other payables as of December 31, 2017 and 2016 (in thousands): December 31, 2017 2016 Revenue payable $ 75,832 $ 2,124 Production tax payable 2,774 — Other 3,364 127 Total other payables $ 81,970 $ 2,251 The following information summarizes the other current liabilities as of December 31, 2017 and 2016 (in thousands): December 31, 2017 2016 Operated prepayment liability $ 88,999 $ — Deferred gain on Western Catarina Midstream Divestiture - short term 23,720 23,720 Phantom compensation payable - short term 2,525 7,388 Total other current liabilities $ 115,244 $ 31,108

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies
Commitments and Contingencies	Note 15. Commitments and Contingencies Litigation On December 4, 2013, and December 16, 2013, three derivative actions were filed in the Court 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 Acquisition I, LLC (“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, which was granted by the Court on November 25, 2014. On October 2, 2015, the Delaware Supreme Court reversed the motions to dismiss and remanded the case to the Court for further proceedings. A mediation in connection with the matter was held on July 7, 2016. A second mediation in connection with the matter was held on June 13, 2017. On August 11, 2017, the Company, the plaintiffs and all named defendants entered into the Stipulation reflecting the terms of the settlement of the Delaware Derivative Action. While the defendants continue to deny each of the plaintiffs’ claims and expressly deny any fault, wrongdoing or liability, the defendants agreed to the settlement solely to resolve the disputes, to avoid the costs and risks of further litigation and to avoid further distraction to the Company’s management. The litigation was settled, subject to the approval of the Court and in consideration of, among other things, the following: (i) a payment to the Company of an aggregate of $11.75 million ($5.2 million, net of fees, expenses and other amounts), (ii) the transfer of the equity of Sanchez Resources and certain related royalty interests in any TMS acreage to the Company, and (iii) the removal of Alan Jackson and Greg Colvin from the Company’s compensation committee. The Stipulation was filed with the Court on August 14, 2017, and a hearing on the settlement was held on November 6, 2017 in the Court. The Court approved the Stipulation and dismissed the Consolidated Derivative Actions with prejudice on November 6, 2017. The terms of the Stipulation became final on December 20, 2017. See Note 10, “Related Party Transactions.” 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. The action was dismissed on November 17, 2017. 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. Catarina Drilling Obligation In connection with the Catarina Acquisition, the undeveloped acreage we acquired is 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 drilling period on a well-for-well basis. The lease also creates 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. Comanche Drilling Obligation In connection with the Comanche Acquisition, we, through our subsidiaries, SN Maverick and SN UnSub, and Gavilan, entered into a development agreement with Anadarko. The development agreement requires us to complete and equip 60 wells in each annual period commencing on September 1, 2017 and continuing thereafter until September 1, 2022. The development agreement permits up to 30 wells completed and equipped in excess of the annual 60 well requirement to be carried over to satisfy part of the 60 well requirement in subsequent annual periods on a well-for-well basis. The development agreement contains a parent guarantee of the performance of SN Maverick and SN UnSub. I f we fail to complete and equip the required number of wells in a given year (after applying any qualifying additional wells from previous years), we and Gavilan must pay Anadarko E&P Onshore, LLC a default fee of $0.2 million for each well we do not timely complete and equip. 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, 2017, the Company had $185.7 million in lease payment obligations that satisfy operating lease criteria. These obligations include: (i) $99.6 million in payments due with respect to firm commitment of oil and natural gas volumes under the Gathering Agreement relating to the Western Catarina Midstream Divestiture that commenced on October 14, 2015 and continues until October 13, 2020, (ii) $81.1 million for a corporate office lease that commenced in the fourth quarter of 2014 and has an expiration date in December 2025, and (iii) $5.0 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. Volume Commitments As is common in our industry, the Company is party to certain oil and natural gas gathering and transportation and natural gas processing agreements that obligate us to deliver a specified volume of production over a defined time horizon. If not fulfilled, the Company is subject to deficiency payments. As of December 31, 2017, the Company had approximately $561.5 million in future commitments related to oil and natural gas gathering and transportation agreements ($222.3 million for 2018 through 2020, $175.6 million from 2021 through 2023, and $163.6 million under commitments expiring after December 31, 2023, in the aggregate) and approximately $179.5 million in future commitments related to natural gas processing agreements ($85.9 million for 2018 through 2020, $31.6 million from 2021 through 2023, and $62.0 expiring after December 31, 2023) that are not recorded in the accompanying consolidated balance sheets. For the year ended December 31, 2017, the Company incurred expenses related to deficiency fees of approximately $4.8 million that are reported on the consolidated statements of operations in the "Oil and natural gas production expenses" line item. We do not anticipate that any future deficiency payments under these contracts would be material, and expect to fulfill these obligations in the future based on the applicable anticipated development plan.

Subsidiary Guarantors

Subsidiary Guarantors	12 Months Ended
	Dec. 31, 2017
Subsidiary Guarantors
Subsidiary Guarantors	Note 16. Subsidiary Guarantors The Company filed registration statements on Form S‑3 with the SEC, which became effective January 14, 2013, 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, 2017, 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, 2017, 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, 2017, 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’s 7.75% Notes and 6.125% Notes are guaranteed by all of the Company’s subsidiaries, except for SN UR Holdings, LLC, SN Services, LLC, SNT, SN Midstream, Manager, SN UnSub General Partner, SN UnSub Holdings, SN UnSub, SN Capital, LLC, Sanchez Resources LLC, SR, SR Acquisition III, LLC and SR TMS, LLC which are unrestricted subsidiaries of the Company. 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 19, “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, except as noted below. SN UnSub’s and SN UnSub General Partner’s ability to distribute funds to the Company or its subsidiaries by dividend or loan is restricted by (i) the restrictive or negative covenants in the SN UnSub Credit Agreement, (ii) the terms of the SN UnSub Preferred Units and (iii) the consent or approval rights of the GSO Funds (or their representatives or affiliates) under the Partnership Agreement and the GP LLC Agreement, as the case may be (see “Note 6. Debt—SN UnSub Credit Agreement” and “Note 7. Stockholders’ and Mezzanine Equity—SN UnSub Preferred Units Issuance”). SN UnSub and SN UnSub General Partner are separate entities apart from their respective security holders and affiliates and the assets and credit of SN UnSub and SN UnSub General Partner are not available to satisfy the debts and other obligations of such security holders and affiliates or any other person or entity.

Investments

Investments	12 Months Ended
	Dec. 31, 2017
Investments
Investments	Note 17. Investments On June 15, 2017, the Company received 1,500,000 shares of Lonestar’s Series B Convertible Preferred Stock as part of the consideration for the Marquis Disposition. The Series B Convertible Preferred Stock converted into Lonestar Class A Common Stock on November 3, 2017. As of December 31, 2017, this ownership represents approximately 6.1% of Lonestar’s outstanding shares of common stock. The investment in Lonestar accounted for by the Company as investments in equity securities measured at fair value in the consolidated balance sheets at the end of each reporting period. The Company recorded losses related to the investment in Lonestar for the year ended December 31, 2017 of less than $0.1 million. Any gains or losses related to the investment in Lonestar are recorded as a component of other income (expense) in the consolidated statement of operations. On June 14, 2017, SN Catarina, LLC (“SN Catarina”), a wholly owned subsidiary of the Company, completed the sale of its 10% undivided interest in the Silver Oak II Gas Processing Facility in Bee County, Texas (the “SOII Facility”) to a subsidiary of Targa Resources Corp. (“Targa”) with an effective date of June 1, 2017 for $12.5 million of cash (the “SOII Disposition”). Prior to the SOII Disposition, the Company had invested $12.5 million in the SOII Facility. No gain or loss was recorded on the SOII Disposition. The Company recorded earnings of approximately $779 thousand from its equity interest in the SOII Facility for the period from March 1, 2017 through June 1, 2017, the effective date of the transaction. On March 1, 2017, pursuant to the LLC Agreement of GRHL, GRHL authorized and issued a total of 100 Class A Units to SN Comanche Manager, a wholly owned unrestricted subsidiary of the Company. GRHL is the parent of Gavilan. SN Comanche Manager, as holder of the Class A Units, does not have voting rights with respect to GRHL except regarding amendments to the LLC Agreement that adversely affect the holders of Class A Units, approval of affiliate transactions, or as required by law. Twenty percent of the Class A Units vest on each of the first five anniversaries of the Effective Date. The Class A Units are entitled to distributions from Available Cash, as defined in and subject to the provisions of the LLC Agreement. The Company accounts for the investment in GRHL as a cost method investment. As of December 31, 2017, the carrying value of the investment in GRHL was $7.3 million, based on the estimated fair value as of March 1, 2017. In general, the fair value of a cost method investment is not evaluated unless circumstances are present that may have an adverse effect on the fair value. The Company has not identified any such circumstances as of December 31, 2017. The Company did not record any earnings from its ownership of the Class A Units for the period from January 1, 2017 through December 31, 2017. On November 22, 2016, a subsidiary of the Company purchased 2,272,727 common units of SNMP for $25.0 million in a private placement. As of December 31, 2017, this ownership represents approximately 15.2% of SNMP’s outstanding common units. Rather than accounting for the investment under the equity method, the Company elected the fair value option to account for its interest in SNMP. The Company records the equity investment in SNMP at fair value at the end of each reporting period. Any gains or losses and dividend income related to the investment in SNMP are recorded as a component of other income (expense) in the consolidated statement of operations. The Company recorded losses related to the investment in SNMP for the twelve months ended December 31, 2017 of approximately $1.6 million. On November 22, 2016, SN Midstream sold its membership interests in Carnero Processing to SNMP for an initial payment of $55.5 million and the assumption by SNMP 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 venture 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 was to be amortized over the term of this firm gas processing agreement according to volumes processed through the Carnero Processing facility, however, upon adoption of ASC 606, this deferred gain will be reversed and opening retained earnings will be adjusted as of January 1, 2018. On July 5, 2016, SN Midstream sold its membership interests in Carnero Gathering to SNMP for an initial payment of approximately $37.0 million and the assumption by SNMP 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, SNMP is required to pay SN Midstream a monthly “earnout” based on gas received at Carnero Gathering’s Raptor Gas Processing Facility receipt points from SN Catarina and gas delivered and processed at the Raptor Gas Processing Facility 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 was to be amortized over the term of this firm gas gathering agreement according to volumes processed through the Carnero Processing facility, however, upon adoption of ASC 606, this deferred gain will be reversed and opening retained earnings will be adjusted as of January 1, 2018. Additionally, the adoption will result in the “earnout” being considered a derivative asset that will be revalued quarterly. 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 owned 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 would process a firm quantity, 125,000 Mcf/d, until the in-service date of Carnero Processing’s Raptor Gas Processing Facility. The Company accounted 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.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2017
Variable Interest Entities
Variable Interest Entities	Note 18. 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 previously in Note 17, “Investments,” pursuant to the LLC Agreement of GRHL, GRHL authorized and issued a total of 100 Class A Units to SN Comanche Manager, a wholly owned unrestricted subsidiary of the Company. Although the Company did not pay any cash for the Class A Units, the Company’s investment in GRHL represents a VIE that could expose the Company to losses limited to the estimated fair value of the investment. The carrying amounts of the investment in GRHL and the Company’s maximum exposure to loss as of December 31, 2017, was approximately $7.3 million. The Company did not record any earnings from its ownership of the Class A Units for the period from March 1, 2017 through December 31, 2017. The Company determined that Blackstone is the primary beneficiary of the VIE as the Company has no significant voting rights in GRHL under the LLC Agreement and no power over decisions related to the business activities of GRHL, other than operation of the properties. As noted previously in Note 17, “Investments,” the Company, via SN Catarina, purchased from a subsidiary of Targa a 10% undivided interest in the SOII Facility in 2015. The Company determined that ownership in the SOII Facility is 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. On June 14, 2017, SN Catarina completed the SOII Disposition for $12.5 million in cash. Prior to the SOII Disposition, 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 had previously accounted 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. Prior to the sale, we included the VIE in the “Other Assets - Investments” long-term asset line on the balance sheet. As noted previously in Note 17, “Investments,” in November 2016, the Company purchased common units of SNMP 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 SNMP. The Company’s investment in SNMP 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 SNMP and the Company’s maximum exposure to loss as of December 31, 2017, was approximately $25.2 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, 2017 and December 31, 2016 (in thousands): December 31, 2017 2016 Beginning Balance $ 39,656 $ 37,527 Investment in GRHL 7,280 — Earnings on (distributions from) equity investments (311) 311 Gain (Loss) from change in fair value of investment in SNMP (1,591) 1,818 Sale of investments (12,527) — Equity in equity investments $ 32,507 $ 39,656 December 31, 2017 2016 Equity in equity investments $ 32,507 $ 39,656 Guarantees of capital investments — — Maximum exposure to loss $ 32,507 $ 39,656

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2017
Condensed Consolidating Financial Information
Condensed Consolidating Financial Information	Note 19. 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. A summary of the condensed consolidated guarantor balance sheets for the periods ended December 31, 2017 and December 31, 2016 (in thousands) is presented below: December 31, 2017 Assets Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total current assets $ 447,984 $ 98,758 $ 117,031 $ (312,975) $ 350,798 Total oil and natural gas properties, net 3,987 1,275,153 748,319 - 2,027,459 Investment in subsidiaries 1,081,692 - (7,280) (1,074,412) - Other assets 25,451 4,415 62,512 - 92,378 Total Assets $ 1,559,114 $ 1,378,326 $ 920,582 $ (1,387,387) $ 2,470,635 Liabilities and Shareholders' Equity Current liabilities $ 212,026 $ 312,531 $ 250,946 $ (312,975) $ 462,528 Long-term liabilities 1,827,072 26,787 195,876 - 2,049,735 Mezzanine equity - - 427,512 - 427,512 Total shareholders' equity (deficit) (479,984) 1,039,008 46,248 (1,074,412) (469,140) Total Liabilities and Shareholders' Equity (deficit) $ 1,559,114 $ 1,378,326 $ 920,582 $ (1,387,387) $ 2,470,635 December 31, 2016 Assets Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total current assets $ 428,384 $ 123,380 $ 158,589 $ (147,548) $ 562,805 Total oil and natural gas properties, net - 704,519 - - 704,519 Investment in subsidiaries 734,704 - - (734,704) - Other assets 14,376 15,221 35,290 - 64,887 Total Assets $ 1,177,464 $ 843,120 $ 193,879 $ (882,252) $ 1,332,211 Liabilities and Shareholders' Equity Current liabilities $ 84,673 $ 78,344 $ 170,435 $ (147,548) $ 185,904 Long-term liabilities 1,788,930 25,086 16,273 - 1,830,289 Total shareholders' equity (deficit) (696,139) 739,690 7,171 (734,704) (683,982) Total Liabilities and Shareholders' Equity (deficit) $ 1,177,464 $ 843,120 $ 193,879 $ (882,252) $ 1,332,211 A summary of the condensed consolidated guarantor statements of operations for the periods ended December 31, 2017, December 31, 2016, and December 31, 2015 (in thousands) is presented below: Year Ended December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total revenues $ - $ 509,701 $ 230,630 $ - $ 740,331 Total operating costs and expenses (92,008) (387,614) (168,942) 680 (647,884) Other income (expense) (121,603) 75,837 (5,145) (680) (51,591) Income (loss) before income taxes (213,611) 197,924 56,543 - 40,856 Income tax benefit 2,336 - - - 2,336 Equity in income (loss) of subsidiaries 193,376 - - (193,376) - Net income (loss) $ (17,899) $ 197,924 $ 56,543 $ (193,376) $ 43,192 Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total revenues $ - $ 431,326 $ - $ - $ 431,326 Total operating costs and expenses (111,155) (367,541) (1,947) - (480,643) Other income (expense) (177,710) 82,948 4,418 - (90,344) Loss before income taxes (288,865) 146,733 2,471 - (139,661) Income tax expense (1,825) - - - (1,825) Equity in income (loss) of subsidiaries 33,730 - - (33,730) - Net income (loss) $ (256,960) $ 146,733 $ 2,471 $ (33,730) $ (141,486) Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total revenues $ - $ 475,779 $ - $ - $ 475,779 Total operating costs and expenses (75,096) (1,169,246) (1,692) - (1,246,034) Other income (expense) 44,726 (402) - - 44,324 Loss before income taxes (30,370) (693,869) (1,692) - (725,931) Income tax benefit (158) - - - (158) Equity in income (loss) of subsidiaries (1,416,657) - - 1,416,657 - Net income (loss) $ (1,447,185) $ (693,869) $ (1,692) $ 1,416,657 $ (726,089) A summary of the condensed consolidated guarantor statements of cash flows for the periods ended December 31, 2017, December 31, 2016, and December 31, 2015 (in thousands) is presented below: Year Ended December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ (148,259) $ 346,345 $ 94,003 $ - $ 292,089 Net cash provided by (used in) investing activities (266,135) (620,382) (760,909) 264,626 (1,382,800) Net cash provided by (used in) financing activities 157,390 303,083 577,381 (264,626) 773,228 Net increase (decrease) in cash and cash equivalents (257,004) 29,046 (89,525) - (317,483) Cash and cash equivalents, beginning of period 343,941 - 157,976 - 501,917 Cash and cash equivalents, end of period $ 86,937 $ 29,046 $ 68,451 $ - $ 184,434 Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ (36,741) $ 218,864 $ 631 $ - $ 182,754 Net cash provided by (used in) investing activities (46,602) (133,412) 55,571 16,209 (108,234) Net cash provided by (used in) financing activities (7,650) (85,452) 101,660 (16,209) (7,651) Net increase (decrease) in cash and cash equivalents (90,993) - 157,862 - 66,869 Cash and cash equivalents, beginning of period 434,934 - 114 - 435,048 Cash and cash equivalents, end of period $ 343,941 $ - $ 157,976 $ - $ 501,917 Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ (43,556) $ 315,516 $ (1,384) $ - $ 270,576 Net cash provided by (used in) investing activities 21,670 (247,202) (40,327) (26,490) (292,349) Net cash provided by (used in) financing activities (16,894) (68,314) 41,825 26,490 (16,893) Net increase (decrease) in cash and cash equivalents (38,780) - 114 - (38,666) Cash and cash equivalents, beginning of period 473,714 - - - 473,714 Cash and cash equivalents, end of period $ 434,934 $ - $ 114 $ - $ 435,048

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2017
Subsequent Events.
Subsequent Events	Note 20. Subsequent Events On January 2, 2018, dividends declared by our Board and accrued for the period from October 1 to December 31, 2017 for the Series A Preferred Stock and Series B Preferred Stock were paid in shares of the Company’s common stock. Indenture and 7.25% Senior Notes On February 14, 2018, the Company closed its private offering to eligible purchasers of $500 million in aggregate principal amount of 7.25% Senior Secured Notes. The 7.25% Senior Secured Notes were issued pursuant to an indenture, dated as of February 14, 2018 (the “Indenture”), among the Company, the guarantors party thereto, Delaware Trust Company, as trustee, and Royal Bank of Canada, as collateral trustee. The 7.25% Senior Secured Notes are guaranteed on a full, joint and several and senior secured basis by each of the Company’s existing domestic restricted subsidiaries and will be guaranteed by any future domestic restricted subsidiary, in each case, if and so long as such entity guarantees (or is an obligor The 7.25% Senior Secured Notes will mature on February 15, 2023, unless on October 10, 2022 either (i) some or all of the Company’s 6.125% Notes are still outstanding and have not been defeased or (ii) the Company or any of its restricted subsidiaries have any outstanding indebtedness that was used to purchase, repurchase, redeem, defease or otherwise acquire or retire for value the Company’s 6.125% Notes, and such indebtedness under this clause (ii) has a final maturity date that is earlier than May 17, 2023, in which case of either clause (i) or clause (ii), the 7.25% Senior Secured Notes will mature on October 14, 2022. The 7.25% Senior Secured Notes are redeemable, in whole or in part, on or after February 15, 2020 at the redemption prices described in the Indenture, together with accrued and unpaid interest. At any time prior to February 15, 2020, the Company may redeem the 7.25% Senior Secured 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 to the redemption date. In addition, the Company may redeem up to 35% of the 7.25% Senior Secured Notes prior to February 15, 2020 in an amount not greater than the net cash proceeds from one or more equity offerings at a redemption price equal to 107.25% of their principal amount, together with accrued and unpaid interest to the redemption date. If the Company sells certain of its assets or experiences specific kinds of changes of control, in certain circumstances it must offer to repurchase the 7.25% Senior Secured Notes. The Indenture restricts the Company’s ability, and the ability of the Company’s restricted subsidiaries, to: (i) incur additional indebtedness or issue preferred stock; (ii) pay dividends or make other distributions; (iii) make other restricted payments and investments; (iv) create liens; (v) incur restrictions on the ability of restricted subsidiaries to pay dividends or make certain other payments; (vi) sell assets, including capital stock of restricted subsidiaries; (vii) merge or consolidate with other entities; and (viii) enter into transactions with affiliates. These covenants The 7.25% Senior Secured Notes and the guarantees are secured on a first-priority basis, subject in priority only to permitted collateral liens and to the prior rights of the Credit Agreement and other “first-out” obligations under the CTA, in the following assets of the Company and the subsidiary guarantors (the “ Shared Collateral ”): (i) substantially all of the Company’s and its restricted subsidiaries’ oil and gas properties with proved reserves, (ii) 100% of the equity interest of the Company’s restricted subsidiaries and any of their future direct material restricted subsidiaries; and (iii) substantially all of the Company’s and any guarantor’s other material personal property, but in each case excluding, among other things, deposit accounts, oil and gas properties with no proved reserves, equity interests in SN UnSub and other existing and future subsidiaries designated as “unrestricted subsidiaries.” The Indenture provides that each of the following is an event of default: (i) default for 30 days in the payment when due of interest on the 7.25% Senior Secured Notes; (ii) default in payment when due (at stated maturity, upon redemption, acceleration or otherwise) of the principal of, or premium, if any, on, the 7.25% Senior Secured Notes; (iii) failure by the Company to comply with certain covenants relating to merger, consolidation, sale of all or substantially all assets or change of control; (iv) failure by the Company for 30 days after notice to comply with certain obligations to repurchase 7.25% Senior Secured Notes from the proceeds of certain asset sales; (v) failure by the Company for 180 days after notice to comply with its reporting obligations; (vi) failure by the Company for 60 days after notice to comply with any of the other agreements in the Indenture; (vii) there occurs with respect to any indebtedness having an outstanding principal amount of $40 million or more of the Company or any of its restricted subsidiaries (a) an event of default which results in such indebtedness being due and payable prior to its express maturity or (b) failure to make a principal, premium or interest payment when due and such defaulted payment is not made, waived or extended within the applicable grace period; (viii) failure by the Company or any of its restricted subsidiaries to pay final judgments aggregating in excess of $40 million, which judgments are not paid, discharged or stayed for a period of 60 days; (ix) certain events of bankruptcy or insolvency described in the Indenture with respect to the Company or any of the Company’s significant subsidiaries; (x) any guarantee ceases to be in full force and effect, other than Third On February 14, 2018, the Company, as borrower, and its existing restricted subsidiaries, as loan parties (the “Loan Parties”), entered into a revolving credit facility represented by a Third Amended and Restated Credit Agreement dated as of February 14, 2018 with Royal Bank of Canada as the administrative agent and collateral agent, RBC Capital Markets as the Arranger and the lenders party thereto, providing for a $25 million first-out senior secured working capital and letter of credit facility (the “Credit Agreement”), which amended and restated the Company’s existing credit facility in its entirety. Availability under the Credit Agreement is at all times subject to customary conditions but, except in limited circumstances, not to satisfaction of any collateral coverage ratio or other maintenance covenants. The Credit Agreement will mature on the earlier of (i) February 14, 2023 and (ii) the 91st day prior to the scheduled maturity of any “material indebtedness,” which is defined to include, without limitation, any indebtedness arising in connection with the Company’s 7.75% Notes, 6.125% Notes or the 7.25% Senior Secured Notes. The 7.75% Notes are scheduled to mature on June 15, 2021. The Company’s obligations under the Credit Agreement are guaranteed by all of the Company’s restricted subsidiaries that guarantee the 7.25% Senior Secured Notes and, pursuant to the CTA, are secured by priority liens on a first-out collateral proceeds payment priority basis in the Shared Collateral referred to above, subject only to permitted collateral liens. As a condition precedent to the issuance of loans or letters of credit under the Credit Agreement when there are no loans or letters of credit currently outstanding, the Company must demonstrate that the PDP Coverage Ratio is no less than 4.00 to 1.00. “PDP Coverage Ratio” means the then-applicable ratio of (i) (a) the Loan Parties’ proved developed producing properties’ PV-10 value, (b) the net mark-to-market value of commodity swaps in effect as of the date of calculation, plus (c) unrestricted cash on hand of the Loan Parties to (ii) the Credit Agreement commitment amount (initially $25,000,000). The Credit Agreement: (x) requires the PDP Coverage Ratio to be calculated (i) following any disposition by a Loan Party to a non-Loan Party of any proved developed producing properties that were included in the most recent reserve report delivered to the collateral agent that had a PV-10 value in excess of $10,000,000 in such reserve report, (ii) as of the end of each fiscal quarter of the Company if any loans or letters of credit under the Credit Agreement are outstanding at such time, and (iii) at the time of certain proposed restricted payments under the Credit Agreement; (y) to the extent at the time of any calculation specified in clause (x)(i) or (ii) the PDP Coverage Ratio is less than 4.00 to 1.00, requires a reduction in the commitment thereunder, together with any mandatory repayment of outstanding loans or cash collateralization of outstanding letters of credit to the extent necessary to increase the PDP Coverage Ratio to at least 4.00 to 1.00; and (z) prohibits any such restricted payments unless the PDP Coverage Ratio after giving effect to such restricted payment on a pro forma basis is at the time at least 4.00 to 1.00. At the Company’s election, interest on borrowings under the Credit Agreement may be calculated based on an alternate base rate (“ABR”) or an adjusted Eurodollar (LIBOR) rate, plus an applicable margin. The applicable margin is either 1.50% or 2.25% for ABR borrowings and either 2.50% or 3.25% for Eurodollar (LIBOR) borrowings and letters of credit, if any, depending on the Company’s utilization of the availability under the Credit Agreement. The Company is also required to pay a commitment fee of 0.50% per annum on any unused commitment amount. Interest on ABR borrowings and the commitment fee are generally payable quarterly. Interest on Eurodollar borrowings are generally payable at the end of the applicable interest period. The 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 and consolidate or merge. The Credit Agreement also provides for cross default between the Credit Agreement and the other material indebtedness of the Company and its restricted subsidiaries, in an aggregate principal amount in excess of $40 million. From time to time, the agents, arrangers, book runners and lenders under the 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. Marquis Disposition On November 7, 2017, Lonestar filed a registration statement on Form S-3 registering, among other things, the resale of the 1.5 million shares of Class A Common Stock held by the Company to comply with Lonestar’s obligations under a registration rights agreement with the Company. The registration statement was amended by Lonestar on February 14, 2018. On February 22, 2018, the registration statement was declared effective by the SEC.

Basis of Presentation and Sum30

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
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 August 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities,” which changes the recognition and presentation requirements of hedge accounting, including eliminating the requirement to separately measure and report hedge ineffectiveness, and presenting all items that affect earnings in the same income statement line item as the hedged item. The ASU also provides new alternatives for applying hedge accounting. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 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 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 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. The Company does not anticipate that ASU 2016-18 will have a material effect on its consolidated and condensed financial statements and related disclosures. 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. 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 adopted ASU 2016-09 as of the quarter ended March 31, 2017 on a retrospective basis. Adoption of this guidance affected the statement of cash flows as of December 31, 2016 as follows (in thousands): Increase in net cash provided by operating activities of approximately $1,906 Increase in net cash used in financing activities of approximately $1,906 Adoption of this guidance affected the statement of cash flows as of December 31, 2015 as follows (in thousands): Increase in net cash provided by operating activities of approximately $533 Increase in net cash used in financing activities of approximately $533 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 15, “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. 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 apply the modified retrospective approach. As part of the assessment, the Company formed an implementation work team, completed trainings on the new revenue recognition model and gathered our material revenue contracts covering current revenue streams for which we evaluated the impacts to the consolidated financial statements under the revised standards. In addition, the Company is evaluating the impacts of significant historical transactions under the new standard. As of December 31, 2017, the Company determined that the deferred gains recorded under the Carnero Gathering Disposition and Carnero Processing Disposition (defined below in Note 10, “Related Party Transactions”) will be de-recognized under the new standard and a derivative asset could be recorded for the value of the earnout provision owed to us by SNMP. Under the modified retrospective approach, the balance of accumulated deficit will be adjusted on January 1, 2018.
Change in Accounting Principle	Change in Accounting Principle During the fourth quarter of 2017, we changed our method of accounting for oil and gas exploration and development activities from full cost to the successful efforts method of accounting. Financial information for prior periods has been recast to reflect retrospective application of the successful efforts method, as prescribed by the Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 932 “Extractive Activities – Oil and Gas.” Although the full cost method of accounting for oil and gas exploration and development activities continues to be an acceptable alternative, the successful efforts method of accounting is the generally preferred method under U.S. GAAP and is more widely used in the industry such that the change improves the comparability of the Company’s financial statements to its peers. Changing to the successful efforts method of accounting is expected to provide greater transparency in results of our assets, enhance operating decision making and capital allocation processes and eliminate proved property impairments based on historical prices, which are not indicative of fair value of our assets. In general, under successful efforts, exploration expenditures such as exploratory dry holes, exploratory geological and geophysical costs, delay rentals, unproved impairments, and exploration overhead are charged against earnings as incurred, versus being capitalized under the full cost method of accounting. Successful efforts also provides for the assessment of potential property impairments under Accounting Standards Codification (ASC) 360 “Property, Plant, and Equipment” by comparing the net carrying value of oil and gas properties with associated projected undiscounted pre-tax future net cash flows. If the expected undiscounted pre-tax future net cash flows are lower than the unamortized capitalized costs, the capitalized cost is reduced to fair value. Under the full cost method of accounting, a write-down would be required if the net carrying value of oil and gas properties exceeded a full cost “ceiling,” using an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months. In addition, gains or losses, if applicable, are generally recognized on the dispositions of oil and gas property and equipment under the successful efforts method, as opposed to an adjustment to the net carrying value of the remaining assets under the full cost method.
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, embedded derivatives 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, 2017 and 2016, 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 successful efforts method of accounting. All direct costs and certain indirect costs associated with the acquisition, successful 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. Depreciation, depletion and amortization— Depreciation, depletion and amortization (“DD&A”) is provided using the units-of-production method based upon estimates of proved reserves of oil, natural gas and NGLs with production of the same converted to a common unit of measure based upon the relative energy content of the hydrocarbons. The Company groups its oil and gas properties with a common geological structure or stratigraphic condition (“common operating field”) in accordance with ASC 932 “Extractive Activities – Oil and Gas” for purposes of computing DD&A, assessing proved property impairments and accounting for asset dispositions. All capitalized costs of oil and natural gas properties are amortized using the units-of-production method based on proved reserves. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined. Once the assessment of unproved properties is complete and when major development projects are evaluated, the costs previously excluded from amortization are transferred to proved oil and natural gas properties amortization begins. All other properties are stated at historical cost, net of impairments, and are depreciated using the straight-line method over their respective useful lives. 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. In addition, considerable judgment is necessary 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 expense. Impairment of Oil and Natural Gas Properties —Capitalized costs (net of accumulated depreciation, depletion and amortization and impairment) of proved oil and natural gas properties are subjected to an impairment test when facts and circumstances indicate that their carrying value may not be recoverable. Net capitalized costs of proved oil and natural gas properties are compared to estimated undiscounted future net cash flows using management’s expectations of future oil and natural gas prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, using estimated discounted future net cash flows. The estimated future cash flows used to determine whether an impairment is present and the related fair value calculations are typically based on judgmental assessments of future production, commodity prices, operating expenses, and capital expenditures, utilizing the available information. The underlying commodity prices embedded in the estimated cash flows are the product of a process that begins with NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that are expected to impact the realizable price. We did not record a proved property impairment during the year ended December 31, 2017. During the year ended December 31, 2016, we recorded a proved property impairment of $3.7 million due to the decline of oil and natural gas prices during the first half of the year. We recorded impairment of $700.3 million to our proved oil and natural gas properties due to the significant decline in oil and natural gas prices during the year ended December 31, 2015. Unproved Properties —Costs associated with unproved properties and properties under development are excluded from the amortization base until the properties have been evaluated. Additionally, the costs associated with 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 amortization base when management determines that a project area has been evaluated through drilling operations or a thorough geologic evaluation. If the results of an assessment indicate that the properties are impaired, the carrying amount of the identified unproved properties are reduced to their fair value. We recorded impairment of $39.6 million to our unproved oil and natural gas properties for the year ended December 31, 2017 due to a write-down of our TMS acreage to fair value. We recorded impairments of $43.6 million and $23.7 million to our unproved oil and natural gas properties due to acreage abandonment from changes in development plan for the years ended December 31, 2016 and December 31, 2015, respectively. The costs of retaining unproved properties and the impairment of unsuccessful leases, are included in “Impairment expense” in the Company’s Consolidated Statements of Operations. Based on management’s review and current operating plans, approximately 4%, 4% and 2% of the unproved property balance at December 31, 2017 is expected to be developed and added to the amortization base during the years 2018, 2019 and 2020, respectively. The remaining balances in unproved properties relate to project areas that will not be thoroughly evaluated until after 2020, and represent leasehold interests that have expiration dates beginning in 2020 or leasehold interests that are currently held by production and/or continuous operations.
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, 2017, 2016 and 2015 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 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 2017, the Company capitalized approximately $18.7 million in costs associated with the incurrence of the SN UnSub Credit Agreement (as defined in “Note 6. Debt”). 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 6. Debt”). During 2015, the Company capitalized approximately $0.4 million in costs associated with amending our Second Amended and Restated Agreement. At December 31, 2017 and December 31, 2016, the Company had approximately $47.2 million and $35.0 million, respectively, of debt issuance costs (net of accumulated amortization of $34.5 million and $22.5. 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 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, 2017 and 2016.
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 and is included in “Depreciation, depletion, amortization and accretion” in the Company’s Consolidated Statements of Operations. 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 8, “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 Sales of oil, natural gas and NGLs 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 entitlement method of accounting is used for the sale of oil, natural gas and NGLs. 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, 2017, 2016 and 2015 there were no material oil and natural gas imbalances.
Sales to Major Customers	Sales to Major Customers The Company’s oil, natural gas and NGLs were sold to certain customers representing 10% or more of its total revenues for the years ended December 31, 2017, 2016 and 2015 as listed below: 2017 2016 2015 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 (the “Services Agreement”). See detailed discussion of the Company’s relationship with SOG in Note 10, “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, 2017 or 2016.
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 8, “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. In addition, they also reflect the effects of the warrants issued in connection with the Comanche Acquisition using the treasury stock method, if the effect is dilutive.

Basis of Presentation and Sum31

Basis of Presentation and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Basis of Presentation and Summary of Significant Accounting Policies
Schedule of entity's oil, NGL and natural gas production sold to certain customers representing 10% or more of its total revenues	2017 2016 2015 Customer A Customer B Customer C Customer D Customer E

Change in Accounting Principle

Change in Accounting Principle (Tables)	12 Months Ended
	Dec. 31, 2017
Change in Accounting Principle
Summary of change in accounting principle	Changes to the Consolidated Statement of Operations For the Year Ended December 31, 2017 Under Full Cost Changes As Reported Under Successful Efforts (In thousands, except per share data) Oil and natural gas production expenses $ 253,368 $ (8,907) $ 244,461 Exploration expenses — 5,755 5,755 Depreciation, depletion, amortization and accretion 199,087 (22,009) 177,078 Impairment of oil and natural gas properties — 39,574 39,574 Other income (expense) 7,351 3,751 11,102 Gain on disposal of assets 10,202 71,753 81,955 Income tax benefit (expense) 2,336 — 2,336 Net loss (17,899) 61,091 43,192 Net income allocable to participating securities — — — Net loss attributable to common stockholders $ (96,145) $ 61,091 $ (35,054) — Net loss per common share - basic and diluted $ (1.27) $ 0.81 $ (0.46) Changes to the Consolidated Statement of Operations For the Year Ended December 31, 2016 Under Full Cost Changes As Reported Under Successful Efforts (In thousands, except per share data) Oil and natural gas production expenses $ 164,567 $ (8,907) $ 155,660 Exploration expenses — 403 403 Depreciation, depletion, amortization and accretion 159,760 (12,275) 147,485 Impairment of oil and natural gas properties 169,046 (121,665) 47,381 Gain on disposal of assets 112,294 (26,972) 85,322 Income tax benefit (expense) (1,825) — (1,825) Net loss (256,958) 115,472 (141,486) Net income allocable to participating securities — — — Net loss attributable to common stockholders $ (272,906) $ 115,472 $ (157,434) — Net loss per common share - basic and diluted $ (4.63) $ 1.96 $ (2.67) Changes to the Consolidated Statement of Operations For the Year Ended December 31, 2015 Under Full Cost Changes As Reported Under Successful Efforts (In thousands, except per share data) Oil and natural gas production expenses 156,528 (1,856) 154,672 Exploration expenses — 1,982 1,982 Depreciation, depletion, amortization and accretion 344,572 (80,193) 264,379 Impairment of oil and natural gas properties 1,365,000 (641,029) 723,971 Gain on disposal of assets — — — Income tax benefit (expense) (7,600) 7,442 (158) Net loss (1,454,627) 728,538 (726,089) Net income allocable to participating securities — — — Net loss attributable to common stockholders $ (1,470,635) $ 728,538 $ (742,097) — Net loss per common share - basic and diluted $ (25.70) $ 12.73 $ (12.97) The following tables present the effects of the change to the successful efforts method in the statement of consolidated cash flows: Changes to the Consolidated Statement of Cash Flows For the Year Ended December 31, 2017 Under Full Cost Change As reported Under Successful Efforts (In thousands) Net loss $ (17,899) $ 61,091 $ 43,192 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 199,087 (22,009) 177,078 Impairment of oil and natural gas properties — 39,574 39,574 Gain on sale of oil and natural gas properties (10,202) (71,753) (81,955) Amortization of deferred gain on Catarina Midstream Sale (14,813) (8,907) (23,720) Deferred taxes (737) — (737) Net cash provided by operating activities 294,093 (2,004) 292,089 Payments for oil and natural gas properties (502,338) 2,004 (500,334) Net cash used in investing activities (1,384,804) 2,004 (1,382,800) Net cash provided by (used in) financing activities 773,228 — 773,228 Increase (decrease) in cash and cash equivalents (317,483) — (317,483) Cash and cash equivalents, beginning of period 501,917 — 501,917 Cash and cash equivalents, end of period $ 184,434 $ — $ 184,434 Changes to the Consolidated Statement of Cash Flows For the Year Ended December 31, 2016 Under Full Cost Change As reported Under Successful Efforts (In thousands) Net loss $ (256,958) $ 115,472 $ (141,486) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 159,760 (12,275) 147,485 Impairment of oil and natural gas properties 169,046 (121,665) 47,381 Gain on sale of oil and natural gas properties (112,294) 26,972 (85,322) Amortization of deferred gain on Catarina Midstream Sale (14,813) (8,907) (23,720) Deferred taxes — — — Net cash provided by operating activities 183,157 (403) 182,754 Payments for oil and natural gas properties (313,342) 403 (312,939) Net cash used in investing activities (108,637) 403 (108,234) Net cash provided by (used in) financing activities (7,651) — (7,651) Increase (decrease) in cash and cash equivalents 66,869 — 66,869 Cash and cash equivalents, beginning of period 435,048 — 435,048 Cash and cash equivalents, end of period $ 501,917 $ — $ 501,917 Changes to the Consolidated Statement of Cash Flows For the Year Ended December 31, 2015 Under Full Cost Change As reported Under Successful Efforts (In thousands) Net income (loss) $ (1,454,627) $ 728,538 $ (726,089) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion, amortization and accretion 344,572 (80,193) 264,379 Impairment of oil and natural gas properties 1,365,000 (641,029) 723,971 Amortization of deferred gain on Catarina Midstream Sale (3,086) (1,856) (4,942) Deferred Taxes 7,443 (7,442) 1 Net cash provided by operating activities 272,558 (1,982) 270,576 Payments for oil and natural gas properties (656,136) 1,982 (654,154) Net cash used in investing activities (294,331) 1,982 (292,349) Net cash provided by (used in) financing activities (16,893) — (16,893) Increase (decrease) in cash and cash equivalents (38,666) — (38,666) Cash and cash equivalents, beginning of period 473,714 — 473,714 Cash and cash equivalents, end of period $ 435,048 $ — $ 435,048 The following tables present the effects of the change to the successful efforts method in the consolidated balance sheet: Changes to Consolidated Balance Sheet December 31, 2017 Under Full Cost Changes As Reported Under Successful Efforts (In thousands) Oil and natural gas properties: Unproved oil and natural gas properties 398,212 393 398,605 Proved oil and natural gas properties 4,462,171 (1,331,764) 3,130,407 Total oil and natural gas properties 4,860,383 (1,331,371) 3,529,012 Less: Accumulated depreciation, depletion, amortization and impairment (2,931,039) 1,429,486 (1,501,553) Total oil and natural gas properties, net 1,929,344 98,115 2,027,459 Total assets $ 2,372,520 $ 98,115 $ 2,470,635 Current liabilities: Other 106,337 8,907 115,244 Total current liabilities 453,621 8,907 462,528 Other liabilities 49,520 15,960 65,480 Total liabilities 2,487,396 24,867 2,512,263 Accumulated deficit (1,905,404) 73,248 (1,832,156) Total stockholders' equity (deficit) (542,388) 73,248 (469,140) Total liabilities and stockholders' equity (deficit) $ 2,372,520 $ 98,115 $ 2,470,635 Changes to Consolidated Balance Sheet December 31, 2016 Under Full Cost Changes As Reported Under Successful Efforts (In thousands) Oil and natural gas properties: Unproved oil and natural gas properties 231,424 (6,401) 225,023 Proved oil and natural gas properties 3,164,115 (1,314,383) 1,849,732 Total oil and natural gas properties 3,395,539 (1,320,784) 2,074,755 Less: Accumulated depreciation, depletion, amortization and impairment (2,736,951) 1,366,715 (1,370,236) Total oil and natural gas properties, net 658,588 45,931 704,519 Total assets $ 1,286,280 $ 45,931 $ 1,332,211 Current liabilities: Other 22,201 8,907 31,108 Total current liabilities 176,997 8,907 185,904 Other liabilities 64,333 24,866 89,199 Total liabilities 1,982,420 33,773 2,016,193 Accumulated deficit (1,809,260) 12,158 (1,797,102) Total stockholders' equity (deficit) (696,140) 12,158 (683,982) Total liabilities and stockholders' equity (deficit) $ 1,286,280 $ 45,931 $ 1,332,211

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2017
Acquisitions and Divestitures
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 $ 781,789 Unproved properties 263,471 Other assets acquired 6,702 Fair value of assets acquired 1,051,962 Asset retirement obligations (8,289) Fair value of net assets acquired $ 1,043,673
Schedule of unaudited pro forma combined statements of operations	Year Ended December 31, 2017 2016 Revenues $ 784,360 $ 693,843 Net income (loss) attributable to common stockholders $ (6,458) $ (242,847) Net income (loss) per common share, basic and diluted $ (0.09) $ (3.38)
Schedule of revenue and revenues in excess of direct operating expenses	Direct operating expenses include lease operating expenses and production and ad valorem taxes (in thousands): Year Ended December 31, 2017 Revenues $ 255,282 Excess of revenues over direct operating expenses $ 138,046

Cash and Cash Equivalents (Tabl

Cash and Cash Equivalents (Tables)	12 Months Ended
	Dec. 31, 2017
Cash and Cash Equivalents
Schedule of cash and cash equivalents	As of December 31, 2017 and 2016, cash and cash equivalents consisted of the following (in thousands): As of December 31, 2017 2016 Cash at banks $ 135,363 $ 58,269 Money market funds 49,071 443,648 Total cash and cash equivalents $ 184,434 $ 501,917

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt
Schedule of long-term debt	Amount Outstanding (in thousands) as of December 31, December 31, Interest Rate Original Maturity Date 2017 2016 Short-Term Debt SR Credit Agreement (1)(2) Variable August 8, 2018 $ 23,996 $ — Total short-term debt $ 23,996 $ — Long-Term Debt Second Amended and Restated Credit Agreement Variable June 30, 2019 $ 50,000 $ — SN UnSub Credit Agreement (1) Variable March 1, 2022 175,500 — 7.75% Notes 7.75% June 15, 2021 600,000 600,000 4.59% Non-Recourse Subsidiary Term Loan (1) 4.59% August 31, 2022 4,164 — 6.125% Notes 6.125% January 15, 2023 1,150,000 1,150,000 1,979,664 1,750,000 Unamortized discount on Additional 7.75% Notes (3,126) (4,030) Unamortized premium on Additional 6.125% Notes 1,360 1,629 Unamortized debt issuance costs (47,215) (34,832) Total long-term debt $ 1,930,683 $ 1,712,767 (1) These debt instruments are Non-Recourse to the Company. (2) Bears a weighted-average interest rate of 5.122%.
Schedule of interest expense	The components of interest expense are (in thousands): Year Ended December 31, 2017 2016 2015 Interest on Senior Notes $ (116,938) $ (116,938) $ (116,938) Interest on SN UnSub Credit Agreement (7,639) — — Interest on SR Credit Agreement (105) — — Interest on Non-Recourse Subsidiary Term Loan (65) — — Interest expense and commitment fees on Second Amended and Restated Credit Agreement (2,135) (1,561) (1,229) Amortization of debt issuance costs (12,647) (7,840) (7,529) Amortization of discount on Additional 7.75% Notes (904) (904) (904) Amortization of premium on Additional 6.125% Notes 270 270 201 Total interest expense $ (140,163) $ (126,973) $ (126,399)

Stockholders' and Mezzanine E36

Stockholders' and Mezzanine Equity (Tables)	12 Months Ended
	Dec. 31, 2017
Stockholders' and Mezzanine Equity
Preferred Units accounted for as mezzanine equity	The SN UnSub Preferred Units issued in March 2017 are accounted for as mezzanine equity in the consolidated balance sheet consisting of the following as of December 31, 2017 (in thousands): December 31, 2017 Mezzanine equity beginning balance $ — Private placement of SN UnSub Preferred Units 500,000 Discount (90,527) Accretion of discount 18,039 Dividends accrued (1) 41,667 Dividends paid (2) (41,667) Total mezzanine equity $ 427,512 (1) In accordance with the Partnership Agreement and SN UnSub Credit Agreement, cash distributions for the 10% dividend on the SN UnSub Preferred Units are prohibited through February 28, 2018, and thus, the dividends for the periods presented are deemed to have been paid in kind and accrued. (2) Dividends paid in 2017 represent tax distributions from available cash to holders of the SN UnSub Preferred Units. The Partnership Agreement provides that tax distributions shall be treated as advances of any amounts holders of the SN UnSub Preferred Units are entitled to receive, and shall be offset against any amounts holders of SN UnSub Preferred Units are entitled to receive.
Schedule of computation of basic and diluted net 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, 2017, 2016 and 2015 (in thousands, except per share amounts): Year Ended December 31, 2017 2016 2015 Net income (loss) $ 43,192 $ (141,486) $ (726,089) Less: Preferred stock dividends (15,948) (15,948) (16,008) Preferred unit dividends and distributions (44,259) — — Preferred unit amortization (18,039) — — Net loss allocable to participating securities (1)(2) — — — Net loss attributable to common stockholders $ (35,054) $ (157,434) $ (742,097) Weighted average number of unrestricted outstanding common shares used to calculate basic net loss per share 75,608 58,900 57,229 Dilutive shares (3)(4)(5) — — — Denominator for diluted loss per common share 75,608 58,900 57,229 Net loss per common share - basic and diluted $ (0.46) $ (2.67) $ (12.97) (1) The Company's restricted shares of common stock are participating securities. (2) For the years ended December 31, 2017, 2016 and 2015, 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, 2017 excludes 2,755,893 shares of weighted average restricted stock and 12,520,179 shares of common stock resulting from an assumed conversion of the Company's Series A Preferred Stock and Series B Preferred Stock and 100,000 contingently issuable shares from the calculation of the denominator for diluted loss per common share as these shares were anti-dilutive. (4) 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. (5) 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.

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
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, 2017 2016 2015 Restricted stock awards, directors $ 6,726 $ 1,000 $ 917 Restricted stock awards, non-employees 15,455 23,961 13,914 Performance awards 728 — — Phantom Stock awards 17,389 12,129 — Total stock-based compensation expense $ 40,298 $ 37,090 $ 14,831
Restricted common shares and PARS
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
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, 2017 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, 2016 6,891,261 $ 9.18 $ 63,262 Granted 2,138,674 11.08 23,697 Vested (4,022,495) 8.71 (35,036) Forfeited (110,712) 8.15 (902) Non-vested common stock at December 31, 2017 4,896,728 $ 10.42 $ 51,021
Phantom Stock shares and PAPS
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Summary of the status of the non-vested shares	A summary of the status of the non‑vested Phantom Stock shares and PAPS for the year ended December 31, 2017 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, 2016 4,012,413 $ 4.87 $ 19,540 Granted 2,163,240 11.07 23,947 Vested (2,533,534) 8.81 (22,320) Forfeited (53,475) 10.49 (561) Non-vested common stock at December 31, 2017 3,588,644 $ 5.74 $ 20,606

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017, 2016 and 2015 are (in thousands): Year Ended December 31, 2017 2016 2015 Current expense (benefit) as a result of current operations $ (1,599) $ 1,825 $ 158 Deferred expense (benefit) as a result of current operations 257,358 (46,191) (254,560) Increase (Decrease) in valuation allowance (258,095) 46,191 254,560 Net income tax expense (benefit) $ (2,336) $ 1,825 $ 158
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 (5.7)% is summarized as follows (in thousands): Year Ended December 31, 2017 2016 2015 Income tax expense (benefit) at the federal statutory rate $ 14,300 $ (48,882) $ (254,077) Officers' compensation limitation 9,570 3,115 1,328 State taxes (net of federal benefit) 2,607 (232) (5,463) Non-deductible general and administrative expenses 841 743 309 Percentage depletion carryforward (86) (144) — Other (52) 39 — Minimum Tax Credit Recoverability (1,599) US Tax Reform - Impact to Deferreds 227,392 — — Differences between actual income taxes and amounts estimated in prior years 2,786 995 3,501 Income tax expense (benefit) 255,759 (44,366) (254,402) US Tax Reform - One-Time Valuation Allowance Change (227,392) — — Other Valuation Allowance Change (30,703) 46,191 254,560 Net income tax expense (benefit) $ (2,336) $ 1,825 $ 158
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, 2017 2016 Deferred tax assets (liabilities): Derivative assets (obligations) $ 9,536 $ 12,516 Depreciable, depletable property, plant and equipment (22,351) 138,120 Share-based compensation 936 12,408 Revenue recognition 3,593 7,077 Investments in joint ventures (22,561) 5,064 Other 321 (2,007) Federal net operating loss carryforward 364,922 420,302 State net operating loss carryforward 4,246 3,256 Deferred tax assets: 338,642 596,736 Valuation allowance (338,642) (596,736) Total Deferred tax assets $ — $ —

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2017
Schedule of expenses allocated to the Company for general and administrative expenses	Expenses allocated to the Company for general and administrative expenses and oil and natural gas production expenses for the years ended December 31, 2017, 2016 and 2015 are as follows (in thousands): Year Ended December 31, 2017 2016 2015 Administrative fees $ 67,381 $ 40,901 $ 30,430 Third-party expenses 5,881 5,001 5,427 Total included in general and administrative expenses and oil and natural gas production expenses $ 73,262 $ 45,902 $ 35,857
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 $ 781,789 Unproved properties 263,471 Other assets acquired 6,702 Fair value of assets acquired 1,051,962 Asset retirement obligations (8,289) Fair value of net assets acquired $ 1,043,673
SR | TMS
Schedule of total purchase price allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition	Proved oil and natural gas properties $ 17,719 Unproved properties 5,227 Other assets acquired 3,952 Fair value of assets acquired 26,898 Asset retirement obligations (2,902) Fair value of net assets acquired $ 23,996

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivatives Fair Value [Line Items]
Schedule of derivative positions	2018 2019 2020 Oil positions: Fixed-for-floating price swaps (NYMEX WTI): Hedged volume (Bbls) 8,121,124 3,149,000 381,000 Average price ($/Bbl) $ 52.45 $ 51.91 $ 53.52 Call swaptions (NYMEX WTI): Option volume (Bbls) - 730,000 - Average price ($/Bbl) $ - $ 55.00 $ - Natural gas positions: Fixed-for-floating price swaps (NYMEX Henry Hub): Hedged volume (MMBtu) 68,818,146 17,644,000 2,361,000 Average price ($/MMBtu) $ 3.04 $ 2.90 $ 2.82
Schedule of reconciliation of changes in fair value of 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, 2017, 2016, and 2015 (in thousands): Year Ended December 31, 2017 2016 2015 Beginning fair value of commodity derivatives $ (35,014) $ 178,283 $ 123,316 Net gains (losses) on crude oil derivatives (48,966) (47,389) 170,592 Net gains (losses) on natural gas derivatives 42,764 (30,307) 26,843 Net settlements on derivative contracts: Crude oil (11,807) (135,491) (123,946) Natural gas (1,232) (24,657) (18,522) Net premiums on derivative contracts: Crude oil — 24,547 — Ending fair value of commodity derivatives $ (54,255) $ (35,014) $ 178,283
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 netting the derivative assets and liabilities on the Company’s condensed consolidated balance sheets (in thousands): December 31, 2017 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 $ 16,510 $ (80) $ 16,430 Long-term asset 2,100 (672) 1,428 Total asset $ 18,610 $ (752) $ 17,858 Offsetting Derivative Liabilities: Current liability $ 56,269 $ (80) $ 56,190 Long-term liability 18,145 (672) 17,474 Total liability $ 74,415 $ (752) $ 73,664 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 $ 844 $ (844) $ — Long-term asset 1,426 (1,426) — Total asset $ 2,270 $ (2,270) $ — Offsetting Derivative Liabilities: Current liability $ 32,622 $ (844) $ 31,778 Long-term liability 4,662 (1,426) 3,236 Total liability $ 37,284 $ (2,270) $ 35,014
Embedded derivatives
Derivatives Fair Value [Line Items]
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 embedded derivatives for the year ended December 31, 2017 (in thousands): December 31, 2017 Beginning fair value of embedded derivatives $ — Initial fair value of embedded derivatives — Loss on embedded derivatives (1,551) Ending fair value of embedded derivatives $ (1,551)

Fair Value of Financial Instr41

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 and 2016 (in thousands): As of December 31, 2017 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 $ 49,071 $ — $ — $ 49,071 Equity investment: Investment in SNMP 25,227 — — 25,227 Investment in Lonestar 5,955 — — 5,955 Oil derivative instruments: Swaps — (66,204) — (66,204) Call Swaptions — (3,431) — (3,431) Gas derivative instruments: Swaps — 15,380 — 15,380 Embedded derivative instruments: Sand and coiled tubing contracts — (1,551) — (1,551) Total $ 80,253 $ (55,806) $ — $ 24,447 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 $ 443,648 $ — $ — $ 443,648 Equity investment: Investment in SNMP 26,818 — — 26,818 Oil derivative instruments: Swaps — (8,291) — (8,291) Enhanced Swaps — — — — Three-way collars — — — — Collars — (572) — (572) Puts — — — — Gas derivative instruments: Swaps — (26,151) — (26,151) Total $ 470,466 $ (35,014) $ — $ 435,452
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, 2017 2016 2015 Beginning balance $ — $ — $ 75,523 Total gains (losses) included in earnings — — 418 Net settlements on derivative contracts (1) — — (14,277) Derivative contracts transferred to Level 2 — — (61,664) Ending balance $ — $ — $ — Gains (losses) included in earnings related to derivatives still held as of December 31, 2017, 2016, and 2015 $ — $ — $ (940) 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, 2017
Asset Retirement Obligations
Schedule of changes in asset retirement obligation	The changes in the asset retirement obligation for the years ended December 31, 2017 and 2016 (in thousands) were as follows: As of December 31, 2017 2016 Abandonment liability as of January 1, $ 25,087 $ 25,907 Liabilities incurred during period 4,968 1,492 Acquisitions 8,289 219 Divestitures (3,538) (4,433) Revisions (1,343) (172) Accretion expense 2,635 2,074 Abandonment liability as of December 31, $ 36,098 $ 25,087

Accrued Liabilities and Other43

Accrued Liabilities and Other Current Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Accrued Liabilities and Other Current Liabilities
Summary of accrued liabilities	The following information summarizes accrued liabilities as of December 31, 2017 and 2016 (in thousands): As of December 31, 2017 2016 Capital expenditures $ 85,340 $ 35,154 Other: General and administrative costs 8,855 14,738 Production taxes 5,084 2,396 Ad valorem taxes 84 2,756 Lease operating expenses 32,152 23,942 Interest payable 34,632 34,266 Preferred stock dividends and other 3,987 4,360 Total accrued liabilities $ 170,134 $ 117,612
Summary of other payables	The following information summarizes the other payables as of December 31, 2017 and 2016 (in thousands): December 31, 2017 2016 Revenue payable $ 75,832 $ 2,124 Production tax payable 2,774 — Other 3,364 127 Total other payables $ 81,970 $ 2,251
Summary of other current liabilities	The following information summarizes the other current liabilities as of December 31, 2017 and 2016 (in thousands): December 31, 2017 2016 Operated prepayment liability $ 88,999 $ — Deferred gain on Western Catarina Midstream Divestiture - short term 23,720 23,720 Phantom compensation payable - short term 2,525 7,388 Total other current liabilities $ 115,244 $ 31,108

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017 and December 31, 2016 (in thousands): December 31, 2017 2016 Beginning Balance $ 39,656 $ 37,527 Investment in GRHL 7,280 — Earnings on (distributions from) equity investments (311) 311 Gain (Loss) from change in fair value of investment in SNMP (1,591) 1,818 Sale of investments (12,527) — Equity in equity investments $ 32,507 $ 39,656 December 31, 2017 2016 Equity in equity investments $ 32,507 $ 39,656 Guarantees of capital investments — — Maximum exposure to loss $ 32,507 $ 39,656

Condensed Consolidating Finan45

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Condensed Consolidating Financial Information
Condensed balance sheets	A summary of the condensed consolidated guarantor balance sheets for the periods ended December 31, 2017 and December 31, 2016 (in thousands) is presented below: December 31, 2017 Assets Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total current assets $ 447,984 $ 98,758 $ 117,031 $ (312,975) $ 350,798 Total oil and natural gas properties, net 3,987 1,275,153 748,319 - 2,027,459 Investment in subsidiaries 1,081,692 - (7,280) (1,074,412) - Other assets 25,451 4,415 62,512 - 92,378 Total Assets $ 1,559,114 $ 1,378,326 $ 920,582 $ (1,387,387) $ 2,470,635 Liabilities and Shareholders' Equity Current liabilities $ 212,026 $ 312,531 $ 250,946 $ (312,975) $ 462,528 Long-term liabilities 1,827,072 26,787 195,876 - 2,049,735 Mezzanine equity - - 427,512 - 427,512 Total shareholders' equity (deficit) (479,984) 1,039,008 46,248 (1,074,412) (469,140) Total Liabilities and Shareholders' Equity (deficit) $ 1,559,114 $ 1,378,326 $ 920,582 $ (1,387,387) $ 2,470,635 December 31, 2016 Assets Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total current assets $ 428,384 $ 123,380 $ 158,589 $ (147,548) $ 562,805 Total oil and natural gas properties, net - 704,519 - - 704,519 Investment in subsidiaries 734,704 - - (734,704) - Other assets 14,376 15,221 35,290 - 64,887 Total Assets $ 1,177,464 $ 843,120 $ 193,879 $ (882,252) $ 1,332,211 Liabilities and Shareholders' Equity Current liabilities $ 84,673 $ 78,344 $ 170,435 $ (147,548) $ 185,904 Long-term liabilities 1,788,930 25,086 16,273 - 1,830,289 Total shareholders' equity (deficit) (696,139) 739,690 7,171 (734,704) (683,982) Total Liabilities and Shareholders' Equity (deficit) $ 1,177,464 $ 843,120 $ 193,879 $ (882,252) $ 1,332,211
Condensed income statements	A summary of the condensed consolidated guarantor statements of operations for the periods ended December 31, 2017, December 31, 2016, and December 31, 2015 (in thousands) is presented below: Year Ended December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total revenues $ - $ 509,701 $ 230,630 $ - $ 740,331 Total operating costs and expenses (92,008) (387,614) (168,942) 680 (647,884) Other income (expense) (121,603) 75,837 (5,145) (680) (51,591) Income (loss) before income taxes (213,611) 197,924 56,543 - 40,856 Income tax benefit 2,336 - - - 2,336 Equity in income (loss) of subsidiaries 193,376 - - (193,376) - Net income (loss) $ (17,899) $ 197,924 $ 56,543 $ (193,376) $ 43,192 Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total revenues $ - $ 431,326 $ - $ - $ 431,326 Total operating costs and expenses (111,155) (367,541) (1,947) - (480,643) Other income (expense) (177,710) 82,948 4,418 - (90,344) Loss before income taxes (288,865) 146,733 2,471 - (139,661) Income tax expense (1,825) - - - (1,825) Equity in income (loss) of subsidiaries 33,730 - - (33,730) - Net income (loss) $ (256,960) $ 146,733 $ 2,471 $ (33,730) $ (141,486) Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total revenues $ - $ 475,779 $ - $ - $ 475,779 Total operating costs and expenses (75,096) (1,169,246) (1,692) - (1,246,034) Other income (expense) 44,726 (402) - - 44,324 Loss before income taxes (30,370) (693,869) (1,692) - (725,931) Income tax benefit (158) - - - (158) Equity in income (loss) of subsidiaries (1,416,657) - - 1,416,657 - Net income (loss) $ (1,447,185) $ (693,869) $ (1,692) $ 1,416,657 $ (726,089)
Condensed cash flows statements	A summary of the condensed consolidated guarantor statements of cash flows for the periods ended December 31, 2017, December 31, 2016, and December 31, 2015 (in thousands) is presented below: Year Ended December 31, 2017 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ (148,259) $ 346,345 $ 94,003 $ - $ 292,089 Net cash provided by (used in) investing activities (266,135) (620,382) (760,909) 264,626 (1,382,800) Net cash provided by (used in) financing activities 157,390 303,083 577,381 (264,626) 773,228 Net increase (decrease) in cash and cash equivalents (257,004) 29,046 (89,525) - (317,483) Cash and cash equivalents, beginning of period 343,941 - 157,976 - 501,917 Cash and cash equivalents, end of period $ 86,937 $ 29,046 $ 68,451 $ - $ 184,434 Year Ended December 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ (36,741) $ 218,864 $ 631 $ - $ 182,754 Net cash provided by (used in) investing activities (46,602) (133,412) 55,571 16,209 (108,234) Net cash provided by (used in) financing activities (7,650) (85,452) 101,660 (16,209) (7,651) Net increase (decrease) in cash and cash equivalents (90,993) - 157,862 - 66,869 Cash and cash equivalents, beginning of period 434,934 - 114 - 435,048 Cash and cash equivalents, end of period $ 343,941 $ - $ 157,976 $ - $ 501,917 Year Ended December 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ (43,556) $ 315,516 $ (1,384) $ - $ 270,576 Net cash provided by (used in) investing activities 21,670 (247,202) (40,327) (26,490) (292,349) Net cash provided by (used in) financing activities (16,894) (68,314) 41,825 26,490 (16,893) Net increase (decrease) in cash and cash equivalents (38,780) - 114 - (38,666) Cash and cash equivalents, beginning of period 473,714 - - - 473,714 Cash and cash equivalents, end of period $ 434,934 $ - $ 114 $ - $ 435,048

Organization and Business (Deta

Organization and Business (Details) - Eagle Ford Shale	Dec. 31, 2017a
Area under agreement, gross (in acres)	487,000
Area under agreement, net (in acres)	285,000

Basis of Presentation and Sum47

Basis of Presentation and Summary of Significant Accounting Policies (RecentAcctg) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
New accounting pronouncement
Net cash provided by (used in) operating activities	$ 292,089	$ 182,754	[1]	$ 270,576	[1]
Net cash provided by (used in) financing activities	773,228	(7,651)	[1]	(16,893)	[1]
Fair Value of Financial Instruments
Sale of investments	$ 12,527
Adjustment | Accounting Standards Update 2016-09
New accounting pronouncement
Net cash provided by (used in) operating activities		1,906
Net cash provided by (used in) financing activities		$ (1,906)
New accounting pronouncement, early adoption, effect | Accounting Standards Update 2016-09
New accounting pronouncement
Net cash provided by (used in) operating activities				533
Net cash provided by (used in) financing activities				$ (533)
[1]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Basis of Presentation and Sum48

Basis of Presentation and Summary of Significant Accounting Policies (Details) $ in Thousands	Sep. 12, 2014USD ($)	Sep. 18, 2013USD ($)	Dec. 31, 2017USD ($)item	Dec. 31, 2016USD ($)		Dec. 31, 2015USD ($)		Jun. 27, 2014	Jun. 13, 2013
Oil and Natural Gas Receivables
Allowance for doubtful accounts			$ 0	$ 0
Oil and Natural Gas Properties
Impairment of proved properties			0	3,700		$ 700,300
Impairment of unproved properties			$ 39,600	43,600		23,700
Percentage of the unproved property balance expected to be added to the amortization base during the year 2018			4.00%
Percentage of the unproved property balance expected to be added to the amortization base during the year 2019			4.00%
Percentage of the unproved property balance expected to be added to the amortization base during the year 2020			2.00%
Debt Issuance Costs
Debt issuance costs			$ 12,647	7,840	[1]	7,529	[1]
Debt issuance costs remaining			47,200	35,000
Accumulated amortization			34,500	22,500
Environmental Expenditures
Environmental remediation liability or loss associated with the Company's properties			$ 0	0
Minimum
Revenue Recognition
Number of owners having the right to take production | item			2
Second Amended And Restated Credit Agreement
Debt Issuance Costs
Debt issuance and amendment costs capitalized				1,600		$ 400
SN UnSub Credit Agreement
Debt Issuance Costs
Debt issuance and amendment costs capitalized			$ 18,700
Form S-3 Registration Statement
Debt Issuance Costs
Debt issuance and amendment costs capitalized				$ 100
6.125% Senior Notes
Debt Issuance Costs
Debt issuance costs	$ 6,400
Interest rate (as a percent)			6.125%					6.125%
6.125% Senior Notes | Second Amended And Restated Credit Agreement
Debt Issuance Costs
Interest rate (as a percent)			6.125%
7.75% Senior Notes
Debt Issuance Costs
Debt issuance costs		$ 4,200
Interest rate (as a percent)			7.75%						7.75%
[1]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Basis of Presentation and Sum49

Basis of Presentation and Summary of Significant Accounting Policies (Concentrations) (Details) - Total revenues - Customer concentration risk	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Customer A
Sales to Major Customers
Concentration risk percentage	19.00%	2.00%	1.00%
Customer B
Sales to Major Customers
Concentration risk percentage	9.00%	14.00%	14.00%
Customer C
Sales to Major Customers
Concentration risk percentage	14.00%	0.00%	0.00%
Customer D
Sales to Major Customers
Concentration risk percentage	26.00%	33.00%	38.00%
Customer E
Sales to Major Customers
Concentration risk percentage	23.00%	20.00%	0.00%

Change in Accounting Principl50

Change in Accounting Principle - Statement of Operations (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
New accounting pronouncement
Oil and natural gas production expenses	$ 244,461	$ 155,660	[1]	$ 154,672	[1]
Exploration expenses	5,755	403	[1]	1,982	[1]
Depreciation, depletion, amortization and accretion	177,078	147,485	[1]	264,379	[1]
Impairment of oil and natural gas properties	39,574	47,381	[1]	723,971	[1]
Other income (expense)	11,102	134	[1]	(2,605)	[1]
Gain on disposal of assets	81,955	85,322
Income tax benefit (expense)	2,336	(1,825)	[1]	(158)	[1]
Net loss	43,192	(141,486)	[1]	(726,089)	[1]
Net loss attributable to common stockholders	$ (35,054)	$ (157,434)	[1]	$ (742,097)	[1]
Net loss per common share - basic and diluted (in dollars per share)	$ (0.46)	$ (2.67)	[1]	$ (12.97)	[1]
Under Full Cost
New accounting pronouncement
Oil and natural gas production expenses	$ 253,368	$ 164,567		$ 156,528
Depreciation, depletion, amortization and accretion	199,087	159,760		344,572
Impairment of oil and natural gas properties		169,046		1,365,000
Other income (expense)	7,351
Gain on disposal of assets	10,202	112,294
Income tax benefit (expense)	2,336	(1,825)		(7,600)
Net loss	(17,899)	(256,958)		(1,454,627)
Net loss attributable to common stockholders	$ (96,145)	$ (272,906)		$ (1,470,635)
Net loss per common share - basic and diluted (in dollars per share)	$ (1.27)	$ (4.63)		$ (25.70)
Changes
New accounting pronouncement
Oil and natural gas production expenses	$ (8,907)	$ (8,907)		$ (1,856)
Exploration expenses	5,755	403		1,982
Depreciation, depletion, amortization and accretion	(22,009)	(12,275)		(80,193)
Impairment of oil and natural gas properties	39,574	(121,665)		(641,029)
Other income (expense)	3,751
Gain on disposal of assets	71,753	(26,972)
Income tax benefit (expense)				7,442
Net loss	61,091	115,472		728,538
Net loss attributable to common stockholders	$ 61,091	$ 115,472		$ 728,538
Net loss per common share - basic and diluted (in dollars per share)	$ 0.81	$ 1.96		$ 12.73
[1]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Change in Accounting Principl51

Change in Accounting Principle - Statement of Cash Flows (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
New accounting pronouncement
Net income (loss)		$ 43,192		$ (141,486)	[1]	$ (726,089)	[1]
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		177,078		147,485	[2]	264,379	[2]
Impairment of oil and natural gas properties		39,574		47,381	[2]	723,971	[2]
Gain on sale of oil and natural gas properties		(81,955)		(85,322)	[2]
Amortization of deferred gain on Catarina Midstream Sale		(23,720)		(23,720)		(4,942)
Deferred taxes		(737)				1	[1]
Net cash provided by operating activities		292,089		182,754	[1]	270,576	[1]
Payments for oil and natural gas properties		(500,334)		(312,939)	[1]	(654,154)	[1]
Net cash used in investing activities		(1,382,800)		(108,234)	[1]	(292,349)	[1]
Net cash provided by (used in) financing activities		773,228		(7,651)	[1]	(16,893)	[1]
Increase (decrease) in cash and cash equivalents		(317,483)		66,869	[1]	(38,666)	[1]
Cash and cash equivalents, beginning of period	[1]	501,917	[3]	435,048		473,714
Cash and cash equivalents, end of period		184,434		501,917	[1],[3]	435,048	[1]
Under Full Cost
New accounting pronouncement
Net income (loss)		(17,899)		(256,958)		(1,454,627)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		199,087		159,760		344,572
Impairment of oil and natural gas properties				169,046		1,365,000
Gain on sale of oil and natural gas properties		(10,202)		(112,294)
Amortization of deferred gain on Catarina Midstream Sale		(14,813)		(14,813)		(3,086)
Deferred taxes		(737)				7,443
Net cash provided by operating activities		294,093		183,157		272,558
Payments for oil and natural gas properties		(502,338)		(313,342)		(656,136)
Net cash used in investing activities		(1,384,804)		(108,637)		(294,331)
Net cash provided by (used in) financing activities		773,228		(7,651)		(16,893)
Increase (decrease) in cash and cash equivalents		(317,483)		66,869		(38,666)
Cash and cash equivalents, beginning of period		501,917		435,048		473,714
Cash and cash equivalents, end of period		184,434		501,917		435,048
Changes
New accounting pronouncement
Net income (loss)		61,091		115,472		728,538
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion		(22,009)		(12,275)		(80,193)
Impairment of oil and natural gas properties		39,574		(121,665)		(641,029)
Gain on sale of oil and natural gas properties		(71,753)		26,972
Amortization of deferred gain on Catarina Midstream Sale		(8,907)		(8,907)		(1,856)
Deferred taxes						(7,442)
Net cash provided by operating activities		(2,004)		(403)		(1,982)
Payments for oil and natural gas properties		2,004		403		1,982
Net cash used in investing activities		$ 2,004		$ 403		$ 1,982
[1]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.
[2]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.
[3]	* Financial information for 2016 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Change in Accounting Principl52

Change in Accounting Principle - Balance Sheet (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015	[2]	Dec. 31, 2014
Oil and Gas Property, Full Cost Method, Net [Abstract]
Unproved oil and natural gas properties	$ 398,605	$ 225,023	[1]
Proved oil and natural gas properties	3,130,407	1,849,732	[1]
Total oil and natural gas properties	3,529,012	2,074,755	[1]
Less: Accumulated depreciation, depletion, amortization and impairment	(1,501,553)	(1,370,236)	[1]
Total oil and natural gas properties, net	2,027,459	704,519	[1]
Other assets	52,488	25,231	[1]
Total assets	2,470,635	1,332,211	[1]
Current liabilities:
Other	115,244	31,108	[1]
Total current liabilities	462,528	185,904	[1]
Other liabilities	65,480	89,199	[1]
Total liabilities	2,512,263	2,016,193	[1]
Accumulated deficit	(1,832,156)	(1,797,102)	[1]
Total stockholders' equity (deficit)	(469,140)	(683,982)	[1],[2]	$ (559,483)		$ 167,735	[2]
Total liabilities and stockholders' equity (deficit)	2,470,635	1,332,211	[1]
Under Full Cost
Oil and Gas Property, Full Cost Method, Net [Abstract]
Unproved oil and natural gas properties	398,212	231,424
Proved oil and natural gas properties	4,462,171	3,164,115
Total oil and natural gas properties	4,860,383	3,395,539
Less: Accumulated depreciation, depletion, amortization and impairment	(2,931,039)	(2,736,951)
Total oil and natural gas properties, net	1,929,344	658,588
Total assets	2,372,520	1,286,280
Current liabilities:
Other	106,337	22,201
Total current liabilities	453,621	176,997
Other liabilities	49,520	64,333
Total liabilities	2,487,396	1,982,420
Accumulated deficit	(1,905,404)	(1,809,260)
Total stockholders' equity (deficit)	(542,388)	(696,140)				$ 999,587
Total liabilities and stockholders' equity (deficit)	2,372,520	1,286,280
Changes
Oil and Gas Property, Full Cost Method, Net [Abstract]
Unproved oil and natural gas properties	393	(6,401)
Proved oil and natural gas properties	(1,331,764)	(1,314,383)
Total oil and natural gas properties	(1,331,371)	(1,320,784)
Less: Accumulated depreciation, depletion, amortization and impairment	1,429,486	1,366,715
Total oil and natural gas properties, net	98,115	45,931
Total assets	98,115	45,931
Current liabilities:
Other	8,907	8,907
Total current liabilities	8,907	8,907
Other liabilities	15,960	24,866
Total liabilities	24,867	33,773
Accumulated deficit	73,248	12,158
Total stockholders' equity (deficit)	73,248	12,158
Total liabilities and stockholders' equity (deficit)	$ 98,115	$ 45,931
[1]	* Financial information for 2016 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.
[2]	Financial information for 2016, 2015, and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Acquisitions and Divestitures53

Acquisitions and Divestitures (Details) $ / shares in Units, $ in Thousands	Mar. 01, 2017USD ($)asubsidiary	Sep. 12, 2014USD ($)	Jun. 27, 2014USD ($)	Dec. 31, 2017USD ($)abbl / dMcf / dagreement$ / shares	Dec. 31, 2016USD ($)$ / shares		Jul. 01, 2016USD ($)
Acquisitions
Proceeds from issuance of debt				$ 373,250	$ 60,000	[1]
Unaudited pro forma combined statements of operations
Revenues				784,360	693,843
Net income (loss) attributable to common stockholders				$ (6,458)	$ (242,847)
Net income (loss) per common share, basic and diluted | $ / shares				$ (0.09)	$ (3.38)
Revenue, post-acquisition				$ 255,282
Excess of revenues over direct operating expenses, post acquisition				$ 138,046
6.125% Senior Notes
Acquisitions
Proceeds from issuance of debt		$ 295,900	$ 829,000
The "Comanche Assets"
Acquisitions
Gross acres | a	318,000
Net acres | a	155,000
Fair value of net assets acquired	$ 2,100,000						$ 1,043,673
Ownership interest acquired (as a percentage)	49.00%
Number of gathering agreements | agreement				2
Total purchase price allocated to assets purchased and liabilities assumed
Proved oil and natural gas properties							781,789
Unproved properties							263,471
Other assets acquired							6,702
Fair value of assets acquired							1,051,962
Asset retirement obligations							(8,289)
Fair value of net assets acquired	$ 2,100,000						$ 1,043,673
The "Comanche Assets" | Gross | Crude oil
Acquisitions
Daily delivery commitment (in units) | bbl / d				63,000
The "Comanche Assets" | Gross | Natural gas
Acquisitions
Daily delivery commitment (in units) | Mcf / d				430,000
The "Comanche Assets" | Net | Crude oil
Acquisitions
Daily delivery commitment (in units) | bbl / d				14,800
The "Comanche Assets" | Net | Natural gas
Acquisitions
Daily delivery commitment (in units) | Mcf / d				101,400
The "Comanche Assets" | SN EF UnSub, LP (“SN UnSub”) and SN EF Maverick, LLC (“SN Maverick”)
Acquisitions
Number of subsidiaries | subsidiary	2
The "Comanche Assets" | SN EF UnSub, LP (“SN UnSub”)
Acquisitions
Purchase price percentage	37.00%
Cash contribution	$ 100,000
Estimated total proved developed producing reserves (in percent)	50.00%
Estimated total proved developed non-producing reserves (in percent)	20.00%
Total proved undeveloped reserves (in percent)	20.00%
The "Comanche Assets" | SN EF Maverick, LLC (“SN Maverick”)
Acquisitions
Purchase price percentage	13.00%
Estimated total proved developed producing reserves (in percent)	0.00%
Estimated total proved developed non-producing reserves (in percent)	30.00%
Total proved undeveloped reserves (in percent)	30.00%
The "Comanche Assets" | Gavilan
Acquisitions
Purchase price percentage	50.00%
Total proved undeveloped reserves (in percent)	50.00%
Eagle Ford Shale
Acquisitions
Gross acres | a				487,000
Net acres | a				285,000
Eagle Ford Shale | The "Comanche Assets"
Acquisitions
Gross acres | a	252,000
Net acres | a	122,000
Pearsall Shale | The "Comanche Assets"
Acquisitions
Gross acres | a	66,000
Net acres | a	33,000
[1]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Acquisitions and Divestitures54

Acquisitions and Divestitures (Disposition) (Details)

Sep. 19, 2017USD ($)a

Jun. 15, 2017USD ($)aMMBoeBoeitemshares

Mar. 01, 2017USD ($)a$ / sharesshares

Dec. 14, 2016USD ($)

Nov. 22, 2016USD ($)item

Jul. 05, 2016USD ($)

Jun. 01, 2016aMMBoeBoeitem

Oct. 14, 2015USD ($)aitemshares

Mar. 31, 2015USD ($)itemshares

Mar. 31, 2017USD ($)

Dec. 31, 2017USD ($)item

Dec. 31, 2016USD ($)

Divestitures

Gain (reduction) on disposition

$ 81,955,000

$ 85,322,000

[1]

Investments

38,462,000

$ 39,656,000

[2]

Preferred Units issued ( in shares)

500,000,000

Lonestar

Divestitures

Investments (in shares or units) | shares

1,500,000

Javelina Disposition

Divestitures

Consideration in cash

$ 105,000,000

Undeveloped net acres | a

68,000

Gain losses on disposal

$ 73,700,000

Marquis Disposition | Lonestar

Divestitures

Consideration in cash

$ 44,000,000

Consideration in common stock (in shares) | shares

1,500,000

Net acres | a

21,000

Net proved reserves | MMBoe

2.7

Reserves developed (as a percentage)

100.00%

Net proved reserves per day | Boe

1,750

Number of wells, gross | item

104

Number of wells, net | item

65

Cotulla | Carrizo LLC

Divestitures

Gain (reduction) on disposition

$ 10,400,000

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

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

Consideration in common stock (in shares) | shares

105,263

Gross acres | a

35,000

Term of agreement

15 years

Term of gas gathering agreement

5 years

Deferred gain

$ 116,800,000

SN Cotulla Assets, LLC | Carrizo LLC

Divestitures

Consideration

$ 153,500,000

Number of additional sale closings | item

2

Consideration in cash

$ 167,400,000

Net acres | a

15,000

Net proved reserves | MMBoe

6.9

Reserves developed (as a percentage)

90.00%

Net proved reserves per day | Boe

3,000

Number of wells, gross | item

112

Number of wells, net | item

93

Gain (reduction) on disposition

$ 85,300,000

SNMP | Disposed of by sale, not discontinued operations

Divestitures

Term of gas gathering agreement

5 years

SNMP | Production Asset Transaction

Divestitures

Consideration

$ 24,200,000

Number of wellbores having partial interest | item

23

11

Percentage of working interest initially conveyed per wellbore

17.92%

Percentage of working interest

47.50%

SNMP | Carnero Gathering, LLC

Divestitures

Consideration in cash

$ 37,000,000

Assumption of capital commitments in joint venture

$ 7,400,000

SNMP | Palmetto | Disposed of by sale, not discontinued operations

Divestitures

Consideration in common stock (in shares) | shares

1,052,632

Investments

$ 2,000,000

Percentage of working interest initially conveyed per wellbore

18.25%

Percentage of working interest

47.50%

The "Comanche Assets"

Divestitures

Gross acres | a

318,000

Net acres | a

155,000

Borrowings

$ 173,500,000

Maximum borrowing capacity

$ 330,000,000

The "Comanche Assets" | GSO Capital Partners LP

Divestitures

Number of shares issued (in shares) | shares

1,455,000

Issuance of warrants | shares

1,940,000

Issuance of warrants (in dollars per share) | $ / shares

$ 10

The "Comanche Assets" | Intrepid Private Equity V-A, LLC

Divestitures

Number of shares issued (in shares) | shares

45,000

Issuance of warrants | shares

60,000

Issuance of warrants (in dollars per share) | $ / shares

$ 10

The "Comanche Assets" | Gavilan

Divestitures

Issuance of warrants | shares

6,500,000

Issuance of warrants (in dollars per share) | $ / shares

$ 10

The "Comanche Assets" | SN UnSub Preferred Units

Divestitures

Preferred Units issued ( in shares)

$ 500,000

Preferred Units issued

$ 500,000,000

The "Comanche Assets" | SN UnSub Preferred Units | GSO Capital Partners LP

Divestitures

Preferred Units issued ( in shares)

$ 485,000

Preferred Units issued

485,000,000

The "Comanche Assets" | SN UnSub Preferred Units | Intrepid Private Equity V-A, LLC

Divestitures

Preferred Units issued ( in shares)

15,000

Preferred Units issued

$ 15,000,000

SN Comanche Manager, LLC | Gavilan

Divestitures

Issuance of units | shares

100

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

[1]

Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

[2]

* Financial information for 2016 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Cash and Cash Equivalents (Deta

Cash and Cash Equivalents (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015	[2]	Dec. 31, 2014	[2]
Cash and cash equivalents
Total cash and cash equivalents	$ 184,434	$ 501,917	[1],[2]	$ 435,048		$ 473,714
Cash at banks
Cash and cash equivalents
Total cash and cash equivalents	135,363	58,269
Money market funds
Cash and cash equivalents
Total cash and cash equivalents	$ 49,071	$ 443,648
[1]	* Financial information for 2016 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.
[2]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Debt (Summary) (Details)

Debt (Summary) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016		Feb. 27, 2015	Sep. 12, 2014	Jul. 18, 2014	Jun. 27, 2014	Jun. 18, 2014	Sep. 18, 2013	Jun. 13, 2013
Long-Term Debt
Short term debt	$ 23,996
Long term debt before unamortized discount	1,979,664	$ 1,750,000
Unamortized debt issuance costs	(47,215)	(34,832)
Total long-term debt	$ 1,930,683	1,712,767	[1]
7.75% Senior Notes
Long-Term Debt
Face value of debt						$ 600,000		$ 600,000	$ 200,000	$ 400,000
Interest rate (as a percent)	7.75%									7.75%
Long term debt before unamortized discount	$ 600,000	600,000
Unamortized discount on Additional 7.75% Notes	(3,126)	(4,030)
4.59% Non-Recourse Subsidiary Term Loan
Long-Term Debt
Face value of debt	$ 4,200
Interest rate (as a percent)	4.59%
Long term debt before unamortized discount	$ 4,164
6.125% Senior Notes
Long-Term Debt
Face value of debt	$ 1,150,000				$ 300,000
Interest rate (as a percent)	6.125%						6.125%
Long term debt before unamortized discount	$ 1,150,000	1,150,000
Unamortized premium on Additional 6.125% Notes	1,360	$ 1,629			$ 2,300
Senior Unsecured Notes
Long-Term Debt
Face value of debt				$ 1,150,000
Second Amended And Restated Credit Agreement
Long-Term Debt
Long term debt before unamortized discount	$ 50,000
Second Amended And Restated Credit Agreement | 6.125% Senior Notes
Long-Term Debt
Interest rate (as a percent)	6.125%
SN UnSub Credit Agreement
Long-Term Debt
Long term debt before unamortized discount	$ 175,500
SR Credit Agreement
Long-Term Debt
Short term debt	$ 23,996
Weighted average interest rate	5.122%
[1]	* Financial information for 2016 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Debt (Interest Expense Componen

Debt (Interest Expense Components) (Details) - USD ($) $ in Thousands	Sep. 12, 2014	Sep. 18, 2013	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Interest expense
Interest			$ (116,938)	$ (116,938)		$ (116,938)
Interest on credit agreement and term loan			(7,639)
Interest expense and commitment fees on Second Amended and Restated Credit Agreement			(2,135)	(1,561)		(1,229)
Amortization of debt issuance costs			(12,647)	(7,840)	[1]	(7,529)	[1]
Amortization of (discount) premium			(634)	(633)	[1]	(703)	[1]
Total interest expense			(140,163)	(126,973)	[2]	(126,399)	[2]
4.59% Non-Recourse Subsidiary Term Loan
Interest expense
Interest on credit agreement and term loan			(65)
7.75% Senior Notes
Interest expense
Amortization of debt issuance costs		$ (4,200)
Amortization of (discount) premium			(904)	(904)		(904)
6.125% Senior Notes
Interest expense
Amortization of debt issuance costs	$ (6,400)
Amortization of (discount) premium			270	$ 270		$ 201
SR Credit Agreement
Interest expense
Interest on credit agreement and term loan			$ (105)
[1]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.
[2]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Debt (Detail)

Debt (Detail) $ in Thousands

Feb. 14, 2018USD ($)

Mar. 01, 2017USD ($)

Sep. 12, 2014USD ($)

Sep. 18, 2013USD ($)

Jun. 13, 2013USD ($)

Sep. 30, 2014USD ($)

Sep. 30, 2013USD ($)

Sep. 30, 2013USD ($)

Dec. 31, 2017USD ($)asubsidiary

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

[1]

Dec. 20, 2017USD ($)

Nov. 06, 2017USD ($)

Jul. 18, 2014USD ($)

Jun. 30, 2014USD ($)

Jun. 27, 2014USD ($)

Jun. 18, 2014USD ($)

Oct. 31, 2013item

Long-Term Debt

Debt issuance costs

$ 12,647

$ 7,840

[1]

$ 7,529

Wycross

Long-Term Debt

Number of wells, gross | item

13

SR

Long-Term Debt

Borrowings

$ 24,000

SR | TMS

Long-Term Debt

Net acres | a

12,500

Minimum | Subsequent Events

Long-Term Debt

Percentage of debt instrument redeem under certain circumstances

35.00%

7.25% Senior Notes

Long-Term Debt

Threshold of allowed hedging

$ 10,000

7.25% Senior Notes | Subsequent Events

Long-Term Debt

Maximum borrowing capacity

$ 50,000

Face value of debt

$ 500,000

Interest rate (as a percent)

7.25%

Redemption price of debt instrument (as a percent)

100.00%

7.75% Senior Notes

Long-Term Debt

Face value of debt

$ 200,000

$ 400,000

$ 600,000

$ 600,000

Interest rate (as a percent)

7.75%

7.75%

Percentage value of Additional Notes at which they are offered in private offering

96.50%

Proceeds for issuance of notes, net of discount/premium and related offering expenses

$ 188,800

$ 388,000

$ 192,900

Debt issuance costs

$ 4,200

Proceeds from interest received

$ 4,100

6.125% Senior Notes

Long-Term Debt

Face value of debt

$ 300,000

$ 1,150,000

Interest rate (as a percent)

6.125%

6.125%

Percentage value of Additional Notes at which they are offered in private offering

100.75%

Proceeds for issuance of notes, net of discount/premium and related offering expenses

299,700

Premium on face value of debt

$ 2,300

$ 1,360

$ 1,629

Debt issuance costs

$ 6,400

Redemption price of debt instrument (as a percent)

100.00%

Accrued interest

$ 3,800

6.125% Senior Notes | Subsequent Events

Long-Term Debt

Interest rate (as a percent)

6.125%

Previous First Lien Credit Agreement | 6.125% Senior Notes

Long-Term Debt

Repayment of debt using proceeds from senior note offering

$ 100,000

Second Amended And Restated Credit Agreement

Long-Term Debt

Maximum borrowing capacity

$ 1,500,000

Borrowings

$ 50,000

Borrowing base

350,000

Aggregate elected commitment amount

$ 300,000

Percentage of increased net debt used to calculate reduction in borrowing base

25.00%

Threshold of allowed hedging

$ 10,000

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%

Second Amended And Restated Credit Agreement | 7.25% Senior Notes | Subsequent Events

Long-Term Debt

Face value of debt

$ 500,000

Second Amended And Restated Credit Agreement | 7.75% Senior Notes | Subsequent Events

Long-Term Debt

Interest rate (as a percent)

7.25%

Second Amended And Restated Credit Agreement | 6.125% Senior Notes

Long-Term Debt

Interest rate (as a percent)

6.125%

Third Amended And Restated Credit Agreement | Subsequent Events

Long-Term Debt

Maximum borrowing capacity

$ 25,000

Percentage of commitment fee on the unused committed amount

0.50%

Third Amended And Restated Credit Agreement | Alternate base rate | Minimum | Subsequent Events

Long-Term Debt

Variable rate basis, spread percentage

1.50%

Third Amended And Restated Credit Agreement | Alternate base rate | Maximum | Subsequent Events

Long-Term Debt

Variable rate basis, spread percentage

2.25%

Third Amended And Restated Credit Agreement | Eurodollar rate | Minimum | Subsequent Events

Long-Term Debt

Variable rate basis, spread percentage

2.50%

Third Amended And Restated Credit Agreement | Eurodollar rate | Maximum | Subsequent Events

Long-Term Debt

Variable rate basis, spread percentage

3.25%

Third Amended And Restated Credit Agreement | 7.25% Senior Notes | Subsequent Events

Long-Term Debt

Face value of debt

$ 25,000

Third Amended And Restated Credit Agreement | 7.75% Senior Notes | Subsequent Events

Long-Term Debt

Interest rate (as a percent)

7.75%

SN UnSub Credit Agreement

Long-Term Debt

Maximum borrowing capacity

$ 500,000

Borrowings

$ 175,500

Letters of credit outstanding

$ 0

Borrowing base

$ 330,000

$ 330,000

Percentage of increased net debt used to calculate reduction in borrowing base

25.00%

Aggregate principal amount

$ 25,000

Junior debt issuances

$ 200,000

Effective borrowing base

5.00%

Number of subsidiaries | subsidiary

0

SN UnSub Credit Agreement | Minimum

Long-Term Debt

Current ratio

1

SN UnSub 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

4

SN UnSub Credit Agreement | Alternate base rate | Minimum

Long-Term Debt

Variable rate basis, spread percentage

1.75%

SN UnSub Credit Agreement | Alternate base rate | Maximum

Long-Term Debt

Variable rate basis, spread percentage

2.75%

SN UnSub Credit Agreement | Eurodollar rate | Minimum

Long-Term Debt

Variable rate basis, spread percentage

2.75%

SN UnSub Credit Agreement | Eurodollar rate | Maximum

Long-Term Debt

Variable rate basis, spread percentage

3.75%

Letters of credit

Long-Term Debt

Maximum borrowing capacity

$ 50,000

$ 80,000

Letters of credit outstanding

$ 0

SR Credit Agreement

Long-Term Debt

Borrowing capacity subsequently increased

24,000

Aggregate elected commitment amount was available for future revolver borrowings.

$ 250,000

Net acres | a

12,500

[1]

Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Stockholders' and Mezzanine E59

Stockholders' and Mezzanine Equity (Details)	Mar. 01, 2017USD ($)item$ / sharesshares	Feb. 06, 2017USD ($)$ / sharesshares	Jul. 28, 2015itemshares	Mar. 26, 2013USD ($)$ / sharesshares	Sep. 17, 2012USD ($)$ / sharesshares	Dec. 31, 2017USD ($)agreementitem$ / sharesshares	Dec. 31, 2016USD ($)$ / shares	May 25, 2017USD ($)
Common stock, par value (in dollars per share) | $ / shares						$ 0.01	$ 0.01
Issuance of common stock (net of underwriting discounts of $7.8 million)						$ 135,942,000
Common shares issued						134,863,000
Issuance costs related to preferred units						20,894,000
Preferred Units issued ( in shares)						500,000,000
Number of rights declared for each common stock | shares			1
Number of rights automatically attached | item			1
Dividends accrued or accumulated						$ 3,987,000	$ 4,360,000
SN Comanche Manager | Class A Units
Total units authorized for issuance | shares	100
Vesting percentage of class A	20.00%
Number of anniversaries | item	5
Common Stock
Number of shares issued (in shares) | shares		10,000,000
Shares issued, price per share (in dollars per share) | $ / shares		$ 12.50
Number of shares of common stock to be issued if all preferred shares are converted | shares						4,275,640
Preferred Class A
Number of shares issued (in shares) | shares					3,000,000
Shares issued, price per share (in dollars per share) | $ / shares					$ 50
Proceeds from the private placement of preferred stock					$ 144,500,000
Issuance costs related to preferred units					$ 5,500,000
Conversion ratio (in shares) | shares					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 | shares						0
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) | shares				4,500,000
Shares issued, price per share (in dollars per share) | $ / shares				$ 50
Proceeds from the private placement of preferred stock				$ 216,600,000
Issuance costs related to preferred units				$ 8,400,000
Conversion ratio (in shares) | shares				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 | shares						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 | shares						0
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%
SN UnSub Preferred Units
Internal rate of return						14.00%
Purchase price for unit						1.5
ATM offering
Common stock available for issuance								$ 75
IPO | Common Stock
Net of underwriters discounts (in dollars per share) | $ / shares		$ 11.7902
Over-allotment option
Number of shares issued (in shares) | shares		1,500,000
Period of options to purchase common stock		30 days
Common shares issued		$ 135,900,000
Underwriting discounts and estimated offering expenses		$ 7,800,000
The "Comanche Assets" | SN UnSub Preferred Units
Preferred Units issued ( in shares)	$ 500,000
Preferred Units issued	$ 500,000,000
Distributions (as percent)						10.00%
The "Comanche Assets" | GSO Capital Partners LP
Number of shares issued (in shares) | shares	1,455,000
Issuance of warrants | shares	1,940,000
Issuance of warrants (in dollars per share) | $ / shares	$ 10
The "Comanche Assets" | GSO Capital Partners LP | SN UnSub Preferred Units
Preferred Units issued ( in shares)						$ 485,000
Preferred Units issued						485,000,000
The "Comanche Assets" | Intrepid Private Equity V-A, LLC
Number of shares issued (in shares) | shares	45,000
Issuance of warrants | shares	60,000
Issuance of warrants (in dollars per share) | $ / shares	$ 10
The "Comanche Assets" | Intrepid Private Equity V-A, LLC | SN UnSub Preferred Units
Preferred Units issued ( in shares)						15,000
Preferred Units issued						$ 15,000,000
The "Comanche Assets" | Blackstone Warrant Holders
Number of warrants | agreement						3
Issuance of warrants | shares						6,500,000
Issuance of warrants (in dollars per share) | $ / shares						$ 10

Stockholders' and Mezzanine E60

Stockholders' and Mezzanine Equity (Mezzanine Equity) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Stockholders' and Mezzanine Equity
Mezzanine equity beginning balance		[1]
Private placement of SN UnSub Preferred Units	500,000
Discount	(90,527)
Amortization of discount	18,039
Dividends accrued	41,667
Dividends paid	(41,667)
Total mezzanine equity	$ 427,512
[1]	* Financial information for 2016 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Stockholders' and Mezzanine E61

Stockholders' and Mezzanine Equity (EPS) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Earnings (Loss) Per Share
Net income (loss)	$ 43,192	$ (141,486)	[1]	$ (726,089)	[1]
Preferred stock dividends	(15,948)	(15,948)	[1]	(16,008)	[1]
Preferred unit dividends and distributions	(44,259)
Preferred unit amortization	(18,039)
Net loss attributable to common stockholders	$ (35,054)	$ (157,434)	[1]	$ (742,097)	[1]
Weighted average number of unrestricted outstanding common shares used to calculate basic net income (loss) per share	75,608,000	58,900,000		57,229,000
Denominator for diluted income (loss) per common share	75,608,000	58,900,000		57,229,000
Net loss per common share - basic and diluted (in dollars per share)	$ (0.46)	$ (2.67)	[1]	$ (12.97)	[1]
Restricted stock
Earnings (Loss) Per Share
Anti-dilutive stock	2,755,893	2,113,462		2,663,010
Non-vested common stock (in shares)	0	0		0
Common Stock
Earnings (Loss) Per Share
Anti-dilutive stock	12,520,179	12,554,481		12,529,314
Convertible Preferred Stock
Earnings (Loss) Per Share
Anti-dilutive stock	100,000	100,000		100,000
[1]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) $ / shares in Units, $ in Thousands	Mar. 01, 2017shares	Dec. 31, 2017USD ($)director$ / sharesitemshares	Dec. 31, 2016USD ($)director$ / sharesshares	Dec. 31, 2015USD ($)item$ / sharesshares	Dec. 29, 2017$ / shares
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%
Number of new forms of restricted stock award agreements | item		2
Total stock-based compensation expense | $		$ 40,298	$ 37,090	$ 14,831
Additional disclosure related to compensation cost
Closing price of common stock (in dollars per share) | $ / shares		$ 5.31			$ 5.31
Minimum
Additional disclosure related to compensation cost
Percentage of target phantom shares	0.00%
Maximum
Additional disclosure related to compensation cost
Percentage of target phantom shares	200.00%
Restricted stock
Additional disclosure related to compensation cost
Unrecognized compensation costs related to non-vested restricted shares outstanding | $		$ 17,500
Expected average period for recognition of unrecognized compensation costs related to non-vested shares		2 years 1 month 17 days
Number of Non-Vested Shares
Shares available for future issuance to participants		8,300,000
Restricted stock | Vesting in equal annual increments over three year period
Stock-Based Compensation
Vesting period		3 years
Restricted stock | Employees and consultants of SOG
Number of Non-Vested Shares
Granted (in shares)		2,100,000	4,400,000	3,400,000
Restricted stock | Employees and consultants of SOG | Three-year vesting period
Stock-Based Compensation
Vesting period			3 years	3 years
Number of Non-Vested Shares
Granted (in shares)			3,300,000	3,300,000
Restricted stock | Employees and consultants of SOG | 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		6	5	5
Vesting period		1 year	1 year	1 year
Granted (in dollars per share) | $ / shares		$ 6.32	$ 8	$ 12.65
Total stock-based compensation expense | $		$ 6,726	$ 1,000	$ 917
Additional disclosure related to compensation cost
Closing price of common stock (in dollars per share) | $ / shares			$ 5.81	$ 9.80
Number of Non-Vested Shares
Granted (in shares)		200,334	156,126	95,237
Weighted Average Fair Value
Granted (in dollars per share) | $ / shares		$ 6.32	$ 8	$ 12.65
Restricted stock | Non-employees
Stock-Based Compensation
Total stock-based compensation expense | $		$ 15,455	$ 23,961	$ 13,914
PARS
Additional disclosure related to compensation cost
Unrecognized compensation costs related to non-vested restricted shares outstanding | $		$ 600
Expected average period for recognition of unrecognized compensation costs related to non-vested shares		3 years 3 months 15 days
Number of Non-Vested Shares
Granted (in shares)		0
PARS | Employees of SOG | Cliff vesting after five years
Stock-Based Compensation
Vesting period			5 years
PARS | Employees of SOG | Five-year vesting period
Number of Non-Vested Shares
Granted (in shares)			1,100,000
PAPS
Number of Non-Vested Shares
Granted (in shares)		0
PARS, PAPS, and Phantom Stock award shares
Stock-Based Compensation
Total stock-based compensation expense | $		$ 17,389	$ 12,129
Additional disclosure related to compensation cost
Unrecognized compensation costs related to non-vested restricted shares outstanding | $		$ 11,800
Expected average period for recognition of unrecognized compensation costs related to non-vested shares		2 years 6 months 15 days
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		$ 11.08
Number of Non-Vested Shares
Non-vested shares, beginning of period (in shares)		6,891,261
Granted (in shares)		2,138,674
Vested (in shares)		(4,022,495)
Forfeited (in shares)		(110,712)
Non-vested shares, end of the period (in shares)		4,896,728	6,891,261
Weighted Average Fair Value
Non-vested common stock at the beginning of the period (in dollars per share) | $ / shares		$ 9.18
Granted (in dollars per share) | $ / shares		11.08
Vested (in dollars per share) | $ / shares		8.71
Forfeited (in dollars per share) | $ / shares		8.15
Non-vested common stock at the end of the period (in dollars per share) | $ / shares		$ 10.42	$ 9.18
Aggregate Intrinsic Value
Non-vested common stock, beginning of period (in dollars) | $		$ 63,262
Granted (in dollars) | $		23,697
Vested (in dollars) | $		(35,036)
Forfeited (in dollars) | $		(902)
Non-vested common stock, end of period (in dollars) | $		$ 51,021	$ 63,262
Phantom Stock shares and PAPS
Stock-Based Compensation
Vesting percentage		0.00%
Granted (in dollars per share) | $ / shares		$ 11.07
Number of Non-Vested Shares
Non-vested shares, beginning of period (in shares)		4,012,413
Granted (in shares)		2,163,240
Vested (in shares)		(2,533,534)
Forfeited (in shares)		(53,475)
Non-vested shares, end of the period (in shares)		3,588,644	4,012,413
Weighted Average Fair Value
Non-vested common stock at the beginning of the period (in dollars per share) | $ / shares		$ 4.87
Granted (in dollars per share) | $ / shares		11.07
Vested (in dollars per share) | $ / shares		8.81
Forfeited (in dollars per share) | $ / shares		10.49
Non-vested common stock at the end of the period (in dollars per share) | $ / shares		$ 5.74	$ 4.87
Aggregate Intrinsic Value
Non-vested common stock, beginning of period (in dollars) | $		$ 19,540
Granted (in dollars) | $		23,947
Vested (in dollars) | $		(22,320)
Forfeited (in dollars) | $		(561)
Non-vested common stock, end of period (in dollars) | $		20,606	$ 19,540
Phantom Stock shares and PAPS | Employees of SOG
Number of Non-Vested Shares
Granted (in shares)			2,200,000
Phantom Stock shares and PAPS | Employees and consultants of SOG
Number of Non-Vested Shares
Granted (in shares)			4,000,000
Phantom Stock shares and PAPS | Employees and consultants of SOG | Three-year vesting period
Stock-Based Compensation
Vesting period			3 years
Number of Non-Vested Shares
Granted (in shares)			2,800,000
Phantom Stock shares and PAPS | Employees and consultants of SOG | Five-year vesting period
Stock-Based Compensation
Vesting period			5 years
Number of Non-Vested Shares
Granted (in shares)			1,200,000
Performance awards
Stock-Based Compensation
Total stock-based compensation expense | $		728
Additional disclosure related to compensation cost
Unrecognized compensation costs related to non-vested restricted shares outstanding | $		$ 2,200
Expected average period for recognition of unrecognized compensation costs related to non-vested shares		3 years 4 days
LTIP PLan
Stock-Based Compensation
Vesting period	5 years
LTIP PLan | Chief Executive Officer | Maximum
Additional disclosure related to compensation cost
Target shares	245,234
LTIP PLan | Executive Chairman of the Board of Directors | Maximum
Additional disclosure related to compensation cost
Target shares	245,234
LTIP PLan | Chief Operating Officer | Maximum
Additional disclosure related to compensation cost
Target shares	245,234
LTIP PLan | President | Maximum
Additional disclosure related to compensation cost
Target shares	81,745

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Components of income tax provision
Current expense (benefit) as a result of current operations		$ (1,599)	$ 1,825		$ 158
Deferred expense (benefit) as a result of current operations		257,358	(46,191)		(254,560)
Increase (Decrease) in valuation allowance		(258,095)	46,191		254,560
Net income tax expense (benefit)		$ (2,336)	1,825	[1]	158	[1]
Reconciliation of the statutory federal income tax with the income tax provision
Effective tax rate (as a percent)		(5.70%)
Federal statutory rate		35.00%
Income tax expense (benefit) at the federal statutory rate		$ 14,300	(48,882)		(254,077)
Officers' compensation limitation		9,570	3,115		1,328
State taxes (net of federal benefit)		2,607	(232)		(5,463)
Non-deductible general and administrative expenses		841	743		309
Percentage depletion carry forward		(86)	(144)
Other		(52)	39
Minimum Tax Credit Recoverability		(1,599)
US Tax Reform - Impact to Deferreds		227,392
Differences between actual income taxes and amounts estimated in prior years		2,786	995		3,501
Income tax expense (benefit)		255,759	(44,366)		(254,402)
US Tax Reform - One-Time Valuation Allowance Change		(227,392)
Other Valuation Allowance change		(30,703)	46,191		254,560
Net income tax expense (benefit)		(2,336)	1,825	[1]	$ 158	[1]
Deferred tax assets (liabilities):
Derivative assets		9,536	12,516
Depreciable, depletable property, plant and equipment			138,120
Depreciable, depletable property, plant and equipment (liability)		(22,351)
Share based compensation		936	12,408
Revenue recognition		3,593	7,077
Investments in joint ventures			5,064
Investments in joint ventures		(22,561)
Other		321
Other			(2,007)
Federal net operating loss carryforward		364,922	420,302
State net operating loss carryforward		4,246	3,256
Deferred tax assets		338,642	596,736
Valuation allowance		(338,642)	(596,736)
Current:
Derivative assets		9,536	$ 12,516
Noncurrent:
Other		321
Net operating loss carryforwards		1,737,700
Provisional non cash adjustment		$ 227,400
Forecast
Reconciliation of the statutory federal income tax with the income tax provision
Federal statutory rate	21.00%
[1]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Related Party Transactions (Det

Related Party Transactions (Details)	Dec. 20, 2017USD ($)	Mar. 01, 2017USD ($)itemshares	Jun. 30, 2017USD ($)	Dec. 31, 2017USD ($)a$ / MMBTU	Dec. 31, 2016USD ($)		Dec. 31, 2015USD ($)		Aug. 11, 2017USD ($)	Nov. 22, 2016USD ($)shares	Oct. 06, 2016USD ($)mi
Related Party Transactions
Accounts receivable - related entities				$ 4,491,000	$ 6,401,000	[1]
Litigation settlement, amount from other party				11,750,000
General and administrative costs				$ 144,401,000	110,081,000	[2]	$ 74,160,000	[2]
Comanche
Related Party Transactions
Initial term of the administrative services agreement		8 years
Administration Fee (as a percent)		2.00%
Costs, fees or other expenses payable		$ 1,000,000
Period for which agreement will extend automatically		1 year
Written notice period for termination of administrative services agreement		180 days
Comanche | Maximum | Per Month
Related Party Transactions
General and administrative costs		$ 500,000
Comanche | Maximum | Per year until March 1, 2019
Related Party Transactions
General and administrative costs		5,000,000
Comanche | Maximum | Per year, thereafter
Related Party Transactions
General and administrative costs		$ 10,000,000
SOG
Related Party Transactions
Related party, cumulative ownership of equity interests by affiliates (as a percent)				100.00%
Administrative fees				$ 67,381,000	40,901,000		30,430,000
Third-party expenses				5,881,000	5,001,000		5,427,000
Total included in general and administrative expenses and oil and natural gas production expenses				$ 73,262,000	45,902,000		$ 35,857,000
SR
Related Party Transactions
Litigation settlement, amount from other party	$ 11,750,000
Ligitation settlement, amount from third party	5,200,000
Credit agreement, amount outstanding	$ 24,000,000
SR | TMS
Related Party Transactions
Net acres | a				12,500
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Less Noncontrolling Interest [Abstract]
Proved oil and natural gas properties									$ 17,719,000
Unproved properties									5,227,000
Other assets acquired									3,952,000
Fair value of assets acquired									26,898,000
Asset retirement obligations									(2,902,000)
Fair value of net assets acquired									$ 23,996,000
SNMP
Related Party Transactions
Accounts payable - related entities				$ 9,800,000	$ 9,000,000
Incremental fee per barrel of water, payable to SNMP			$ 1
Contingent lease option exercise payment											$ 1
Contingent crude storage terminal payment											$ 250,000
Contingent payment, crude storage terminal within number of miles of a project | mi											5
Seco Pipeline, LLC
Related Party Transactions
Agreement for transported natural gas quantities to SN Catarina (price per unit) | $ / MMBTU				0.22
Perpetual term of agreement unless terminated				1 month
SN Comanche Manager | Class A Units
Related Party Transactions
Total units authorized for issuance | shares		100
Vesting percentage of class A		20.00%
Number of anniversaries | item		5
Antonio R. Sanchez, Jr. | SNMP
Related Party Transactions
Ownership of investment (as a percent)				0.67%
Antonio R. Sanchez, III | SNMP
Related Party Transactions
Ownership of investment (as a percent)				2.06%
Patricio D. Sanchez | SNMP
Related Party Transactions
Ownership of investment (as a percent)				2.42%
Eduardo A. Sanchez | SNMP
Related Party Transactions
Ownership of investment (as a percent)				2.04%
Common Stock | SNMP
Related Party Transactions
Investments (in shares or units) | shares										2,272,727
Investments										$ 25,000,000
[1]	* Financial information for 2016 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.
[2]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Derivative Instruments (Details

Derivative Instruments (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)MMBTU$ / bbl$ / MMBTUbbl	Dec. 31, 2016USD ($)		Dec. 31, 2015USD ($)
Derivatives Fair Value [Line Items]
Deferred payment of premiums	$ 56,190	$ 31,778	[1]
Embedded derivatives
Reconciliation of the changes in fair value of the commodity derivatives
Net gains / (losses) on derivatives	(1,551)
Ending fair value of commodity derivatives	$ (1,551)
Not designated as hedges | Swaption | 2018 | Crude oil
Derivatives Fair Value [Line Items]
Notional amount (in barrels) | bbl	730,000
Average swap price per unit | $ / bbl	55
Not designated as hedges | Commodity derivatives
Reconciliation of the changes in fair value of the commodity derivatives
Beginning fair value of commodity derivatives	$ (35,014)	178,283		$ 123,316
Ending fair value of commodity derivatives	(54,255)	(35,014)		178,283
Not designated as hedges | Commodity derivatives | Crude oil
Reconciliation of the changes in fair value of the commodity derivatives
Net gains / (losses) on derivatives	(48,966)	(47,389)		170,592
Net settlements on derivative contracts	(11,807)	(135,491)		(123,946)
Net premiums on derivative contracts		(24,547)
Not designated as hedges | Commodity derivatives | Natural gas
Reconciliation of the changes in fair value of the commodity derivatives
Net gains / (losses) on derivatives	42,764	(30,307)		26,843
Net settlements on derivative contracts	$ (1,232)	$ (24,657)		$ (18,522)
Not designated as hedges | Swaps | January 1 - December 31, 2017 | Crude oil
Derivatives Fair Value [Line Items]
Notional amount (in barrels) | bbl	8,121,124
Average swap price per unit | $ / bbl	52.45
Not designated as hedges | Swaps | January 1 - December 31, 2017 | Natural gas
Derivatives Fair Value [Line Items]
Notional amount (in MMBtu) | MMBTU	68,818,146
Average swap price per unit | $ / MMBTU	3.04
Not designated as hedges | Swaps | 2018 | Crude oil
Derivatives Fair Value [Line Items]
Notional amount (in barrels) | bbl	3,149,000
Average swap price per unit | $ / bbl	51.91
Not designated as hedges | Swaps | 2018 | Natural gas
Derivatives Fair Value [Line Items]
Notional amount (in MMBtu) | MMBTU	17,644,000
Average swap price per unit | $ / MMBTU	2.90
Not designated as hedges | Swaps | 2019 | Crude oil
Derivatives Fair Value [Line Items]
Notional amount (in barrels) | bbl	381,000
Average swap price per unit | $ / bbl	53.52
Not designated as hedges | Swaps | 2019 | Natural gas
Derivatives Fair Value [Line Items]
Notional amount (in MMBtu) | MMBTU	2,361,000
Average swap price per unit | $ / MMBTU	2.82
[1]	* Financial information for 2016 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Derivative Instruments (Balance

Derivative Instruments (BalanceSheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	$ 18,610	$ 2,270
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(752)	(2,270)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	17,858
Offsetting Derivative Liabilities:
Gross Amount of Recognized Liabilities	74,415	37,284
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(752)	(2,270)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	73,664	35,014
Current asset
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	16,510	844
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(80)	(844)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	16,430
Long-term asset
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	2,100	1,426
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(672)	(1,426)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	1,428
Current liability
Offsetting Derivative Liabilities:
Gross Amount of Recognized Liabilities	56,269	32,622
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(80)	(844)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	56,190	31,778
Long-term liability
Offsetting Derivative Liabilities:
Gross Amount of Recognized Liabilities	18,145	4,662
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(672)	(1,426)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	$ 17,474	$ 3,236

Fair Value of Financial Instr67

Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Level 3
Fair Value of Financial Instruments
Derivative instruments	$ 0	$ 0
Recurring basis
Fair Value of Financial Instruments
Investments	25,200	26,800
Total	24,447	435,452
Recurring basis | SNMP
Fair Value of Financial Instruments
Investments	25,227	26,818
Recurring basis | Lonestar
Fair Value of Financial Instruments
Investments	5,955
Recurring basis | Money market funds
Fair Value of Financial Instruments
Cash and cash equivalents	49,071	443,648
Recurring basis | Active Market for Identical Assets (Level 1)
Fair Value of Financial Instruments
Total	80,253	470,466
Recurring basis | Active Market for Identical Assets (Level 1) | SNMP
Fair Value of Financial Instruments
Investments	25,227	26,818
Recurring basis | Active Market for Identical Assets (Level 1) | Lonestar
Fair Value of Financial Instruments
Investments	5,955
Recurring basis | Active Market for Identical Assets (Level 1) | Money market funds
Fair Value of Financial Instruments
Cash and cash equivalents	49,071	443,648
Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Total	(55,806)	(35,014)
Crude oil | Recurring basis | Swaption | Call
Fair Value of Financial Instruments
Derivative instruments	(3,431)
Crude oil | Recurring basis | Swaption | Call | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments	(3,431)
Swaps | Recurring basis
Fair Value of Financial Instruments
Derivative instruments		(8,291)
Swaps | Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments		(8,291)
Swaps | Crude oil | Recurring basis
Fair Value of Financial Instruments
Derivative instruments	66,204	(572)
Swaps | Crude oil | Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments	66,204	(572)
Swaps | Natural gas | Recurring basis
Fair Value of Financial Instruments
Derivative instruments	15,380	(26,151)
Swaps | Natural gas | Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments	15,380	$ (26,151)
Embedded derivatives
Fair Value of Financial Instruments
Net gains / (losses) on derivatives	(1,551)
Sand and coiled tubing contracts | Recurring basis
Fair Value of Financial Instruments
Embedded derivative instruments	(1,551)
Sand and coiled tubing contracts | Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Embedded derivative instruments	$ (1,551)

Fair Value of Financial Instr68

Fair Value of Financial Instruments (Other) (Details) - USD ($) $ in Thousands	Nov. 20, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jun. 27, 2014	Jun. 13, 2013	Mar. 26, 2013	Sep. 17, 2012
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Impairment of proved properties		$ 0	$ 3,700	$ 700,300
Level 3
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Carrying value of impaired proved properties		$ 3,300
7.75% Senior Notes
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%
6.125% Senior Notes
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%
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
Total gains (losses) included in earnings				418
Net settlements on derivative contracts				(14,277)
Derivative contracts transferred to Level 2				(61,664)
Gains (losses) included in earnings related to derivatives still held as of December 31, 2017, 2016, and 2015				(940)
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 | 7.75% Senior Notes | 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		$ 567,000
Recurring basis | 6.125% Senior Notes | 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		$ 974,600
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		0
Conversion ratio (in shares)								2.3250
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		0
Conversion ratio (in shares)							2.3370
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, 2017		Dec. 31, 2016
Changes in the asset retirement obligation
Abandonment liability, beginning of period	$ 25,087	[1]	$ 25,907
Liabilities incurred during period	4,968		1,492
Acquisitions	8,289		219
Divestitures	(3,538)		(4,433)
Revisions	(1,343)		(172)
Accretion expense	2,635		2,074
Abandonment liability, end of period	$ 36,098		$ 25,087	[1]
[1]	* Financial information for 2016 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Accrued Liabilities and Other70

Accrued Liabilities and Other Current Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Accrued Liabilities and Other Current Liabilities.
Capital expenditures	$ 85,340	$ 35,154	[1]
General and administrative costs	8,855	14,738
Production taxes	5,084	2,396
Ad valorem taxes	84	2,756
Lease operating expenses	32,152	23,942
Interest payable	34,632	34,266
Preferred stock dividends and other	3,987	4,360
Total accrued liabilities	170,134	117,612
Revenue payable	75,832	2,124
Production tax payable	2,774
Other	3,364	127
Total other payables	81,970	2,251
Operated prepayment liability	88,999
Deferred gain on Western Catarina Midstream Divestiture - short term	23,720	23,720
Phantom compensation payable - short term	2,525	7,388
Total other current liabilities	$ 115,244	$ 31,108	[1]
[1]	* Financial information for 2016 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Thousands	Dec. 20, 2017USD ($)	Nov. 22, 2016USD ($)	Dec. 16, 2013claim	Dec. 31, 2017USD ($)item	Oct. 06, 2016USD ($)	Jul. 05, 2016USD ($)
Commitments and contingencies
Number of derivative actions filed | claim			3
Litigation settlement, amount from other party				$ 11,750
Litigation settlement, net, amount from other party				5,200
Operating leases
Lease payment obligation				$ 185,700
SR
Commitments and contingencies
Litigation settlement, amount from other party	$ 11,750
Catarina
Commitments and contingencies
Maximum number of wells to be drilled in each annual period | item				50
Minimum number of wells to be drilled in accordance with agreement | 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
Number of wells that can be carried over to satisfy part of the well requirement in the subsequent annual period on a well-for-well basis | item				30
Corporate office Lease
Operating leases
Lease payment obligation				$ 81,100
Acreage Lease
Operating leases
Lease payment obligation				$ 5,000
Term of lease				10 years
Permanent improvements
Operating leases
Lease payment obligation				$ 4,000
Western Catarina Midstream Divestiture
Operating leases
Lease payment obligation				$ 99,600
Carnero Gathering, LLC
Investment
Equity method investment cost					$ 48,000	$ 26,000
Carnero Gathering, LLC | SNMP
Investment
Consideration in cash		$ 55,500
Ownership of investment (as a percent)		50.00%				50.00%
Anadarko E&P Onshore, LLC | The "Comanche Assets"
Commitments and contingencies
Minimum number of wells to be drilled in accordance with agreement | item				60
Number of wells that can be carried over to satisfy part of the well requirement in the subsequent annual period on a well-for-well basis | item				30
Contingent per well default fee				$ 200

Commitments and Contingencies72

Commitments and Contingencies (Volume Commitments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	[1]	Dec. 31, 2015	[1]
Oil and Gas Delivery Commitments and Contracts [Line Items]
Oil and natural gas production expenses	$ 244,461	$ 155,660		$ 154,672
Volume commitments
Oil and Gas Delivery Commitments and Contracts [Line Items]
Future commitments	561,500
Oil and natural gas production expenses	4,800
Volume commitments for 2018 through 2020
Oil and Gas Delivery Commitments and Contracts [Line Items]
Future commitments	222,300
Volume commitments from 2021 through 2023
Oil and Gas Delivery Commitments and Contracts [Line Items]
Future commitments	175,600
Volume commitments expiring after December 31, 2023
Oil and Gas Delivery Commitments and Contracts [Line Items]
Future commitments	163,600
Natural gas | Volume commitments
Oil and Gas Delivery Commitments and Contracts [Line Items]
Future commitments	179,500
Natural gas | Volume commitments for 2018 through 2020
Oil and Gas Delivery Commitments and Contracts [Line Items]
Future commitments	85,900
Natural gas | Volume commitments from 2021 through 2023
Oil and Gas Delivery Commitments and Contracts [Line Items]
Future commitments	31,600
Natural gas | Volume commitments expiring after December 31, 2023
Oil and Gas Delivery Commitments and Contracts [Line Items]
Future commitments	$ 62,000
[1]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Subsidiary Guarantors (Details)

Subsidiary Guarantors (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Jun. 27, 2014	Jun. 13, 2013
Ownership interest in Subsidiaries (as a percent)	100.00%
Amount of independent assets	$ 0
Amount of independent operations	$ 0
7.75% Senior Notes
Ownership interest in Subsidiaries (as a percent)	100.00%
Interest rate (as a percent)	7.75%		7.75%
6.125% Senior Notes
Ownership interest in Subsidiaries (as a percent)	100.00%
Interest rate (as a percent)	6.125%	6.125%

Investments (Details)

Investments (Details) $ in Thousands

Jun. 14, 2017USD ($)

Mar. 01, 2017itemshares

Nov. 22, 2016USD ($)shares

Oct. 06, 2016USD ($)

Jul. 05, 2016USD ($)

Oct. 02, 2015USD ($)Mcf

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

[1]

Jun. 15, 2017shares

Investments in marketable securities

Investment gains (losses) recorded

$ (1,591)

$ 1,818

Gain or loss on equity method investment

(871)

1,818

[1]

$ (935)

Equity method gains (losses)

779

3,466

[2]

Investment in GRHL

7,280

SOII Facility

Investments in marketable securities

Ownership of investment (as a percent)

10.00%

10.00%

Equity method investment cost

12,500

12,500

Gain or loss on equity method investment

$ 0

Equity method gains (losses)

779,000

$ 1,200

Consideration in cash

$ 12,500

Amount committed

$ 12,500

Gas processing plant capacity per day (in MMcf) | Mcf

125,000

Carnero Gathering, LLC

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

Investments in marketable securities

Ownership of investment (as a percent)

50.00%

50.00%

Lonestar

Investments in marketable securities

Investments (in shares or units) | shares

1,500,000

Maximum | Lonestar

Investments in marketable securities

Investment gains (losses) recorded

$ (100)

SNMP | Carnero Gathering, LLC

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

SN Comanche Manager | Class A Units

Investments in marketable securities

Total units authorized for issuance | shares

100

Vesting percentage of class A

20.00%

Number of anniversaries | item

5

Common Stock | Lonestar

Investments in marketable securities

Ownership of investment (as a percent)

6.10%

Common Stock | SNMP

Investments in marketable securities

Investments (in shares or units) | shares

2,272,727

Investments

$ 25,000

Ownership of investment (as a percent)

15.20%

Investment gains (losses) recorded

$ 1,600

[1]

Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

[2]

Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Thousands	Oct. 02, 2015	Dec. 31, 2017	Dec. 31, 2016	Nov. 22, 2016	Dec. 31, 2015
Variable Interest Entity [Line Items]
Equity in investments		$ 32,507	$ 39,656		$ 37,527
SOII Facility
Variable Interest Entity [Line Items]
Ownership interest (as a percent)	10.00%
Common Stock | SNMP
Variable Interest Entity [Line Items]
Investments				$ 25,000
Recurring basis
Variable Interest Entity [Line Items]
Investments		$ 25,200	$ 26,800

Variable Interest Entities (Car

Variable Interest Entities (Carrying Amounts) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Variable Interest Entities
Beginning Balance	$ 39,656	$ 37,527
Investment in GRHL	7,280
Earnings on (distributions from) equity investments	(311)	311
Gain (Loss) from change in fair value of investment in SNMP	(1,591)	1,818
Sale of investments	(12,527)
Equity in investments	32,507	39,656
Maximum exposure to loss	$ 32,507	$ 39,656

Condensed Consolidating Finan77

Condensed Consolidating Financial Information (Details)	Dec. 31, 2017
Condensed Consolidating Financial Information
Ownership interest in Subsidiaries (as a percent)	100.00%

Condensed Consolidating Finan78

Condensed Consolidating Financial Information (BalanceSheet) (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015	[2]	Dec. 31, 2014	[2]
Assets
Total current assets	$ 350,798	$ 562,805	[1]
Total oil and natural gas properties, net	2,027,459	704,519	[1]
Other assets	92,378	64,887
Total assets	2,470,635	1,332,211	[1]
Liabilities and Shareholders' Equity
Current liabilities	462,528	185,904	[1]
Long-term liabilities	2,049,735	1,830,289
Mezzanine equity	427,512		[1]
Total shareholders' equity (deficit)	(469,140)	(683,982)	[1],[2]	$ (559,483)		$ 167,735
Total liabilities and stockholders' equity (deficit)	2,470,635	1,332,211	[1]
Eliminations
Assets
Total current assets	(312,975)	(147,548)
Investment in subsidiaries	(1,074,412)	(734,704)
Total assets	(1,387,387)	(882,252)
Liabilities and Shareholders' Equity
Current liabilities	(312,975)	(147,548)
Total shareholders' equity (deficit)	(1,074,412)	(734,704)
Total liabilities and stockholders' equity (deficit)	(1,387,387)	(882,252)
Parent Company
Assets
Total current assets	447,984	428,384
Total oil and natural gas properties, net	3,987
Investment in subsidiaries	1,081,692	734,704
Other assets	25,451	14,376
Total assets	1,559,114	1,177,464
Liabilities and Shareholders' Equity
Current liabilities	212,026	84,673
Long-term liabilities	1,827,072	1,788,930
Total shareholders' equity (deficit)	(479,984)	(696,139)
Total liabilities and stockholders' equity (deficit)	1,559,114	1,177,464
Combined Guarantor Subsidiaries
Assets
Total current assets	98,758	123,380
Total oil and natural gas properties, net	1,275,153	704,519
Other assets	4,415	15,221
Total assets	1,378,326	843,120
Liabilities and Shareholders' Equity
Current liabilities	312,531	78,344
Long-term liabilities	26,787	25,086
Total shareholders' equity (deficit)	1,039,008	739,690
Total liabilities and stockholders' equity (deficit)	1,378,326	843,120
Combined Non-Guarantor Subsidiaries
Assets
Total current assets	117,031	158,589
Total oil and natural gas properties, net	748,319
Investment in subsidiaries	(7,280)
Other assets	62,512	35,290
Total assets	920,582	193,879
Liabilities and Shareholders' Equity
Current liabilities	250,946	170,435
Long-term liabilities	195,876	16,273
Mezzanine equity	427,512
Total shareholders' equity (deficit)	46,248	7,171
Total liabilities and stockholders' equity (deficit)	$ 920,582	$ 193,879
[1]	* Financial information for 2016 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.
[2]	Financial information for 2016, 2015, and 2014 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Condensed Consolidating Finan79

Condensed Consolidating Financial Information (IncomeStatement) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016		Dec. 31, 2015
Condensed Income Statements, Captions [Line Items]
Total revenues	$ 740,331	$ 431,326	[1]	$ 475,779	[1]
Total operating costs and expenses	(647,884)	(480,643)	[1]	(1,246,034)	[1]
Other income (expense)	(51,591)	(90,344)	[1]	44,324	[1]
Loss before income taxes	40,856	(139,661)	[1]	(725,931)	[1]
Income tax benefit (expense)	2,336	(1,825)	[1]	(158)	[1]
Net income (loss)	43,192	(141,486)	[1]	(726,089)	[1]
Eliminations
Condensed Income Statements, Captions [Line Items]
Total operating costs and expenses	680
Other income (expense)	(680)
Equity in income (loss) of subsidiaries	(193,376)	(33,730)		1,416,657
Net income (loss)	(193,376)	(33,730)		1,416,657
Parent Company
Condensed Income Statements, Captions [Line Items]
Total operating costs and expenses	(92,008)	(111,155)		(75,096)
Other income (expense)	(121,603)	(177,710)		44,726
Loss before income taxes	(213,611)	(288,865)		(30,370)
Income tax benefit (expense)	2,336	(1,825)		(158)
Equity in income (loss) of subsidiaries	193,376	33,730		(1,416,657)
Net income (loss)	(17,899)	(256,960)		(1,447,185)
Combined Guarantor Subsidiaries
Condensed Income Statements, Captions [Line Items]
Total revenues	509,701	431,326		475,779
Total operating costs and expenses	(387,614)	(367,541)		(1,169,246)
Other income (expense)	75,837	82,948		(402)
Loss before income taxes	197,924	146,733		(693,869)
Net income (loss)	197,924	146,733		(693,869)
Combined Non-Guarantor Subsidiaries
Condensed Income Statements, Captions [Line Items]
Total revenues	230,630
Total operating costs and expenses	(168,942)	(1,947)		(1,692)
Other income (expense)	(5,145)	4,418
Loss before income taxes	56,543	2,471		(1,692)
Net income (loss)	$ 56,543	$ 2,471		$ (1,692)
[1]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Condensed Consolidating Finan80

Condensed Consolidating Financial Information (CashFlows) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities		$ 292,089		$ 182,754	[1]	$ 270,576	[1]
Net cash provided by (used in) investing activities		(1,382,800)		(108,234)	[1]	(292,349)	[1]
Net cash provided by (used in) financing activities		773,228		(7,651)	[1]	(16,893)	[1]
Increase (decrease) in cash and cash equivalents		(317,483)		66,869	[1]	(38,666)	[1]
Cash and cash equivalents, beginning of period	[1]	501,917	[2]	435,048		473,714
Cash and cash equivalents, end of period		184,434		501,917	[1],[2]	435,048	[1]
Eliminations
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) investing activities		264,626		16,209		(26,490)
Net cash provided by (used in) financing activities		(264,626)		(16,209)		26,490
Parent Company
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities		(148,259)		(36,741)		(43,556)
Net cash provided by (used in) investing activities		(266,135)		(46,602)		21,670
Net cash provided by (used in) financing activities		157,390		(7,650)		(16,894)
Increase (decrease) in cash and cash equivalents		(257,004)		(90,993)		(38,780)
Cash and cash equivalents, beginning of period		343,941		434,934		473,714
Cash and cash equivalents, end of period		86,937		343,941		434,934
Combined Guarantor Subsidiaries
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities		346,345		218,864		315,516
Net cash provided by (used in) investing activities		(620,382)		(133,412)		(247,202)
Net cash provided by (used in) financing activities		303,083		(85,452)		(68,314)
Increase (decrease) in cash and cash equivalents		29,046
Cash and cash equivalents, end of period		29,046
Combined Non-Guarantor Subsidiaries
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities		94,003		631		(1,384)
Net cash provided by (used in) investing activities		(760,909)		55,571		(40,327)
Net cash provided by (used in) financing activities		577,381		101,660		41,825
Increase (decrease) in cash and cash equivalents		(89,525)		157,862		114
Cash and cash equivalents, beginning of period		157,976		114
Cash and cash equivalents, end of period		$ 68,451		$ 157,976		$ 114
[1]	Financial information for 2016 and 2015 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.
[2]	* Financial information for 2016 has been recast to reflect retrospective application of the successful efforts method of accounting. See Note 3.

Subsequent Events (Details)

Subsequent Events (Details) - USD ($) shares in Millions	Feb. 14, 2018	Jun. 15, 2017	Dec. 31, 2017	Sep. 12, 2014	Jul. 18, 2014	Jun. 27, 2014	Jun. 18, 2014	Sep. 18, 2013	Jun. 13, 2013
Subsequent Events
Equity interest			100.00%
Lonestar | Marquis Disposition
Subsequent Events
Consideration in common stock (in shares)		1.5
7.25% Senior Notes
Subsequent Events
Threshold of allowed hedging			$ 10,000,000
6.125% Senior Notes
Subsequent Events
Interest rate (as a percent)			6.125%			6.125%
Face value of debt			$ 1,150,000,000	$ 300,000,000
Redemption price of debt instrument (as a percent)			100.00%
7.75% Senior Notes
Subsequent Events
Interest rate (as a percent)			7.75%						7.75%
Face value of debt					$ 600,000,000		$ 600,000,000	$ 200,000,000	$ 400,000,000
Prior to February 15, 2020 | 7.25% Senior Notes
Subsequent Events
Redemption price of debt instrument (as a percent)			107.25%
Subsequent Events | 7.25% Senior Notes
Subsequent Events
Interest rate (as a percent)	7.25%
Face value of debt	$ 500,000,000
Redemption price of debt instrument (as a percent)	100.00%
Number of days of default in interest payment	30 days
Number of days of delay to comply with obligations to repurchase debt	30 days
Number of days of delay to comply with reporting obligations	180 days
Number of days of delay to comply with any other agreement in indenture	60 days
Maximum borrowing capacity	$ 50,000,000
Number of days of failure to make priority lien enforceble	45 days
Subsequent Events | 6.125% Senior Notes
Subsequent Events
Interest rate (as a percent)	6.125%
Third Amended And Restated Credit Agreement | Subsequent Events
Subsequent Events
Maximum borrowing capacity	$ 25,000,000
Excess of PV10 value to calculate PDP coverage ratio	$ 10,000,000
Percentage of commitment fee on the unused committed amount	0.50%
Third Amended And Restated Credit Agreement | Subsequent Events | 7.25% Senior Notes
Subsequent Events
Face value of debt	$ 25,000,000
Third Amended And Restated Credit Agreement | Subsequent Events | 7.75% Senior Notes
Subsequent Events
Interest rate (as a percent)	7.75%
Minimum | Subsequent Events
Subsequent Events
Percentage of debt instrument redeem under certain circumstances	35.00%
Minimum | Subsequent Events | 7.25% Senior Notes
Subsequent Events
Minimum principal amount outstanding	$ 40,000,000
Percentage of principal amount held by holders	25.00%
Minimum | Third Amended And Restated Credit Agreement | Subsequent Events
Subsequent Events
PDP Coverage ratio	4
Alternate base rate | Minimum | Third Amended And Restated Credit Agreement | Subsequent Events
Subsequent Events
Variable rate basis, spread percentage	1.50%
Alternate base rate | Maximum | Third Amended And Restated Credit Agreement | Subsequent Events
Subsequent Events
Variable rate basis, spread percentage	2.25%
Eurodollar rate | Minimum | Third Amended And Restated Credit Agreement | Subsequent Events
Subsequent Events
Variable rate basis, spread percentage	2.50%
Eurodollar rate | Maximum | Third Amended And Restated Credit Agreement | Subsequent Events
Subsequent Events
Variable rate basis, spread percentage	3.25%