Sanchez Energy (SNECQ) 10-Q 9 May 16 2016 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	May. 06, 2016
Document and Entity Information
Entity Registrant Name	Sanchez Energy Corp
Entity Central Index Key	1,528,837
Document Type	10-Q
Document Period End Date	Mar. 31, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		65,220,112
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 362,221	$ 435,048
Oil and natural gas receivables	33,596	30,668
Joint interest billings receivables	547	1,259
Accounts receivable - related entities	3,636	3,697
Fair value of derivative instruments	136,479	172,494
Other current assets	22,043	23,452
Total current assets	558,522	666,618
Oil and natural gas properties, at cost, using the full cost method:
Unproved oil and natural gas properties	281,106	253,529
Proved oil and natural gas properties	2,978,732	2,914,867
Total oil and natural gas properties	3,259,838	3,168,396
Less: Accumulated depreciation, depletion, amortization and impairment	(2,480,381)	(2,412,293)
Total oil and natural gas properties, net	779,457	756,103
Other assets:
Debt issuance costs, net	125
Fair value of derivative instruments	5,299	5,789
Investments	55,721	49,985
Other assets	22,079	22,809
Total assets	1,421,203	1,501,304
Current liabilities:
Accounts payable	1,600	4,184
Other payables	1,599	2,004
Accrued liabilities:
Capital expenditures	57,580	51,983
Other	60,570	69,974
Deferred premium liability	20,523	24,548
Other current liabilities	14,921	14,813
Total current liabilities	156,793	167,506
Long term debt, net of premium, discount and debt issuance costs	1,706,367	1,705,927
Asset retirement obligations	26,467	25,907
Other liabilities	54,699	58,133
Total liabilities	$ 1,944,326	$ 1,957,473
Commitments and Contingencies (Note 16)
Stockholders' equity:
Preferred stock ($0.01 par value, 15,000,000 shares authorized; 1,838,985 shares issued and outstanding as of March 31, 2016 and December 31, 2015 of 4.875% Convertible Perpetual Preferred Stock, Series A; 3,527,830 shares issued and outstanding as of March 31, 2016 and December 31, 2015 of 6.500% Convertible Perpetual Preferred Stock, Series B)	$ 53	$ 53
Common stock ($0.01 par value, 150,000,000 shares authorized; 64,296,945 and 61,928,089 shares issued and outstanding as of March 31, 2016 and December 31, 2015, respectively)	646	619
Additional paid-in capital	1,082,293	1,079,513
Accumulated deficit	(1,606,115)	(1,536,354)
Total stockholders’ deficit	(523,123)	(456,169)
Total liabilities and stockholders’ deficit	$ 1,421,203	$ 1,501,304

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	15,000,000	15,000,000
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	64,296,945	61,928,089
Common stock, shares outstanding	64,296,945	61,928,089
Preferred Class A
Preferred stock, shares issued	1,838,985	1,838,985
Preferred stock, shares outstanding	1,838,985	1,838,985
Dividend rate (as a percent)	4.875%	4.875%
Preferred Class B
Preferred stock, shares issued	3,527,830	3,527,830
Preferred stock, shares outstanding	3,527,830	3,527,830
Dividend rate (as a percent)	6.50%	6.50%

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
REVENUES:
Oil sales	$ 42,682	$ 75,524
Natural gas liquid sales	15,045	13,853
Natural gas sales	22,089	21,216
Total revenues	79,816	110,593
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses	44,693	34,163
Production and ad valorem taxes	3,943	8,670
Depreciation, depletion, amortization and accretion	46,965	102,657
Impairment of oil and natural gas properties	22,084	441,450
General and administrative (inclusive of stock-based compensation expense of $3,344 and $7,694, respectively, for the three months ended March 31, 2016 and 2015)	19,480	21,477
Total operating costs and expenses	137,165	608,417
Operating loss	(57,349)	(497,824)
Other income (expense):
Interest income and other expense	(88)	(1,824)
Interest expense	(31,606)	(31,558)
Earnings from equity investments	512
Net gains on commodity derivatives	22,757	41,303
Total other income (expense)	(8,425)	7,921
Income (loss) before income taxes	(65,774)	(489,903)
Income tax expense		7,442
Net loss	(65,774)	(497,345)
Less:
Preferred stock dividends	(3,987)	(3,991)
Net income allocable to participating securities	0	0
Net loss attributable to common stockholders	$ (69,761)	$ (501,336)
Net loss per common share - basic and diluted (in dollars per share)	$ (1.20)	$ (8.83)
Weighted average number of shares used to calculate net loss attributable to common stockholders - basic and diluted (in shares)	58,099	56,805

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Condensed Consolidated Statements of Operations
General and administrative, stock-based compensation expense (in dollars)	$ 3,344	$ 7,694

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Stockholders' Equity (Deficit) - 3 months ended Mar. 31, 2016 - USD ($) shares in Thousands, $ in Thousands	Preferred Class A	Preferred Class B	Common Stock	Additional Paid-in Capital	Accumulated Deficit	Total
Balance at Dec. 31, 2015	$ 18	$ 35	$ 619	$ 1,079,513	$ (1,536,354)	$ (456,169)
Balance (in shares) at Dec. 31, 2015	1,839	3,528	61,928
Increase (Decrease) in Stockholders' Equity (Deficit)
Preferred stock dividends					(3,987)	(3,987)
Restricted stock awards, net of forfeitures			$ 27	(27)
Restricted stock awards, net of forfeitures (in shares)			2,369
Stock-based compensation				2,807		2,807
Net loss					(65,774)	(65,774)
Balance at Mar. 31, 2016	$ 18	$ 35	$ 646	$ 1,082,293	$ (1,606,115)	$ (523,123)
Balance (in shares) at Mar. 31, 2016	1,839	3,528	64,297

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (65,774)	$ (497,345)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	46,965	102,657
Impairment of oil and natural gas properties	22,084	441,450
Stock-based compensation expense	3,344	7,694
Net gains on commodity derivative contracts	(22,757)	(41,303)
Net cash settlement received on commodity derivative contracts	50,221	29,355
Losses incurred on premiums for derivative contracts	6,103	121
Amortization of deferred gain on Western Catarina Midstream Divestiture	(3,703)
Amortization of debt issuance costs	1,915	1,815
Accretion of debt discount, net	158	227
Deferred taxes		7,442
Loss on inventory market adjustment	478
Earnings from equity investments	(512)
Changes in operating assets and liabilities:
Accounts receivable	(2,216)	29,922
Other current assets	322	873
Accounts payable	(2,584)	(4,168)
Accounts receivable - related entities	61	(2,847)
Other payables	(405)	566
Accrued liabilities	(9,404)	(8,660)
Other current liabilities	(159)	(5,166)
Other liabilities		1,167
Net cash provided by operating activities	24,137	63,800
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for oil and natural gas properties	(85,767)	(270,584)
Payments for other property and equipment	(228)	828
Proceeds from sale of oil and natural gas properties		81,958
Acquisition of oil and natural gas properties		13
Payments for investments	(5,224)
Net cash used in investing activities	(91,219)	(187,785)
CASH FLOWS FROM FINANCING ACTIVITIES:
Financing costs	(1,758)	(400)
Preferred dividends paid	(3,987)	(3,991)
Net cash used in financing activities	(5,745)	(4,391)
Decrease in cash and cash equivalents	(72,827)	(128,376)
Cash and cash equivalents, beginning of period	435,048	473,714
Cash and cash equivalents, end of period	362,221	345,338
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in asset retirement obligations	78	979
Change in accrued capital expenditures	5,597	(58,068)
Purchase of oil and natural gas properties in exchange for common stock		7,520
SUPPLEMENTAL DISCLOSURE:
Cash paid for taxes	160
Cash paid for interest	$ 35,517	$ 38,978

Organization

Organization	3 Months Ended
	Mar. 31, 2016
Organization
Organization	Note 1. Organization Sanchez Energy Corporation (together with our consolidated subsidiaries, 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 unconventional oil and natural gas resources in the onshore U.S. Gulf Coast, with a current focus on the Eagle Ford Shale in South Texas and the Tuscaloosa Marine Shale (“TMS”) in Mississippi and Louisiana. We have accumulated net leasehold acreage in the oil and condensate, or black oil and volatile oil, windows of the Eagle Ford Shale and in what we believe to be the core of the TMS. We are currently focused on the horizontal development of significant resource potential from the Eagle Ford Shale.

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2016
Basis of Presentation and Summary of Significant Accounting Policies
Basis of Presentation and Summary of Significant Accounting Policies	Note 2. Basis of Presentation and Summary of Significant Accounting Policies The accompanying condensed consolidated financial statements are unaudited and were prepared from the Company’s records. The condensed consolidated financial statements were prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP” or “U.S. GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. The Company derived the condensed consolidated balance sheet as of December 31, 2015 from the audited financial statements filed in its Annual Report on Form 10-K for the fiscal year ended December 31, 2015 (the “2015 Annual Report”). Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by U.S. GAAP. These condensed consolidated financial statements should be read in connection with the consolidated financial statements and notes thereto included in the 2015 Annual Report, which contains a summary of the Company’s significant accounting policies and other disclosures. In the opinion of management, these financial statements include the adjustments and accruals, all of which are of a normal recurring nature, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results to be expected for the entire year. As of March 31, 2016, the Company’s significant accounting policies are consistent with those discussed in Note 2, “Basis of Presentation and Summary of Significant Accounting Policies,” in the notes to the Company’s consolidated financial statements contained in its 2015 Annual Report. Principles of Consolidation The Company’s condensed consolidated financial statements include the accounts of the Company and its subsidiaries. All intercompany balances and transactions have been eliminated. Use of Estimates The condensed 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 calculation of depletion and impairment of oil and natural gas properties, the evaluation of unproved properties for impairment, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates. Recent Accounting Pronouncements In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018, with a modified retrospective approach to be used for implementation. ASU 2016-02 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 those leases previously classified as operating leases under the old guidance. In addition, ASU 2016-02 updates the criteria for a lessee’s classification of a finance lease. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In April 2015, the FASB issued ASU 2015-03, “Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” This guidance is intended to more closely align the presentation of debt issuance costs under U.S. GAAP with the presentation requirements under the International Financial Reporting Standards. Under this new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented. This guidance is effective for fiscal years and interim periods beginning after December 15, 2015. During the first quarter 2016, the Company adopted ASU 2015-03 retrospectively to the comparable periods in this Form 10-Q. Adoption of this guidance affected the balance sheets as of December 31, 2015 as follows (in thousands): Decrease in Long term debt, net of premium, discount and debt issuance costs of approximately $41,039 Decrease in Debt issuance costs, net (Other Assets) of approximately $41,039 In February 2015, the FASB issued ASU 2015-02, “Consolidation—Amendments to the Consolidation Analysis.” This ASU will simplify existing requirements by reducing the number of acceptable consolidation models and placing more emphasis on risk of loss when determining a controlling financial interest. The provisions of this new standard will affect how limited partnerships and similar entities are assessed for consolidation, including the elimination of the presumption that a general partner should consolidate a limited partnership. This guidance is effective for fiscal years and interim periods beginning in 2016. During the first quarter 2016, the Company adopted ASU 2015-02 retrospectively to the comparable periods in this Form 10-Q. See further disclosure around the adoption of ASU 2015-02, and the impact on the Company’s consolidated financial statements in Note 19, “Variable Interest Entities.” In July 2015, FASB issued ASU No. 2015-11, “ Simplifying the Measurement of Inventory ,” effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is not permitted. The guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material.

Acquisitions and Divestitures

Acquisitions and Divestitures	3 Months Ended
	Mar. 31, 2016
Acquisitions and Divestitures
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures Our acquisitions are accounted for under the acquisition method of accounting in accordance with Accounting Standards Codification (“ASC”) Topic 805, “Business Combinations.” 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 condensed consolidated financial statements since the closing dates of the acquisitions. Catarina Acquisition On June 30, 2014, we completed our acquisition of contiguous acreage in Dimmit, LaSalle and Webb Counties, Texas with 176 gross producing wells ( the “Catarina Acquisition”) for an aggregate adjusted purchase price of $557. 1 million. The effective date of the transaction was January 1, 2014. The purchase price was funded with a portion of the proceeds from the Original 6.125% Notes (as defined below in Note 6, “Long-Term Debt”) and cash on hand. The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands): Proved oil and natural gas properties $ Unproved properties Other assets acquired Fair value of assets acquired Asset retirement obligations Fair value of net assets acquired $ Palmetto Disposition On March 31, 2015, we sold escalating working interests in 59 wellbores located in Gonzales County, Texas to a subsidiary of SPP for an adjusted purchase price of approximately $83.4 million (the “Palmetto Disposition”). The effective date of the transaction was January 1, 2015. The aggregate average working interest percentage initially conveyed was 18.25% per wellbore and, upon January 1 of each subsequent year after the closing, the purchaser’s working interest will automatically increase in incremental amounts according to the purchase agreement until January 1, 2019, at which point the purchaser will own a 47.5% working interest and we will own a 2.5% working interest in each of the wellbores. We received consideration consisting of approximately $83.0 million (approximately $81.4 million as adjusted) cash and 1,052,632 common units of SPP valued at approximately $2.0 million as of the date of the closing (as discussed further in Note 8, “Investments”). The Company did not record any gains or losses related to the Palmetto Disposition. On August 4, 2015, the common units of SPP were subject to a 1 -for-10 reverse split, at which time we owned 105,263 common units of SPP. 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 date, owned certain midstream gathering and processing assets located in Dimmit County and Webb County, Texas and 105,263 common units of SPP, to SPP for an adjusted purchase price of $345.8 million in cash (the “Western Catarina Midstream Divestiture”). In connection with the closing of the Western Catarina Midstream Divestiture, SN Catarina and Catarina Midstream entered into a Firm Gathering and Processing Agreement effective October 14, 2015 (the “Gathering Agreement”) for an initial term of 15 years pursuant to which production from approximately 35,000 acres that we operate in Dimmit County and Webb County, Texas will be dedicated for gathering by Catarina Midstream, LLC (“Catarina Midstream”). In addition, for the first five years of the Gathering Agreement, SN Catarina will be required to meet a minimum quarterly volume delivery commitment of 10,200 barrels per day of crude oil and condensate and 142,000 Mcf per day of natural gas, subject to certain adjustments. SN Catarina will be required to pay gathering and processing fees of $0.96 per barrel for crude oil and condensate and $0.74 per Mcf for natural gas that are tendered through the gathering system, in each case, subject to an annual escalation for a positive increase in the consumer price index. In addition, SN Catarina has, under certain circumstances, a right of first refusal during the term of the Gathering Agreement and afterwards with respect to dispositions by Catarina Midstream of its ownership interest in the gathering system. The Company recorded a deferred gain of approximately $74.1 million as a result of Gathering Agreement being accounted for as an operating lease. This deferred gain will be amortized straight-line over the firm commitment term of five years as an offset to the transportation fees paid to SPP under the Gathering Agreement.

Cash and Cash Equivalents

Cash and Cash Equivalents	3 Months Ended
	Mar. 31, 2016
Cash and Cash Equivalents
Cash and Cash Equivalents	Note 4. Cash and Cash Equivalents As of March 31, 2016 and December 31, 2015, cash and cash equivalents consisted of the following (in thousands): March 31, December 31, 2016 2015 Cash at banks $ $ Money market funds Total cash and cash equivalents $ $

Oil and Natural Gas Properties

Oil and Natural Gas Properties	3 Months Ended
	Mar. 31, 2016
Oil and Natural Gas Properties
Oil and Natural Gas Properties	Note 5. Oil and Natural Gas Properties The Company’s oil and natural gas properties are accounted for using the full cost method of accounting. All direct costs and certain indirect costs associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Once evaluated, these costs, as well as the estimated costs to retire the assets, are included in the amortization base and amortized to depletion expense using the units ‑of ‑production method. Depletion is calculated based on estimated proved oil and natural gas reserves. Proceeds from the sale or disposition of oil and natural gas properties are applied to reduce net capitalized costs unless the sale or disposition causes a significant change in the relationship between costs and the estimated quantity of proved reserves. Full Cost Ceiling Test— Capitalized costs (net of accumulated depreciation, depletion and amortization and deferred income taxes) of proved oil and natural gas properties are subject to a full cost ceiling limitation. The ceiling limits these costs to an amount equal to the present value, discounted at 10% , of estimated future net cash flows from estimated proved reserves less estimated future operating and development costs, abandonment costs (net of salvage value) and estimated related future income taxes. In accordance with SEC rules, the oil and natural gas prices used to calculate the full cost ceiling are the 12-month average prices, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements. Prices are adjusted for “basis” or location differentials. Prices are held constant over the life of the reserves. If unamortized costs capitalized within the cost pool exceed the ceiling, the excess is charged to expense and separately disclosed during the period in which the excess occurs. Amounts thus required to be written off are not reinstated for any subsequent increase in the cost center ceiling. During the three month period ended March 31, 2016, the Company recorded a full cost ceiling test impairment after income taxes of $22.1 million. Based on a current expectation that prices will remain unfavorable during the first half of 2016 based upon the current NYMEX forward prices, absent a material addition to proved reserves and/or a material reduction in future development costs, we believe that there is a reasonable likelihood that the Company will incur additional impairments to our full cost pool in 2016. The Company recorded impairment expense of $441.5 million for the three month period ended March 31, 2015. Costs associated with unproved properties and properties under development, including costs associated with seismic data, leasehold acreage and the current drilling of wells, are excluded from the full cost amortization base until the properties have been evaluated. 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 when management determines that a project area has been evaluated through drilling operations or a thorough geologic evaluation, the project area is transferred into the full cost pool subject to amortization. The Company assesses the carrying value of its unproved properties that are not subject to amortization for impairment periodically. If the results of an assessment indicate that the properties are impaired, the amount of the asset impaired is added to the full cost pool subject to both periodic amortization and the ceiling test.

Long-Term Debt

Long-Term Debt	3 Months Ended
	Mar. 31, 2016
Long-Term Debt
Long-Term Debt	Note 6. Long ‑Term Debt Long-term debt on March 31, 2016, consisted of $1.15 billion face value of 6.125% senior notes (consisting of $850 million in Original 6.125% Notes (defined below) and $300 million in Additional 6.125% Notes (defined below), which were issued at a premium to face value of $2.3 million) maturing on January 15, 2023, and $600 million principal amount of 7.75% senior notes (consisting of $400 million in Original 7.75% Notes (defined below) and $200 million in Additional 7.75% Notes (defined below), which were issued at a discount to face value of $7.0 million), maturing on June 15, 2021. During the first quarter 2016, the Company adopted ASU 2015-03 retrospectively to the comparable periods in this Form 10-Q. Adoption of this guidance affected the balance sheets as of December 31, 2015 as follows (in thousands): Decrease in Long term debt, net of premium, discount and debt issuance costs of approximately $41,039 Decrease in Debt issuance costs, net (Other Assets) of approximately $41,039 As of March 31, 2016, and December 31, 2015, the Company’s long ‑term debt consisted of the following: Amount Outstanding (in thousands) as of March 31, December 31, Interest Rate Maturity date 2016 2015 Second Amended and Restated Credit Agreement Variable June 30, 2019 $ — $ — 7.75% Notes 7.75% June 15, 2021 6.125% Notes 6.125% January 15, 2023 Unamortized discount on Additional 7.75% Notes Unamortized premium on Additional 6.125% Notes Unamortized debt issuance costs Total long-term debt $ $ The components of interest expense are (in thousands): Three Months Ended March 31, 2016 2015 Interest on Senior Notes $ $ Interest expense and commitment fees on credit agreement Amortization of debt issuance costs Amortization of discount on Additional 7.75% Notes Amortization of premium on Additional 6.125% Notes Total interest expense $ $ Credit Facility Previous Credit Agreement: On May 31, 2013, we and our subsidiaries, SEP Holdings III, LLC (“SEP III”), SN Marquis LLC (“SN Marquis”) and SN Cotulla Assets, LLC (“SN Cotulla”), collectively, as the borrowers, entered into a revolving credit facility represented by a $500 million Amended and Restated Credit Agreement with Royal Bank of Canada as the administrative agent, Capital One, National Association as the syndication agent and RBC Capital Markets as sole lead arranger and sole book runner and each of the other lenders party thereto (the “Amended and Restated Credit Agreement”). The Amended and Restated Credit Agreement was to mature on May 31, 2018. On May 12, 2014, the Company borrowed $100 million under the Amended and Restated Credit Agreement. The Company used proceeds from the issuance of the Original 6.125% Notes to repay the $100 million outstanding. Second Amended and Restated Credit Agreement : On June 30, 2014, the Company, as borrower, and SEP III, SN Marquis, SN Cotulla, SN Operating, LLC, SN TMS, LLC and SN Catarina, LLC as loan parties, entered into a revolving credit facility represented by a $1.5 billion Second Amended and Restated Credit Agreement with Royal Bank of Canada as the administrative agent, Capital One, National Association as the syndication agent, Compass Bank and SunTrust Bank as co-documentation agents, RBC Capital Markets as sole lead arranger and sole book runner and the lenders party thereto (together with all subsequent amendments, the ‘‘Second Amended and Restated Credit Agreement’’). The Company has elected an available commitment amount under the Second Amended and Restated Credit Agreement of $300 million. Additionally, the Second Amended and Restated Credit Agreement provides for the issuance of letters of credit, limited in the aggregate to the lesser of $80 million and the total availability thereunder. As of March 31, 2016, there were no borrowings and no letters of credit outstanding under the Second Amended and Restated Credit Agreement, which had a borrowing base of $350 million. Availability under the Second Amended and Restated Credit Agreement is at all times subject to customary conditions and the then applicable borrowing base and aggregate elected commitment amount. All of the $300 million aggregate elected commitment amount was available for future revolver borrowings as of March 31, 2016. The Second Amended and Restated Credit Agreement matures on June 30, 2019. The borrowing base under the Second Amended and Restated Credit Agreement is redetermined semi-annually by the lenders based on, among other things, an evaluation of the Company’s and its restricted subsidiaries’ oil and natural gas reserves. Semi-annual redeterminations of the borrowing base are generally scheduled to occur on or before April 1 and October 1 of each year. The borrowing base is also subject to (i) automatic reduction by 25% of the amount of any increase in the aggregate amount of the Company’s high yield debt and second lien debt, other than high yield or second lien debt issued in exchange for or to refinance existing high yield debt, permitted second lien debt incurred to refinance or replace permitted second lien debt, and permitted second lien debt representing the payment of interest in kind, (ii) interim redetermination at the election of the Company once between each scheduled redetermination, (iii) interim redetermination at the election of a majority of the lenders once between each scheduled redetermination, and (iv) if the required lenders so direct, in connection with asset sales and swap terminations during the period since the most recent borrowing base determination with a combined borrowing base value of more than 10% of the value of the proved developed oil and gas properties included in the most recent reserve report, a reduction in an amount equal to the borrowing base value, as determined by the administrative agent in its reasonable judgment, of such assets and swaps. The Company’s obligations under the Second Amended and Restated Credit Agreement are secured by a first priority lien on substantially all of the Company’s assets and the assets of its existing and future subsidiaries other than subsidiaries designated as “unrestricted subsidiaries”, including a first priority lien on all ownership interests in existing and future subsidiaries, other than subsidiaries (other than the SPV, as defined below) designated as “unrestricted subsidiaries”. The obligations under the Second Amended and Restated Credit Agreement are guaranteed by all of the Company’s existing and future subsidiaries not designated as ‘‘unrestricted subsidiaries.’’ At the Company’s election, borrowings under the Second Amended and Restated Credit Agreement may be made on an alternate base rate or an adjusted eurodollar rate basis, plus an applicable margin. The applicable margin varies from 1.00% to 2.00% for alternate base rate borrowings and from 2.00% to 3.00% for eurodollar borrowings and letters of credit, if any, depending on the utilization of the borrowing base. The Company is also required to pay a commitment fee of 0.50% per annum on any unused aggregate elected commitment amount. The Second Amended and Restated Credit Agreement contains various affirmative and negative covenants and events of default that limit the Company’s ability to, among other things, incur indebtedness, make restricted payments, grant liens, consolidate or merge, dispose of certain assets, make certain investments, engage in transactions with affiliates, hedge transactions and make certain acquisitions. The Second Amended and Restated Credit Agreement also provides for cross default between the Second Amended and Restated Credit Agreement and the other debt (including debt under the 6.125% Notes and the 7.75% Notes) and obligations in respect of hedging agreements (on a mark-to-market basis), of the Company and its restricted subsidiaries, in an aggregate principal amount in excess of $10 million. Furthermore, the Second Amended and Restated Credit Agreement contains financial covenants that require the Company to satisfy the following tests: (i) current assets plus undrawn borrowing capacity on the Second Amended and Restated Credit Agreement to current liabilities of at least 1.0 to 1.0 at all times, and (ii) net first lien debt (defined as the excess of first lien debt over cash) to consolidated last twelve months EBITDA of not greater than 2.00 to 1.0 as of the last day of any fiscal quarter. As of March 31, 2016, the Company was in compliance with the covenants of the Second Amended and Restated Credit Agreement. The Second Amended and Restated Credit Amendment, among other things, also (a) permits the repurchase by the Company and its restricted subsidiaries, or by a special purpose unrestricted subsidiary of the Company (the “SPV”), of the Company’s senior unsecured notes and common and preferred equity securities, from cash in excess of lender credit exposure in an aggregate amount up to approximately $298.5 million subject to certain caps on purchases of the Company’s common and preferred equity securities and other limitations; (b) permits (i) the formation and capitalization of the SPV with up to $150 million, (ii) the SPV to purchase, hold and dispose of, including by way of distribution to its immediate parent, up to $150 million of the Company’s senior unsecured notes and common and preferred equity securities, (iii) the SPV to hold cash received from its immediate parent in a deposit account maintained with a lender under the Second Amended and Restated Credit Agreement, and (iv) the SPV to distribute cash to its immediate parent; (c) requires (i) the Company to cause the SPV to distribute all cash held by it or in its name as of the close of business on December 31, 2016 to its immediate parent, (ii) the equity interests in the SPV to be pledged in favor of the secured parties, (iii) the closing of deposit, securities and commodity accounts maintained by the Company with persons other than lenders or affiliates of lenders under the Second Amended and Restated Credit Agreement, and (iv) the Company to enter into account control agreements in favor of the administrative agent for the benefit of the secured parties in respect of each of the Company’s deposit, securities and commodity accounts; (d) provides that, in the event of a borrowing base deficiency, the Company shall use unrestricted cash of the Company and its subsidiaries in excess of $35 million to prepay borrowings and cash collateralize letter of credit exposure, as applicable; and (f) restricts the Company from increasing its aggregate elected commitment amount until the lenders’ next regularly scheduled borrowing base redetermination, which is expected to occur in the fourth quarter 2016. From time to time, the agents, arrangers, book runners and lenders under the Second Amended and Restated Credit Agreement and their affiliates have provided, and may provide in the future, investment banking, commercial lending, hedging and financial advisory services to the Company and its affiliates in the ordinary course of business, for which they have received, or may in the future receive, customary fees and commissions for these transactions. 7.75% Senior Notes Due 2021 On June 13, 2013, we completed a private offering of $400 million in aggregate principal amount of the Company’s 7.75% senior notes that will mature on June 15, 2021 (the “Original 7.75% Notes”). Interest on the notes is payable on each June 15 and December 15. We received net proceeds from this offering of approximately $388 million, after deducting initial purchasers’ discounts and offering expenses, which we used to repay outstanding indebtedness under our credit facilities. The Original 7.75% Notes are senior unsecured obligations and are guaranteed on a joint and several senior unsecured basis by, with certain exceptions, substantially all of our existing and future subsidiaries. On September 18, 2013, we issued an additional $200 million in aggregate principal amount of our 7.75% senior notes due 2021 (the “Additional 7.75% Notes” and, together with the Original 7.75% Notes, the “7.75% Notes”) in a private offering at an issue price of 96.5% of the principal amount of the Additional 7.75% Notes. We received net proceeds of $188.8 million (after deducting the initial purchasers’ discounts and offering expenses of $4.2 million) from the sale of the Additional 7.75% Notes. The Company also received cash for accrued interest from June 13, 2013 through the date of issuance of $4.1 million, for total net proceeds of $192.9 million from the sale of the Additional 7.75% Notes. The Additional 7.75% Notes were issued under the same indenture as the Original 7.75% Notes, and are, therefore, treated as a single class of securities under the indenture. We used the net proceeds from the offering to partially fund our acquisition of contiguous acreage in McMullen County, Texas with 13 gross producing wells (the “Wycross Acquisition”) completed in October 2013, a portion of the 2013 and 2014 capital budgets and for general corporate purposes. The 7.75% Notes are senior unsecured obligations and rank equally in right of payment with all of our existing and future senior unsecured indebtedness. The 7.75% Notes rank senior in right of payment to our future subordinated indebtedness. The 7.75% Notes are effectively junior in right of payment to all of our existing and future secured debt (including under our Second Amended and Restated Credit Agreement) to the extent of the value of the assets securing such debt. The 7.75% Notes are fully and unconditionally guaranteed (except for customary release provisions) on a joint and several senior unsecured basis by the subsidiary guarantors party to the indenture governing the 7.75% Notes. To the extent set forth in the indenture governing the 7.75% Notes, certain of our subsidiaries will be required to fully and unconditionally guarantee the 7.75% Notes on a joint and several senior unsecured basis in the future. The indenture governing the 7.75% Notes, among other things, restricts our ability and our restricted subsidiaries’ ability to: (i) incur, assume, or guarantee additional indebtedness or issue certain types of equity securities; (ii) pay distributions on, purchase or redeem shares or purchase or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create or incur liens on their assets; (vi) sell assets; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) restrict distributions or other payments from the Company’s restricted subsidiaries; and (ix) designate subsidiaries as unrestricted subsidiaries. We have the option to redeem all or a portion of the 7.75% Notes at any time on or after June 15, 2017 at the applicable redemption prices specified in the indenture plus accrued and unpaid interest. We may also redeem the 7.75% Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make whole premium, together with accrued and unpaid interest and additional interest, if any, to the redemption date, at any time prior to June 15, 2017. In addition, we may redeem up to 35% of the 7.75% Notes prior to June 15, 2016 under certain circumstances with an amount not greater than the net cash proceeds of one or more equity offerings at the redemption price specified in the indenture. We may also be required to repurchase the 7.75% Notes upon a change of control or if we sell certain of our assets. On July 18, 2014, we completed an exchange offer of $600 million aggregate principal amount of the 7.75% Notes that had been registered under the Securities Act of 1933, as amended (the “Securities Act”), for an equal amount of the 7.75% Notes that had not been registered under the Securities Act. 6.125% Senior Notes Due 2023 On June 27, 2014, the Company completed a private offering of $850 million in aggregate principal amount senior unsecured 6.125% notes due 2023 (the “Original 6.125% Notes”). Interest on the notes is payable on each July 15 and January 15. The Company received net proceeds from this offering of approximately $829 million, after deducting initial purchasers’ discounts and estimated offering expenses, which the Company used to repay all of the $100 million in borrowings outstanding under its Amended and Restated Credit Agreement and to finance a portion of the purchase price of the Catarina Acquisition. We used the remaining proceeds from the offering to fund a portion of the remaining 2014 capital budget and for general corporate purposes. The Original 6.125% Notes are the senior unsecured obligations of the Company and are guaranteed on a joint and several senior unsecured basis by, with certain exceptions, substantially all of the Company’s existing and future subsidiaries. On September 12, 2014, we issued an additional $300 million in aggregate principal amount of our 6.125% senior notes due 2023 (the “Additional 6.125% Notes” and, together with the Original 6.125% Notes, the “6.125% Notes” and, together with the 7.75% Notes, the “Senior Notes”) in a private offering at an issue price of 100.75% of the principal amount of the Additional 6.125% Notes. We received net proceeds of $295.9 million, after deducting the initial purchasers’ discounts, adding premiums to face value of $2.3 million and deducting estimated offering expenses of $6.4 million. The Company also received cash for accrued interest from June 27, 2014 through the date of the issuance of $3.8 million, for total net proceeds of $299.7 million from the sale of the Additional 6.125% Notes. The Additional 6.125% Notes were issued under the same indenture as the Original 6.125% Notes, and are, therefore, treated as a single class of securities under the indenture. We used a portion of the net proceeds from the offering to fund a portion of the 2014 capital budget and intend to use the remainder of the net proceeds to fund a portion of the 2015 capital budget, and for general corporate purposes. The 6.125% Notes are senior unsecured obligations and rank equally in right of payment with all of our existing and future senior unsecured indebtedness. The 6.125% Notes rank senior in right of payment to the Company’s future subordinated indebtedness. The 6.125% Notes are effectively junior in right of payment to all of the Company’s existing and future secured debt (including under the Second Amended and Restated Credit Agreement) to the extent of the value of the assets securing such debt. The 6.125% Notes are fully and unconditionally guaranteed (except for customary release provisions) on a joint and several senior unsecured basis by the subsidiary guarantors party to the indenture governing the 6.125% Notes. To the extent set forth in the indenture governing the 6.125% Notes, certain of our subsidiaries will be required to fully and unconditionally guarantee the 6.125% Notes on a joint and several senior unsecured basis in the future. The indenture governing the 6.125% Notes, among other things, restricts our ability and our restricted subsidiaries’ ability to: (i) incur, assume or guarantee additional indebtedness or issue certain types of equity securities; (ii) pay distributions on, purchase or redeem shares or purchase or redeem subordinated debt; (iii) make certain investments; (iv) enter into certain transactions with affiliates; (v) create or incur liens on their assets; (vi) sell assets; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) restrict distributions or other payments from the Company’s restricted subsidiaries; and (ix) designate subsidiaries as unrestricted subsidiaries. The Company has the option to redeem all or a portion of the 6.125% Notes, at any time on or after July 15, 2018 at the applicable redemption prices specified in the indenture plus accrued and unpaid interest. The Company may also redeem the 6.125% Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make whole premium, together with accrued and unpaid interest and additional interest, if any, to the redemption date, at any time prior to July 15, 2018. In addition, the Company may redeem up to 35% of the 6.125% Notes prior to July 15, 2017 under certain circumstances with an amount not greater than the net cash proceeds of one or more equity offerings at the redemption price specified in the indenture. The Company may also be required to repurchase the 6.125% Notes upon a change of control or if we sell certain Company assets. On February 27, 2015, we completed an exchange offer of $1.15 billion aggregate principal amount of the 6.125% Notes that had been registered under the Securities Act for an equal amount of the 6.125% Notes that had not been registered under the Securities Act.

Derivative Instruments

Derivative Instruments	3 Months Ended
	Mar. 31, 2016
Derivative Instruments
Derivative Instruments	Note 7. Derivative Instruments To reduce the impact of fluctuations in oil and natural gas prices on the Company’s revenues, 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, through options, modify the future prices to be realized. These transactions may include price swaps whereby the Company will receive a fixed price for its production and pay a variable market price to the contract counterparty. In addition, the Company periodically enters into option transactions as a way to manage its exposure to fluctuating prices and/or enhance the value of fixed price swaps. Additionally, the Company may enter into collars, whereby it receives the excess, if any, of the fixed floor over the floating rate or pays the excess, if any, of the floating rate over the fixed ceiling price. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It is never the Company’s intention to enter into derivative contracts for speculative trading purposes. Under ASC Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the 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 will net derivative assets and liabilities for counterparties where it has a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings since the Company has elected not to designate its current derivative contracts as hedges. As of March 31, 2016, the Company had the following NYMEX WTI crude oil swaps and puts, respectively, covering anticipated future production: Calendar Year Volumes (Bbls) Average Price per Bbl Price Range per Bbl 2016 $ $ - $ Calendar Year Volumes (Bbls) Put Price per Bbl Put Price Range per Bbl 2016 $ $ - $ As of March 31, 2016, the Company had the following NYMEX Henry Hub natural gas swaps covering anticipated future production: Calendar Year Volumes (MMBtu) Average Price per MMBtu Price Range per MMBtu 2016 $ $ - $ 2017 $ $ - $ The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the three months ended March 31, 2016, and the year ended December 31, 2015 (in thousands): Three Months Ended March 31, 2016 Beginning fair value of commodity derivatives $ Net gains on crude oil derivatives Net gains on natural gas derivatives Net settlements on derivative contracts: Crude oil Natural gas Net premiums on derivative contracts: Crude oil Ending fair value of commodity derivatives $ Balance Sheet Presentation The Company’s derivatives are presented on a net basis as “Fair value of derivative instruments” on the condensed consolidated balance sheets. The following information summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s condensed consolidated balance sheets (in thousands): March 31, 2016 Gross Amounts Net Amounts Gross Amount Offset in the Presented in the of Recognized Consolidated Consolidated Assets Balance Sheets Balance Sheets Offsetting Derivative Assets: Current asset $ $ $ Long-term asset Total asset $ $ $ Offsetting Derivative Liabilities: Current liability $ $ $ — Long-term liability — Total liability $ $ $ — December 31, 2015 Gross Amounts Net Amounts Gross Amount Offset in the Presented in the of Recognized Consolidated Consolidated Assets Balance Sheets Balance Sheets Offsetting Derivative Assets: Current asset $ $ $ Long-term asset Total asset $ $ $ Offsetting Derivative Liabilities: Current liability $ $ $ — Long-term liability — Total liability $ $ $ —

Investments

Investments	3 Months Ended
	Mar. 31, 2016
Investments.
Investments	Note 8. Investments On October 2, 2015, the Company, through SN Midstream LLC, a wholly-owned subsidiary of the Company (“SN Midstream”), entered into joint venture agreements with an affiliate of Targa to, among other things, construct a new cryogenic natural gas processing plant (the “Processing Plant”) and associated high pressure gathering pipelines near the Company’s Catarina asset in the Eagle Ford Shale. The Processing Plant, which will be located in La Salle County, Texas, is expected to have initial capacity of 200 MMcf per day with the ability to increase to 260 MMcf per day. In connection with the Processing Plant joint venture agreement, SN Midstream has committed to invest approximately $80 million and received a 50% ownership interest in the joint venture owning the Processing Plant. Construction is expected to be completed in 2017. In connection with the gathering pipelines joint venture agreement, SN Midstream has committed to invest approximately $35 million and received a 50% ownership interest in the joint venture owning the gathering pipelines that will connect the Company's existing Catarina gathering system to the Processing Plant. Construction on the gathering pipelines is scheduled to be completed in two phases, with both phases expected to be completed in 2016. The first phase, which connected the Company’s existing Catarina gathering system to the SOII Facility (defined below), was completed in February 2016. The second phase will connect the Company’s existing gathering system to the Processing Plant, and is expected to be completed later this year. As of March 31, 2016, the Company had invested $22.7 million in the gathering pipelines joint venture. The Company is accounting for these joint ventures as equity method investments as Targa is the operator of the joint ventures and has the most influence with respect to the normal day-to-day construction and operating decisions. As of March 31, 2016, the Company had invested approximately $20.0 million in the Processing Plant joint venture. We have included these equity method investment balances in the “Other Assets - Investments” long-term asset line on the balance sheet. The Company recorded earnings of approximately $523 thousand from equity investments from the gathering pipelines joint venture and recorded losses of approximately $12 thousand from equity investments from the Processing Plant joint venture for the quarter ended March 31, 2016. We have included these equity method earnings and losses in the “Earnings from equity investments” line on the statement of operations. On October 2, 2015, the Company, via SN Catarina, purchased from a subsidiary of Targa a 10% undivided interest in the Silver Oak II Gas Processing Facility (the “SOII Facility”) in Bee County, Texas for a purchase price of $12.5 million. Targa owns the remaining undivided 90% interest in the SOII Facility, which is operated by Targa. Concurrently with the execution of the purchase and sale agreement for the SOII Facility, the Company entered into a firm gas processing agreement, whereby Targa began processing a firm quantity, 125,000 Mcf per day, on March 1, 2016 until the in-service date of the Processing Plant discussed above. The Company is accounting for the investment in the SOII Facility as an equity method investment as Targa is the operator and majority interest owner of the SOII Facility. As of March 31, 2016, the Company had invested $12.5 million in the SOII Facility. The Company did not record earnings from the equity interest in the SOII Facility for the quarter ended March 31, 2016.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	3 Months Ended
	Mar. 31, 2016
Fair Value of Financial Instruments
Fair Value of Financial Instruments	Note 9. 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 March 31, 2016 and December 31, 2015 (in thousands): As of March 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 $ $ — $ — $ Oil derivative instruments: Swaps — — Puts — — Gas derivative instruments: Swaps — — Total $ $ $ — $ As of December 31, 2015 Active Market for Identical Observable Unobservable Total Assets Inputs Inputs Carrying (Level 1) (Level 2) (Level 3) Value Cash and cash equivalents: Money market funds $ $ — $ — $ Oil derivative instruments: Swaps — — Puts — — Gas derivative instruments: Swaps — — Total $ $ $ — $ Financial Instruments : The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents on the Company’s condensed consolidated balance sheets at March 31, 2016, and December 31, 2015. The Company’s money market funds represent cash equivalents backed by the assets of high-quality banks and financial institutions. The Company identified the money market funds as Level 1 instruments due to the fact that the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained and there are active markets for the underlying investments. The Company’s derivative instruments, which consist of swaps and puts, are classified as Level 2 as of March 31, 2016 and December 31, 2015, in the table above. The fair values of the Company’s derivatives are based on third-party pricing models which utilize inputs that are either readily available in the public market, such as forward curves, or can be corroborated from active markets of broker quotes. Since swaps do not include optionality and, therefore, generally have no unobservable inputs, they are classified as Level 2. As of December 31, 2015, the Company believes that substantially all of the inputs required to calculate the fair value of swaps and puts 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 March 31, 2016 and December 31, 2015. Fair Value on a Non ‑Recurring Basis The Company follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. Fair value measurements of assets acquired and liabilities assumed in business combinations are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties is based on market and cost approaches. Our purchase price allocations for the Catarina Acquisition is presented in Note 3, “Acquisitions and Divestitures.” Liabilities assumed include asset retirement obligations existing at the date of acquisition. Asset retirement obligation estimates are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligations is presented in Note 10, “Asset Retirement Obligations.” In connection with the exchange agreements entered into in February, May and August 2014 by the Company with certain holders of the Company’s Series A Convertible Perpetual Preferred Stock (“Series A Preferred Stock”) and Series B Convertible Perpetual Preferred Stock (“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. 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 13, “Stockholders’ Equity.” Fair Value of Other Financial Instruments Financial instruments not carried at fair value consist of oil and natural gas receivables, accounts payable and accrued liabilities and long-term debt. The carrying amounts of our oil and natural gas receivables, accounts payable and accrued liabilities approximate fair value due to the highly liquid nature of these short-term instruments. The registered 7.75% Notes are traded in an active market, and as such, are classified as Level 1 financial instruments. The estimated fair value of the 7.75% Notes was $348.0 million as of March 31, 2016, and were 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 $609.5 million as of March 31, 2016, and were calculated using quoted market prices based on trades of such debt as of that date.

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2016
Asset Retirement Obligations
Asset Retirement Obligations	Note 10. 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 third-party historical data as well as current estimates. When the liability is initially recorded, the carrying amount of the related long ‑lived asset is increased. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, any gain or loss is treated as an adjustment to the full cost pool. 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 three months ended March 31, 2016 and the year ended December 31, 2015 were as follows (in thousands): Three Months Ended March 31, 2016 Year Ended December 31, 2015 Abandonment liability, beginning of period $ $ Liabilities incurred during period Acquisitions — — Divestitures Revisions — Accretion expense Abandonment liability, end of period $ $

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2016
Related Party Transactions
Related Party Transactions	Note 11. Related Party Transactions SOG, headquartered in Houston, Texas, is a private full service oil and natural gas company engaged in the exploration and development of oil and natural gas primarily in the South Texas and onshore Gulf Coast areas on behalf of its affiliates. The Company refers to SOG, Sanchez Energy Partners I, LP (“SEP I”), and their affiliates (but excluding the Company) collectively as the “Sanchez Group.” The Company does not have any employees. On December 19, 2011 it entered into a services agreement with SOG pursuant to which specified employees of SOG provide certain services with respect to the Company’s business under the direction, supervision and control of SOG. Pursuant to this arrangement, SOG performs centralized corporate functions for the Company, such as general and administrative services, geological, geophysical and reserve engineering, lease and land administration, marketing, accounting, operational services, information technology services, compliance, insurance maintenance and management of outside professionals. The Company compensates SOG for the services at a price equal to SOG’s cost of providing such services, including all direct costs and indirect administrative and overhead costs (including the allocable portion of salary, bonus, incentive compensation and other amounts paid to persons that provide the services on SOG’s behalf) allocated in accordance with SOG’s regular and consistent accounting practices, including for any such costs arising from amounts paid directly by other members of the Sanchez Group on SOG’s behalf or borrowed by SOG from other members of the Sanchez Group, in each case, in connection with the performance by SOG of services on the Company’s behalf. The Company also reimburses SOG for sales, use or other taxes, or other fees or assessments imposed by law in connection with the provision of services to the Company (other than income, franchise or margin taxes measured by SOG’s net income or margin and other than any gross receipts or other privilege taxes imposed on SOG) and for any costs and expenses arising from or related to the engagement or retention of third-party service providers. Salaries and associated benefits of SOG employees and are allocated to the Company based on a fixed percentage that is reviewed quarterly and adjusted, if needed, based on a detailed analysis of actual time spent by the professional staff on Company projects and activities. General and administrative expenses such as office rent, utilities, supplies and other overhead costs, are allocated on the same percentages as the SOG employee salaries. Expenses allocated to the Company for general and administrative expenses for the three months ended March 31, 2016 and 2015, are as follows (in thousands): March 31, 2016 2015 Administrative fees $ $ Third-party expenses Total included in general and administrative expenses $ $ As of March 31, 2016 and December 31, 2015, the Company had a net receivable from SOG and other members of the Sanchez Group of $3.6 million and $3.7 million, respectively, which are reflected as “Accounts receivable—related entities” in the condensed consolidated balance sheets. The net receivable as of March 31, 2016 and December 31, 2015 consists primarily of advances paid related to leasehold and other costs paid to SOG. As of March 31, 2016 and December 31, 2015, the Company had a net payable to SPP of approximately $4.6 million and $4.4 million, respectively, that consists primarily of the accrual for fees associated with the Gathering Agreement (see Note 3, “Acquisitions and Divestitures” for further discussion), which is reflected in the “Other Accrued liabilities” account on the consolidated balance sheets. Palmetto Disposition On March 31, 2015, we completed the Palmetto Disposition discussed above to a subsidiary of SPP, which is a related party (see Note 3, “Acquisitions and Divestitures”). The second phase of the escalating working interests on the sold Palmetto wells was effective on January 1, 2016. Western Catarina Midstream Divestiture On October 14, 2015, we completed the Western Catarina Midstream Divestiture discussed above to SPP, which is a related party (see Note 3, “Acquisitions and Divestitures”). TMS Asset Purchase In August 2013, we acquired rights to approximately 40,000 net undeveloped acres in what we believe to be the core of the TMS (the “TMS transaction”) for cash and shares of our common stock. In connection with the TMS transaction, we established an Area of Mutual Interest (“AMI”) in the TMS with SR Acquisition I, LLC (“SR”), a subsidiary of our affiliate Sanchez Resources, LLC (“Sanchez Resources”), which transaction included a carry on drilling costs for up to 6 gross ( 3 net) wells. Sanchez Resources is indirectly owned, in part, by our Chief Executive Officer and the Executive Chairman of the Board, who each also serve on our Board. Eduardo Sanchez, Patricio Sanchez and Ana Lee Sanchez Jacobs, each an immediate family member of our Chief Executive Officer and the Executive Chairman of our Board, collectively, either directly or indirectly, own a majority of the equity interests of Sanchez Resources. Sanchez Resources is managed by Eduardo Sanchez, who is the brother of our Chief Executive Officer and the son of our Executive Chairman of the Board. In addition, Eduardo Sanchez was named President of Sanchez Energy, effective as of October 1, 2015. As part of the transaction, we acquired all of the working interests in the AMI owned at closing from three sellers ( two third parties and one related party of the Company, SR) resulting in our owning an undivided 50% working interest across the AMI through the TMS. Total consideration for the TMS transactions consisted of approximately $70 million in cash and the issuance of 342,760 common shares of the Company, valued at approximately $7.5 million. The cash consideration provided to SR was $14.4 million, before consideration of any well carries. The acquisitions were accounted for as the purchase of assets at cost on the acquisition date. We also committed, as a part of the total consideration, to carry SR for its 50% working interest in an initial 3 gross ( 1.5 net) TMS wells to be drilled within the AMI (the “Initial Well Carry”) with an option to drill an additional 6 gross ( 3 net) TMS wells (“Additional Wells”) within the AMI. In August 2015, the Company signed an agreement with SR whereby the Company paid SR approximately $8 million in lieu of drilling the remaining two Additional Wells (the “Buyout Agreement”). The Buyout Agreement stipulates that SN has earned full rights to all acreage stated in the TMS transaction and effectively terminates any future well carry commitments.

Accrued Liabilities

Accrued Liabilities	3 Months Ended
	Mar. 31, 2016
Accrued Liabilities
Accrued Liabilities	Note 12. Accrued Liabilities The following information summarizes accrued liabilities as of March 31, 2016 and December 31, 2015 (in thousands): March 31, December 31, 2016 2015 Capital expenditures $ $ Other: General and administrative costs Production taxes Ad valorem taxes Lease operating expenses Interest payable Total accrued liabilities $ $

Stockholders' Equity

Stockholders' Equity	3 Months Ended
	Mar. 31, 2016
Stockholders' Equity
Stockholders' Equity	Note 13. Stockholders’ Equity Common Stock Offerings — On September 18, 2013, the Company completed a public offering of 11,040,000 shares of common stock (including 1,440,000 shares purchased pursuant to the full exercise of the underwriters’ overallotment option), at an issue price of $23.00 per share. The Company received net proceeds from this offering of $241.4 million, after deducting underwriters’ fees and offering expenses of $12.5 million. The Company used the net proceeds from the offering to partially fund the Wycross Acquisition completed in October 2013 and a portion of the 2013 and 2014 capital budgets, and for general corporate purposes. On June 12, 2014, the Company completed a public offering of 5,000,000 shares of common stock, at an issue price of $35.25 per share. The Company received net proceeds from this offering of $167.5 million, after deducting underwriters’ fees and offering expenses of $8.7 million. The Company used the net proceeds from the offering to partially fund the 2014 capital budget and for general corporate purposes. 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. 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 Board of Directors of the Company (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 March 31, 2016, all dividends accumulated through that date had been paid. Except as required by law or the Company’s Amended and Restated Certificate of Incorporation (the “Charter”), holders of the Series A Preferred Stock will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). In that event and until such arrearage is paid in full, the holders of the Series A Preferred Stock and the holders of the Series B Preferred Stock, voting as a single class, will be entitled to elect two directors and the number of directors on the Board will increase by that same number. At any time on or after October 5, 2017, the Company may at its option cause all outstanding shares of the Series A Preferred Stock to be automatically converted into common stock at the conversion price, if, among other conditions, the closing sale price (as defined) of the Company’s common stock equals or exceeds 130% of the conversion price for a specified period prior to the conversion. If a holder elects to convert shares of Series A Preferred Stock upon the occurrence of certain specified fundamental changes, the Company will be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option time value of the shares of Series A Preferred Stock as a result of the fundamental change. Series B Preferred Stock Offering —On March 26, 2013, the Company completed a private placement of 4,500,000 shares of Series B Preferred Stock. The issue price of each share of the Series B Preferred Stock was $50.00 . The Company received net proceeds from the private placement of $216.6 million, after deducting placement agent’s fees and offering costs of $8.4 million. Each share of Series B Preferred Stock is convertible at any time at the option of the holder thereof at an initial conversion rate of 2.337 shares of common stock per share of Series B Preferred Stock (which is equal to an initial conversion price of $21.40 per share of common stock) and is subject to specified adjustments. Based on the initial conversion price, approximately 8,255,055 shares of common stock would be issuable upon conversion of all of the outstanding shares of the Series B 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 March 31, 2016, all dividends accumulated through that date had been paid. Except as required by law or the Charter, holders of the Series B Preferred Stock will have no voting rights unless dividends fall into arrears for six or more quarterly periods (whether or not consecutive). In that event and until such arrearage is paid in full, the holders of the Series B Preferred Stock and the holders of the Series A Preferred Stock, voting as a single class, will be entitled to elect two directors and the number of directors on the Board will increase by that same number. At any time on or after April 6, 2018, the Company may at its option cause all outstanding shares of the Series B Preferred Stock to be automatically converted into common stock at the conversion price, if, among other conditions, the closing sale price (as defined) of the Company’s common stock equals or exceeds 130% of the conversion price for a specified period prior to the conversion. If a holder elects to convert shares of Series B Preferred Stock upon the occurrence of certain specified fundamental changes, the Company will be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option time value of the shares of Series B Preferred Stock as a result of the fundamental change. Preferred Stock Exchange —On February 12, 2014 and February 13, 2014, the Company entered into exchange agreements with certain holders (the “February 2014 Holders”) of the Series A Preferred Stock, and of Series B Preferred Stock, pursuant to which such holders agreed to exchange an aggregate of (i) 947,490 shares of Series A Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 2,425,574 shares of the Company’s common stock, and (ii) 756,850 shares of the Series B Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 2,021,066 shares of common stock. Additionally, on May 29, 2014, the Company entered into exchange agreements with certain holders (the “May 2014 Holders”) of the Series A Preferred Stock, and of Series B Preferred Stock, pursuant to which such holders agreed to exchange an aggregate of (i) 166,025 shares of Series A Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 418,715 shares of the Company’s common stock, and (ii) 210,820 shares of the Series B Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 553,980 shares of common stock. Further, on August 28, 2014, the Company entered into exchange agreements with certain holders (the “August 2014 Holders,” and together with the May 2014 Holders and the February 2014 Holders, the “Holders”) of the Series A Preferred Stock, pursuant to which such holders agreed to exchange an aggregate of 47,500 shares of Series A Preferred Stock (and waive their rights to any accrued and unpaid dividends thereon) for 119,320 shares of the Company’s common stock. Since the Holders were not entitled to any consideration over and above the initial conversion rates of 2.325 and 2.337 common shares for each preferred share exchanged for Series A Preferred Stock and Series B Preferred Stock, respectively, any consideration is considered an inducement for the Holders to convert earlier than the Company could have forced conversion. The Company has determined the fair value of consideration transferred to the Holders and the fair value of consideration transferrable pursuant to the original conversion terms. The $13.9 million, $3.1 million and $0.3 million excess of the fair value of the shares of common stock issued over the carrying value of the Series A Preferred Stock and Series B Preferred Stock redeemed in connection with the exchange agreements entered into in February, May and August 2014, respectively, has been reflected as an additional preferred stock dividend, that is, as an increase in accumulated deficit to arrive at net loss attributable to common stockholders in our condensed consolidated financial statements. Preferred Stock Conversion —On November 20, 2015, a holder of our Series B Convertible Perpetual Preferred Stock exercised its right to convert 4,500 shares our Series B Convertible Perpetual Preferred Stock, at the prescribed initial conversion rate of 2.337 shares of common stock per share of Series B Convertible Perpetual Preferred Stock, in exchange for 10,517 shares of our common stock. NOL Rights Plan —On July 28, 2015, the Company entered into a net operating loss carryforwards (“NOLs”) rights plan with Continental Stock Transfer & Trust Company, as rights agent. In connection therewith, the Board declared a dividend of one preferred share purchase right (“Right”) for each outstanding share of the Company’s common stock. The dividend was paid on August 10, 2015 to stockholders of record as of the close of business on August 7, 2015 (the “NOL Record Date”). In addition, one Right automatically attached to each share of common stock issued between the NOL Record Date and such date as when the Rights become exercisable. Earnings (Loss) Per Share— The following table shows the computation of basic and diluted net loss per share for the three months ended March 31, 2016 and 2015 (in thousands, except per share amounts): Three Months Ended March 31, 2016 2015 Net income (loss) $ $ Less: Preferred stock dividends Net loss allocable to participating securities (1)(2) — — Net income (loss) attributable to common stockholders $ $ Weighted average number of unrestricted outstanding common shares used to calculate basic net earnings (loss) per share Dilutive shares (3)(4) — — Denominator for diluted earnings (loss) per common share Net income (loss) per common share - basic and diluted $ $ (1) The Company’s restricted shares of common stock are participating securities. (2) For the three months ended March 31, 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 three months ended March 31, 2016 excludes 685,597 shares of weighted average restricted stock and 12,520,179 shares of common stock resulting from an assumed conversion of the Series A Preferred Stock and Series B Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive. (4) The three months ended March 31, 2015 excludes 1,556,115 shares of weighted average restricted stock and 12,530,695 shares of common stock resulting from an assumed conversion of the Series A Preferred Stock and Series B Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

Stock-Based Compensation

Stock-Based Compensation	3 Months Ended
	Mar. 31, 2016
Stock-Based Compensation
Stock-Based Compensation	Note 14. Stock ‑Based Compensation At the Annual Meeting of Stockholders of the Company held on May 21, 2015 (“2015 Annual Meeting”), the Company’s stockholders approved the Sanchez Energy Corporation Second Amended and Restated 2011 Long Term Incentive Plan (the “LTIP”). The Board had previously approved the LTIP on April 20, 2015, subject to stockholder approval. The Company’s directors and consultants as well as employees of the Sanchez Group who provide services to the Company are eligible to participate in the LTIP. Awards to participants may be made in the form of restricted shares, phantom shares, share options, share appreciation rights and other share-based awards. The maximum number of shares that may be delivered pursuant to the LTIP is limited to (i) 4,000,000 shares of common stock plus the number of shares of common stock available under the predecessor to the LTIP on the record date of the 2015 Annual Meeting (the "Record Date") at which the stockholders approved the LTIP as well as (ii) upon the issuance of additional shares of common stock from time to time after the Record Date, an automatic increase of 15% of such issuance of additional shares of common stock, unless the Board determines to increase the maximum number of shares of common stock by a lesser amount. Shares withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. In addition, if an award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of shares, the shares subject to such award are then available for new awards under the LTIP. Shares delivered pursuant to awards under the LTIP may be newly issued shares, shares acquired by the Company in the open market, shares acquired by the Company from any other person, or any combination of the foregoing. The LTIP is administered by the Compensation Committee of the Board as appointed by the Board. The Board may terminate or amend the LTIP at any time with respect to any shares for which a grant has not yet been made. The Board has the right to alter or amend the LTIP or any part of the LTIP from time to time, including increasing the number of shares that may be granted, subject to stockholder approval as may be required by the exchange upon which the common shares are listed at that time, if any. No change may be made in any outstanding grant that would materially reduce the benefits of the participant without the consent of the participant. The LTIP will expire upon its termination by the Board or, if earlier, when no shares remain available under the LTIP for awards. Upon termination of the LTIP, awards then outstanding will continue pursuant to the terms of their grants. The Company records stock-based compensation expense for awards granted to its directors (for their services as directors) in accordance with the provisions of ASC 718, “Compensation—Stock Compensation.” Stock-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method. Awards granted to employees of the Sanchez Group (including those employees of the Sanchez Group who also serve as the Company’s officers) and consultants in exchange for services are considered awards to non-employees and the Company records stock-based compensation expense for these awards at fair value in accordance with the provisions of ASC 505-50, “Equity-Based Payments to Non-Employees.” For awards granted to non-employees, the Company records compensation expenses equal to the fair value of the stock-based award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. Compensation expense for unvested awards to non-employees is revalued at each period end and is amortized over the vesting period of the stock-based award. Stock-based payments are measured based on the fair value of the equity instruments granted, as it is more determinable than the value of the services rendered. For the restricted stock awards granted to non-employees, stock-based compensation expense is based on fair value re-measured at each reporting period and recognized over the vesting period using the straight-line method. Compensation expense for these awards will be revalued at each period end until vested. During the three months ended March 31, 2016, the Company did not issue any shares of restricted common stock pursuant to the LTIP to directors of the Company. During the three months ended March 31, 2016, the Company issued approximately 3.1 million shares of restricted common stock pursuant to the LTIP to certain employees (including the Company’s officers) and consultants of SOG, 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. In February 2016, the Compensation Committee approved several new forms of agreements for use in equity awards pursuant to the LTIP. The new forms of agreements consist of a two new forms of restricted stock award agreements, one of which provides for vesting in equal annual increments over a three year period from the Grant Date (the “Grant Date”) and the other of which provides for cliff vesting five years after the Grant Date or earlier if the common stock closing price equals or exceeds certain benchmarks as set forth in the form of agreement (the “Performance Accelerated Restricted Stock” or “PARS”), and two new forms of phantom stock agreements payable only in cash, one of which provides for vesting in equal annual increments over a three year period from the Grant Date (the “Phantom Stock”) and the other of which provides for cliff vesting five years after the Grant Date or earlier if the Company’s common stock closing price equals or exceeds certain benchmarks as set forth in the form of agreement (the “Performance Accelerated Phantom Stock” or “PAPS”). The PARS, PAPS and Phantom Stock awards granted to certain employees of the Sanchez Group (including those employees of the Sanchez Group who also serve as the Company’s officers) and consultants in exchange for services are considered awards to non-employees and the Company records stock-based compensation expense for these awards at fair value in accordance with the provisions of ASC 718, “Compensation – Stock Compensation.” In accordance with the guidance, the inclusion of market performance acceleration conditions does not change the accounting classification as compared to the restricted stock without market performance acceleration conditions, as both are still classified as equity within the Company’s balance sheet. The phantom share 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. 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: Three Months Ended March 31, 2016 2015 Restricted stock awards, directors $ $ Restricted stock awards, non-employees Total stock-based compensation expense $ $ Based on the $5.49 per share closing price of the Company’s common stock on March 31, 2016, there was approximately $32.8 million of unrecognized compensation cost related to the non ‑vested restricted shares outstanding. The cost is expected to be recognized over an average period of approximately 2.3 years. Based on the $5.49 per share closing price of the Company’s common stock on March 31, 2016, there was approximately $13.9 million of unrecognized compensation cost related to the non ‑vested PARS, PAPS, and Phantom Stock award shares outstanding. The cost is expected to be recognized over an average period of approximately 2.73 years. A summary of the status of the non-vested shares for the three months ended March 31, 2016 and 2015 is presented below (in thousands): Three Months Ended March 31, March 31, 2016 2015 Non-vested common stock, beginning of period Granted Vested Forfeited Non-vested common stock, end of period As of March 31, 2016, approximately 4.9 million shares remain available for future issuance to participants.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2016
Income Taxes
Income Taxes	Note 15. Income Taxes The Company's effective tax rate for the three months ended March 31, 2016 and 2015 was 0% and (1.5) %, respectively. The difference between the statutory federal income taxes calculated using a U.S. Federal statutory corporate income tax rate of 35% and the Company’s effective tax rate of 0% for the three months ended March 31, 2016 is related to the valuation allowance on deferred tax assets. 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 (1.5)% for the three months ended March 31, 2015 is primarily related to related to the valuation allowance on deferred tax assets. As of March 31, 2016, the Company had estimated NOLs of $863.7 million, which begin to expire in 2031. The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance with authoritative guidance for accounting for income taxes. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is recovered or settled, respectively. In recording deferred income tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred income tax assets will be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those deferred income tax assets would be deductible. The Company believes that after considering all the available objective evidence, both positive and negative, historical and prospective, with greater weight given to historical evidence, management is not able to determine that it is more likely than not that the deferred tax assets will be realized and, therefore, has established a valuation allowance of $537.0 million to reduce the net deferred tax asset to $0 at March 31, 2016. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods. At March 31, 2016, the Company had no material uncertain tax positions.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2016
Commitments and Contingencies
Commitments and Contingencies	Note 16. Commitments and Contingencies From time to time, the Company may be involved in lawsuits that arise in the normal course of its business. We are not aware of any material governmental proceedings against us or contemplated to be brought against us. On December 4, 13 and 16, 2013, three derivative actions were filed in the Court of Chancery of the State of Delaware against the Company, certain of its officers and directors, Sanchez Resources, Altpoint Capital Partners LLC and Altpoint Sanchez Holdings, LLC (Friedman v. A.R. Sanchez, Jr. et al., No. 9158; City of Roseville Employees’ Retirement System v. A.R. Sanchez, Jr. et al., No. 9132; and Delaware County Employees Retirement Fund v. A.R. Sanchez, Jr. et al., No. 9165 (collectively, the ‘‘Consolidated Derivative Actions’’)). On December 20, 2013, the Consolidated Derivative Actions were consolidated, co-lead counsel for the plaintiffs was appointed and the plaintiffs were ordered to file an amended consolidated complaint (In re Sanchez Energy Derivative Litigation, Consolidated C.A. No. 9132-VCG, hereinafter, the “Delaware Derivative Action”). On January 28, 2014, a verified consolidated stockholder derivative complaint was filed. The Consolidated Derivative Actions concern the Company’s purchase of working interests in the TMS from Sanchez Resources. Plaintiffs alleged breaches of fiduciary duty against the individual defendants as directors of the Company; breaches of fiduciary duty against Antonio R. Sanchez, III as an executive director of the Company; aiding and abetting breaches of fiduciary duty against Sanchez Resources, Eduardo Sanchez, Altpoint Capital Partners LLC and Altpoint Sanchez Holdings, LLC; and unjust enrichment against A.R. Sanchez, Jr. and Antonio R. Sanchez, III. All of the defendants filed a motion to dismiss on April 1, 2014. Briefing concerning the motions to dismiss concluded on June 27, 2014. A hearing was held on August 11, 2014, on the motions to dismiss, and the court subsequently granted the motions to dismiss. The plaintiffs appealed the case to the Delaware Supreme Court for which the parties fully briefed the appeal and provided oral argument. On October 2, 2015, the Delaware Supreme Court reversed the motions to dismiss and remanded the case to the Court of Chancery of the State of Delaware. No scheduling order for the matter has been set at this time; however, discovery has started. The Company is unable to reasonably predict an outcome or to reasonably estimate a range of possible loss. On January 9, 2014, a derivative action was filed in 333rd district court in Harris County, Texas against the Company and certain of its officers and directors, styled Martin v. Sanchez, No. 2014-01028 (333rd Dist. Harris County, Texas). The complaint alleged a breach of fiduciary duty, corporate waste and unjust enrichment against various officers and directors. No action has been taken to date and damages are unspecified. On March 14, 2014, this action was stayed following a ruling on the motion to dismiss in the Delaware Derivative Action. After the motions to dismiss were granted in the Delaware Derivative Action, the parties entered into another agreed stay pending the appeal of the Delaware Derivative Action to the Delaware Supreme Court. This stay was entered by the court on February 5, 2015. Since the Delaware Supreme Court has ruled on the appeal, the parties agreed to another stay for 60 days following the completion of fact discovery in the Delaware Derivative Action. This action is in its preliminary stages, and the Company is unable to reasonably predict an outcome or to estimate a range of reasonably possible loss. Defendants believe that the allegations contained in the matters described above are without merit and intend to vigorously defend themselves against the claims raised. In connection with the Catarina Acquisition, the 77,000 acres of undeveloped acreage that were included in the acquisition are subject to a continuous drilling obligation. Such drilling obligation requires us to drill (i) 50 wells in each annual period commencing on July 1, 2014 and (ii) at least one well in any consecutive 120 -day period in order to maintain rights to any future undeveloped acreage. Up to 30 wells drilled in excess of the minimum 50 wells in a given annual period can be carried over to satisfy part of the 50 well requirement in the subsequent annual period on a well for well basis. The lease also created a customary security interest in the production therefrom in order to secure royalty payments to the lessor and other lease obligations. Our current capital budget and plans include the drilling of at least the minimum number of wells required to maintain access to such undeveloped acreage. As of March 31, 2016, the Company had $253.2 million in lease payment obligations that satisfy operating lease criteria. These obligations include: (i) $190.2 million in payments due with respect to firm commitment of oil and natural gas volumes under the Gathering Agreement contract signed with SPP as part of the Western Catarina Midstream Divestiture that commenced on October 14, 2015 and continues until October 13, 2020, (ii) $49.5 million for a new corporate office lease that commenced in the fourth quarter of 2014 and has an expiration date in March 2025, (iii) $7.1 million for a ground lease agreement for land owned by the Calhoun Port Authority that commenced during the third quarter of 2014 and has an expiration date in August 2024 and (iv) $6.3 million for a 10 year acreage lease agreement for a promotional ranch managed by the Company in Kenedy County, Texas. This acreage lease agreement includes a contractual requirement for the Company to spend a minimum of $4 million to make permanent improvements over the ten year life of the lease. The lease agreement does not specify the timing for such improvements to be made within the lease term. The Company’s ground lease with the Calhoun Port Authority is terminable upon 180 days written notice by the Company to the lessor in addition to a $1 million termination payment. The Company has the right to terminate its lease obligation for its acreage in Kenedy County, Texas at any time without penalty with six months advanced written notice and payment of any accrued leasehold expenses. As discussed in Note 8, “Investments” above, SN Midstream entered into joint venture agreements with an affiliate of Targa to construct the Processing Plant and associated high pressure gathering pipelines near the Company’s Catarina asset. In connection with the Processing Plant joint venture agreement, SN Midstream has committed to invest approximately $80 million and receive a 50% ownership interest in the joint venture owning the Processing Plant. Construction is expected to be completed in 2017. In connection with the gathering pipelines joint venture agreement, SN Midstream has committed to invest approximately $35 million and receive a 50% ownership interest in the joint venture owning the gathering pipelines that will connect the Company's existing Catarina gathering system to the Processing Plant. Construction on the gathering pipelines is expected to be completed in 2016. As of December 31, 2015, the Company had invested approximately $20.0 million in the Processing Plant joint venture, and $22.7 million in the gathering pipeline joint venture. As of March 31, 2016, the Company has guaranteed SN Midstream’s remaining commitment to invest approximately $60 million and $12.3 million, respectively, in the Processing Plant and gathering pipelines joint ventures. Membership percentage interests in the Processing Plant joint venture and the gathering pipelines joint venture for the Company and Targa are calculated based on the aggregate capital contributions made by each party related to the total capital contributions made by both parties. If SN Midstream fails to make capital contributions or the Company fails to fulfill the guarantee or, in the case of the Processing Plant joint venture, the Company does not elect to contribute more than $80 million (if the cost to construct the Processing Plant exceeds $160 million) our membership interest in the joint venture could be reduced. If our membership interest falls below 20% in either joint venture, we have the potential to lose appointed board seats and voting rights.

Subsidiary Guarantors

Subsidiary Guarantors	3 Months Ended
	Mar. 31, 2016
Subsidiary Guarantors
Subsidiary Guarantors	Note 17. 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 March 31, 2016, such subsidiaries are 100 percent owned by the Company and any guarantees by these subsidiaries will be full and unconditional (except for customary release provisions). In the event that more than one of these subsidiaries provide guarantees of any debt securities issued by the Company, such guarantees will constitute joint and several obligations. The Company also filed a registration statement on Form S-4 with the SEC, which became effective on June 20, 2014, pursuant to which the Company completed an offering of the 7.75% Notes, which are guaranteed by its subsidiaries named therein. As of March 31, 2016, such guarantor subsidiaries are 100 percent owned by the Company and the guarantees by these subsidiaries are full and unconditional (except for customary release provisions) and are joint and several. The Company also filed a registration statement on Form S-4 with the SEC, which became effective on January 23, 2015, pursuant to which the Company completed an offering of the 6.125% Notes, which are guaranteed by its subsidiaries named therein. As of March 31, 2016, such guarantor subsidiaries are 100 percent owned by the Company and the guarantees by these subsidiaries are full and unconditional (except for customary release provisions) and are joint and several. The rules of Regulation S-X Rule 3-10 require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is 100% owned by the registrant. See Note 18, “Condensed Consolidating Financial Information” for further discussion regarding the condensed consolidating financial information for guarantor and non-guarantor subsidiaries. The Company has no assets or operations independent of its subsidiaries and there are no significant restrictions upon the ability of its subsidiaries to distribute funds to the Company.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	3 Months Ended
	Mar. 31, 2016
Condensed Consolidating Financial Information
Condensed Consolidating Financial Information	Not Note 18. Condensed Consolidating Financial Information As noted above, the rules of the SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is 100% owned by the registrant. The Company is, therefore, presenting condensed consolidating financial information on a parent company, combined guarantor subsidiaries, combined non-guarantor subsidiaries and consolidated basis (in thousands) and should be read in conjunction with the consolidated financial statements. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had such guarantor subsidiaries operated as independent entities. Investments in subsidiaries are accounted for by the respective parent company using the equity method for purposes of this presentation. Results of operations of subsidiaries are, therefore, reflected in the parent company’s investment accounts and earnings. The principal elimination entries set forth below eliminate investments in subsidiaries and intercompany balances and transactions. Typically in a condensed consolidating financial statement, the net income and equity of the parent company equals the net income and equity of the consolidated entity. March 31, 2016 Assets Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total current assets $ $ $ $ $ Total oil and natural gas properties, net - - - Investment in subsidiaries - - - Other assets - Total Assets $ $ $ $ $ Liabilities and Shareholders' Equity Current liabilities $ $ $ $ $ Long-term liabilities - - Total shareholders' equity (deficit) Total Liabilities and Shareholders' Equity (deficit) $ $ $ $ $ December 31, 2015 Assets Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total current assets $ $ $ $ $ Total oil and natural gas properties, net - - - Investment in subsidiaries - - - Other assets - Total Assets $ $ $ $ $ Liabilities and Shareholders' Equity Current liabilities $ $ $ $ $ Long-term liabilities - - Total shareholders' equity (deficit) Total Liabilities and Shareholders' Equity (deficit) $ $ $ $ $ Three Months Ended March 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total revenues $ - $ $ - $ - $ Total operating costs and expenses - Other income (expense) - Income (loss) before income taxes $ $ $ $ - $ Income tax expense - - - - - Equity in income (loss) of subsidiaries - - - Net income (loss) $ $ $ $ $ Three Months Ended March 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total revenues $ - $ $ - $ - $ Total operating costs and expenses - Other income (expense) - - Income (loss) before income taxes $ $ $ $ - $ Income tax expense - Equity in income (loss) of subsidiaries - - - Net income (loss) $ $ $ $ $ Three Months Ended March 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ $ $ $ - $ Net cash provided by (used in) investing activities Net cash provided by (used in) financing activities Net increase (decrease) in cash and cash equivalents $ $ - $ $ - $ Cash and cash equivalents, beginning of period - - Cash and cash equivalents, end of period $ $ - $ $ - $ Three Months Ended March 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ $ $ $ - $ Net cash provided by (used in) investing activities - Net cash provided by (used in) financing activities Net increase (decrease) in cash and cash equivalents $ $ - $ - $ - $ Cash and cash equivalents, beginning of period - - Cash and cash equivalents, end of period $ $ - $ - $ - $

Variable Interest Entities

Variable Interest Entities	3 Months Ended
	Mar. 31, 2016
Variable Interest Entities
Variable Interest Entities	Note 19. Variable Interest Entities During the first quarter of 2016, the Company adopted ASU 2015-02, “Consolidation—Amendments to the Consolidation Analysis,” which introduces a separate analysis for determining if limited partnerships and similar entities are variable interest entities (“VIEs”) and clarifies the steps a reporting entity would have to take to determine whether the voting rights of stockholders in a corporation or similar entity are substantive. As noted above in Note 8, “Investments,” the Company, through SN Midstream, entered into joint venture agreements with an affiliate of Targa in October 2015 to, among other things, construct the Processing Plant and associated high pressure gathering pipelines near the Company’s Catarina asset in the Eagle Ford Shale. In addition, the Company, via SN Catarina, purchased from a subsidiary of Targa a 10% undivided interest in the SOII Facility. The Company determined that the gathering and Processing Plant joint ventures and ownership in the SOII Facility are more similar to limited partnerships than corporations. Under the revised guidance of ASU 2015-02, a limited partnership or similar entity with equity at risk will not be a VIE if they are able to exercise kick-out rights over the general partner(s) or they are able to exercise substantive participating rights. We concluded that the gathering and Processing Plant joint ventures and investment in SOII Facility are VIEs under the revised guidance because we cannot remove Targa as operator and we do not have substantive participating rights. In addition, Targa has the power to direct activities of the VIEs regarding the risks associated with price, operations, and capital investment which have most significant impact the VIEs economic performance. In connection with the Processing Plant joint venture agreement, SN Midstream has committed to invest approximately $80 million and received a 50% ownership interest in the joint venture owning the Processing Plant. In connection with the gathering pipelines joint venture agreement, SN Midstream has committed to invest approximately $35 million and received a 50% ownership interest in the joint venture owning the gathering pipelines that will connect the Company's existing Catarina gathering system to the Processing Plant. The Company’s investment in the gathering joint venture, the Processing Plant and the SOII Facility represent VIEs that could expose the Company to losses. The amount of losses the Company could be exposed to from the gathering and Processing Plant joint ventures is limited to the capital investment guaranteed of approximately $80 million and $35 million related to the Processing Plant joint venture and gathering pipelines joint venture, respectively. The amount of losses the Company could be exposed to from the investment in the SOII Facility is limited to the equity in the investment at any point in time. As of March 31, 2016, the Company had invested $22.7 million in the gathering pipelines joint venture, approximately $20.0 million in the Processing Plant joint venture, and approximately $12.5 million in the SOII Facility. There is no debt incurred by the gathering pipelines joint venture, the Processing Plant joint venture, or the SOII Facility. The Company is accounting for these VIEs as equity method investments and determined that Targa is the primary beneficiary of the VIEs as Targa is the operator of the gathering and the Processing Plant joint ventures and the SOII Facility and has the most influence with respect to the normal day-to-day operating decisions. We have included these VIEs in the “Other Assets - Investments” long-term asset line on the balance sheet. Below is a tabular comparison of the carrying amounts of the assets and liabilities of the VIEs and the Company’s maximum exposure to loss as of March 31, 2016 and December 31, 2015 (in thousands): March 31, December 31, 2016 2015 Capital investments $ $ Earnings in equity investments — Equity in equity investments $ $ March 31, December 31, 2016 2015 Equity in equity investments $ $ Guarantees of capital investments Maximum exposure to loss $ $

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2016
Subsequent Events.
Subsequent Events	Note 20. Subsequent Events The Company filed registration statements on Form S-3 with the SEC on March 21, 2016, which became effective April 25, 2016, and registered, among other securities, debt securities.

Basis of Presentation and Sum28

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2016
Basis of Presentation and Summary of Significant Accounting Policies
Principles of Consolidation	Principles of Consolidation The Company’s condensed 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 condensed 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 calculation of depletion and impairment of oil and natural gas properties, the evaluation of unproved properties for impairment, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018, with a modified retrospective approach to be used for implementation. ASU 2016-02 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 those leases previously classified as operating leases under the old guidance. In addition, ASU 2016-02 updates the criteria for a lessee’s classification of a finance lease. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In April 2015, the FASB issued ASU 2015-03, “Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” This guidance is intended to more closely align the presentation of debt issuance costs under U.S. GAAP with the presentation requirements under the International Financial Reporting Standards. Under this new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented. This guidance is effective for fiscal years and interim periods beginning after December 15, 2015. During the first quarter 2016, the Company adopted ASU 2015-03 retrospectively to the comparable periods in this Form 10-Q. Adoption of this guidance affected the balance sheets as of December 31, 2015 as follows (in thousands): Decrease in Long term debt, net of premium, discount and debt issuance costs of approximately $41,039 Decrease in Debt issuance costs, net (Other Assets) of approximately $41,039 In February 2015, the FASB issued ASU 2015-02, “Consolidation—Amendments to the Consolidation Analysis.” This ASU will simplify existing requirements by reducing the number of acceptable consolidation models and placing more emphasis on risk of loss when determining a controlling financial interest. The provisions of this new standard will affect how limited partnerships and similar entities are assessed for consolidation, including the elimination of the presumption that a general partner should consolidate a limited partnership. This guidance is effective for fiscal years and interim periods beginning in 2016. During the first quarter 2016, the Company adopted ASU 2015-02 retrospectively to the comparable periods in this Form 10-Q. See further disclosure around the adoption of ASU 2015-02, and the impact on the Company’s consolidated financial statements in Note 19, “Variable Interest Entities.” In July 2015, FASB issued ASU No. 2015-11, “ Simplifying the Measurement of Inventory ,” effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is not permitted. The guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	3 Months Ended
	Mar. 31, 2016
Catarina
Acquisitions
Schedule of total purchase price allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition	The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands): Proved oil and natural gas properties $ Unproved properties Other assets acquired Fair value of assets acquired Asset retirement obligations Fair value of net assets acquired $

Cash and Cash Equivalents (Tabl

Cash and Cash Equivalents (Tables)	3 Months Ended
	Mar. 31, 2016
Cash and Cash Equivalents
Schedule of cash and cash equivalents	As of March 31, 2016 and December 31, 2015, cash and cash equivalents consisted of the following (in thousands): March 31, December 31, 2016 2015 Cash at banks $ $ Money market funds Total cash and cash equivalents $ $

Long-Term Debt (Tables)

Long-Term Debt (Tables)	3 Months Ended
	Mar. 31, 2016
Long-Term Debt
Schedule of long-term debt	Amount Outstanding (in thousands) as of March 31, December 31, Interest Rate Maturity date 2016 2015 Second Amended and Restated Credit Agreement Variable June 30, 2019 $ — $ — 7.75% Notes 7.75% June 15, 2021 6.125% Notes 6.125% January 15, 2023 Unamortized discount on Additional 7.75% Notes Unamortized premium on Additional 6.125% Notes Unamortized debt issuance costs Total long-term debt $ $
Schedule of interest expense	The components of interest expense are (in thousands): Three Months Ended March 31, 2016 2015 Interest on Senior Notes $ $ Interest expense and commitment fees on credit agreement Amortization of debt issuance costs Amortization of discount on Additional 7.75% Notes Amortization of premium on Additional 6.125% Notes Total interest expense $ $

Derivative Instruments (Tables)

Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2016
Derivative contract covering anticipated future production
Schedule of reconciliation of the changes in fair value of the Company's commodity derivatives	The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the three months ended March 31, 2016, and the year ended December 31, 2015 (in thousands): Three Months Ended March 31, 2016 Beginning fair value of commodity derivatives $ Net gains on crude oil derivatives Net gains on natural gas derivatives Net settlements on derivative contracts: Crude oil Natural gas Net premiums on derivative contracts: Crude oil Ending fair value of commodity derivatives $
Summary of balance sheet presentation of the Company's commodity derivatives	The following information summarizes the gross fair values of derivative instruments, presenting the impact of offsetting the derivative assets and liabilities on the Company’s condensed consolidated balance sheets (in thousands): March 31, 2016 Gross Amounts Net Amounts Gross Amount Offset in the Presented in the of Recognized Consolidated Consolidated Assets Balance Sheets Balance Sheets Offsetting Derivative Assets: Current asset $ $ $ Long-term asset Total asset $ $ $ Offsetting Derivative Liabilities: Current liability $ $ $ — Long-term liability — Total liability $ $ $ — December 31, 2015 Gross Amounts Net Amounts Gross Amount Offset in the Presented in the of Recognized Consolidated Consolidated Assets Balance Sheets Balance Sheets Offsetting Derivative Assets: Current asset $ $ $ Long-term asset Total asset $ $ $ Offsetting Derivative Liabilities: Current liability $ $ $ — Long-term liability — Total liability $ $ $ —
Crude oil
Derivative contract covering anticipated future production
Schedule of anticipated future production	Calendar Year Volumes (Bbls) Average Price per Bbl Price Range per Bbl 2016 $ $ - $ Calendar Year Volumes (Bbls) Put Price per Bbl Put Price Range per Bbl 2016 $ $ - $
Natural gas
Derivative contract covering anticipated future production
Schedule of anticipated future production	Calendar Year Volumes (MMBtu) Average Price per MMBtu Price Range per MMBtu 2016 $ $ - $ 2017 $ $ - $

Fair Value of Financial Instr33

Fair Value of Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2016
Fair Value of Financial Instruments
Schedule of financial assets and liabilities measured at fair value on a recurring basis	The following tables set forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2016 and December 31, 2015 (in thousands): As of March 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 $ $ — $ — $ Oil derivative instruments: Swaps — — Puts — — Gas derivative instruments: Swaps — — Total $ $ $ — $ As of December 31, 2015 Active Market for Identical Observable Unobservable Total Assets Inputs Inputs Carrying (Level 1) (Level 2) (Level 3) Value Cash and cash equivalents: Money market funds $ $ — $ — $ Oil derivative instruments: Swaps — — Puts — — Gas derivative instruments: Swaps — — Total $ $ $ — $

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2016
Asset Retirement Obligations
Schedule of changes in asset retirement obligation	The changes in the asset retirement obligation for the three months ended March 31, 2016 and the year ended December 31, 2015 were as follows (in thousands): Three Months Ended March 31, 2016 Year Ended December 31, 2015 Abandonment liability, beginning of period $ $ Liabilities incurred during period Acquisitions — — Divestitures Revisions — Accretion expense Abandonment liability, end of period $ $

Related Party Transactions (Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2016
Related Party Transactions
Schedule of expenses allocated to the Company for general and administrative expenses	March 31, 2016 2015 Administrative fees $ $ Third-party expenses Total included in general and administrative expenses $ $

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	3 Months Ended
	Mar. 31, 2016
Accrued Liabilities
Summary of accrued liabilities	The following information summarizes accrued liabilities as of March 31, 2016 and December 31, 2015 (in thousands): March 31, December 31, 2016 2015 Capital expenditures $ $ Other: General and administrative costs Production taxes Ad valorem taxes Lease operating expenses Interest payable Total accrued liabilities $ $

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	3 Months Ended
	Mar. 31, 2016
Stockholders' Equity
Schedule of computation of basic and diluted net loss per share	The following table shows the computation of basic and diluted net loss per share for the three months ended March 31, 2016 and 2015 (in thousands, except per share amounts): Three Months Ended March 31, 2016 2015 Net income (loss) $ $ Less: Preferred stock dividends Net loss allocable to participating securities (1)(2) — — Net income (loss) attributable to common stockholders $ $ Weighted average number of unrestricted outstanding common shares used to calculate basic net earnings (loss) per share Dilutive shares (3)(4) — — Denominator for diluted earnings (loss) per common share Net income (loss) per common share - basic and diluted $ $ (1) The Company’s restricted shares of common stock are participating securities. (2) For the three months ended March 31, 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 three months ended March 31, 2016 excludes 685,597 shares of weighted average restricted stock and 12,520,179 shares of common stock resulting from an assumed conversion of the Series A Preferred Stock and Series B Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive. The three months ended March 31, 2015 excludes 1,556,115 shares of weighted average restricted stock and 12,530,695 shares of common stock resulting from an assumed conversion of the Series A Preferred Stock and Series B Preferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive.

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2016
Stock-Based Compensation
Schedule of stock-based compensation expense	The Company recognized the following stock-based compensation expense (in thousands) which is included in general and administrative expense in the condensed consolidated statements of operations: Three Months Ended March 31, 2016 2015 Restricted stock awards, directors $ $ Restricted stock awards, non-employees Total stock-based compensation expense $ $
Summary of the status of the non-vested shares	A summary of the status of the non-vested shares for the three months ended March 31, 2016 and 2015 is presented below (in thousands): Three Months Ended March 31, March 31, 2016 2015 Non-vested common stock, beginning of period Granted Vested Forfeited Non-vested common stock, end of period

Condensed Consolidating Finan39

Condensed Consolidating Financial Information (Tables)	3 Months Ended
	Mar. 31, 2016
Condensed Consolidating Financial Information
Condensed balance sheet	March 31, 2016 Assets Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total current assets $ $ $ $ $ Total oil and natural gas properties, net - - - Investment in subsidiaries - - - Other assets - Total Assets $ $ $ $ $ Liabilities and Shareholders' Equity Current liabilities $ $ $ $ $ Long-term liabilities - - Total shareholders' equity (deficit) Total Liabilities and Shareholders' Equity (deficit) $ $ $ $ $ December 31, 2015 Assets Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total current assets $ $ $ $ $ Total oil and natural gas properties, net - - - Investment in subsidiaries - - - Other assets - Total Assets $ $ $ $ $ Liabilities and Shareholders' Equity Current liabilities $ $ $ $ $ Long-term liabilities - - Total shareholders' equity (deficit) Total Liabilities and Shareholders' Equity (deficit) $ $ $ $ $
Condensed income statement	Three Months Ended March 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total revenues $ - $ $ - $ - $ Total operating costs and expenses - Other income (expense) - Income (loss) before income taxes $ $ $ $ - $ Income tax expense - - - - - Equity in income (loss) of subsidiaries - - - Net income (loss) $ $ $ $ $ Three Months Ended March 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Total revenues $ - $ $ - $ - $ Total operating costs and expenses - Other income (expense) - - Income (loss) before income taxes $ $ $ $ - $ Income tax expense - Equity in income (loss) of subsidiaries - - - Net income (loss) $ $ $ $ $
Condensed cash flow statement	Three Months Ended March 31, 2016 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ $ $ $ - $ Net cash provided by (used in) investing activities Net cash provided by (used in) financing activities Net increase (decrease) in cash and cash equivalents $ $ - $ $ - $ Cash and cash equivalents, beginning of period - - Cash and cash equivalents, end of period $ $ - $ $ - $ Three Months Ended March 31, 2015 Parent Company Combined Guarantor Subsidiaries Combined Non-Guarantor Subsidiaries Eliminations Consolidated Net cash provided by (used in) operating activities $ $ $ $ - $ Net cash provided by (used in) investing activities - Net cash provided by (used in) financing activities Net increase (decrease) in cash and cash equivalents $ $ - $ - $ - $ Cash and cash equivalents, beginning of period - - Cash and cash equivalents, end of period $ $ - $ - $ - $

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	3 Months Ended
	Mar. 31, 2016
Variable Interest Entities
Schedule of carrying amounts of assets and liabilities of VIEs	Below is a tabular comparison of the carrying amounts of the assets and liabilities of the VIEs and the Company’s maximum exposure to loss as of March 31, 2016 and December 31, 2015 (in thousands): March 31, December 31, 2016 2015 Capital investments $ $ Earnings in equity investments — Equity in equity investments $ $ March 31, December 31, 2016 2015 Equity in equity investments $ $ Guarantees of capital investments Maximum exposure to loss $ $

Basis of Presentation and Sum41

Basis of Presentation and Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Mar. 31, 2016
New accounting pronouncement
Long term debt, net of premium, discount and debt issuance costs	$ 1,705,927,000	$ 1,706,367,000
Scenario, Adjustment [Member] | ASU-Imputation of interest
New accounting pronouncement
Long term debt, net of premium, discount and debt issuance costs	(41,039)
Debt issuance costs	$ (41,039)

Acquisitions and Divestitures42

Acquisitions and Divestitures (Details) $ in Thousands	Jun. 30, 2014USD ($)item	Mar. 31, 2016	Jun. 27, 2014
Senior Notes 6.125 Percent Due 2023
Acquisitions
Interest rate (as a percent)		6.125%	6.125%
Catarina
Total purchase price allocated to assets purchased and liabilities assumed
Proved oil and natural gas properties	$ 446,906
Unproved properties	122,224
Other assets acquired	2,682
Fair value of assets acquired	571,812
Asset retirement obligations	(14,723)
Fair value of net assets acquired	$ 557,089
Gross producing wells | item	176

Acquisitions and Divestitures43

Acquisitions and Divestitures (Divestitures) (Details)	Oct. 14, 2015USD ($)abbl / dMcf / dshares	Aug. 04, 2015	Mar. 31, 2015USD ($)itemshares	Mar. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)
Divestitures
Investments				$ 55,721,000	$ 49,985,000
Palmetto
Divestitures
Percentage of working interest initially conveyed per wellbore			18.25%
Palmetto | Disposed of by sale, not discontinued operations
Divestitures
Number of wellbores having partial interest | item			59
Adjusted purchase price			$ 83,400,000
Percentage of working interest owned			47.50%
Percentage of working interest retained per wellbore			2.50%
Consideration in cash			$ 83,000,000
Adjusted consideration in cash			$ 81,400,000
Western Catarina Midstream Divestiture
Divestitures
Consideration	$ 345,800,000
Common units (in shares) | shares	105,263
Term of agreement	15 years
Area under agreement (in acres) | a	35,000
Term of gas gathering agreement	5 years
Deferred gain	$ 74,100,000
SPP | Palmetto | Disposed of by sale, not discontinued operations
Divestitures
Common units (in shares) | shares			1,052,632
Investments			$ 2,000,000
Stock split (as a percent)		0.10
SPP | Prior to Stock Split | Palmetto | Disposed of by sale, not discontinued operations
Divestitures
Common units (in shares) | shares				105,263
Crude oil | Western Catarina Midstream Divestiture
Divestitures
Daily delivery commitment (in units) | bbl / d	10,200
Gathering and processing fees	$ 0.96
Natural gas | Western Catarina Midstream Divestiture
Divestitures
Daily delivery commitment (in units) | Mcf / d	142,000
Gathering and processing fees	$ 0.74

Cash and Cash Equivalents (Deta

Cash and Cash Equivalents (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014
Cash and cash equivalents
Total cash and cash equivalents	$ 362,221	$ 435,048	$ 345,338	$ 473,714
Cash at banks
Cash and cash equivalents
Total cash and cash equivalents	336,250	35,600
Money market funds
Cash and cash equivalents
Total cash and cash equivalents	$ 25,971	$ 399,448

Oil and Natural Gas Properties

Oil and Natural Gas Properties (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Oil and Natural Gas Properties
Impairment expense	$ 22,084	$ 441,450

Long-Term Debt (Summary) (Detai

Long-Term Debt (Summary) (Details) - USD ($)	Sep. 12, 2014	Sep. 18, 2013	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Feb. 27, 2015	Jul. 18, 2014	Jun. 27, 2014	Jun. 13, 2013
Long-Term Debt
Face value of debt			$ 1,750,000,000		$ 1,750,000,000
Unamortized debt issuance costs			(40,757,000)		(41,039,000)
Total long-term debt			1,706,367,000		1,705,927,000
Interest expense
Interest on Senior Notes			(29,235,000)	$ (29,235,000)
Interest expense and commitment fees on credit agreement			(297,000)	(281,000)
Amortization of debt issuance costs			(1,915,000)	(1,815,000)
Amortization of discount on Additional 7.75% notes			(226,000)	(226,000)
Amortization of premium on Additional 6.125% notes			67,000	(1,000)
Total interest expense			$ (31,606,000)	$ (31,558,000)
Senior Notes 7.75 Percent Due 2021
Long-Term Debt
Interest rate (as a percent)			7.75%						7.75%
Face value of debt		$ 200,000,000	$ 600,000,000		600,000,000		$ 600,000,000		$ 400,000,000
Unamortized discount on Additional 7.75% Notes		(7,000,000)	$ (4,708,000)		(4,933,000)
Debt issuance costs		$ 4,200,000
Senior Notes 6.125 Percent Due 2023
Long-Term Debt
Interest rate (as a percent)			6.125%					6.125%
Face value of debt	$ 300,000,000		$ 1,150,000,000		1,150,000,000	$ 1,150,000,000		$ 850,000,000
Unamortized premium on Additional 6.125% Notes	2,300,000		$ 1,832,000		1,899,000
Debt issuance costs	$ 6,400,000
Scenario, Adjustment [Member] | ASU-Imputation of interest
Long-Term Debt
Total long-term debt					(41,039)
Debt issuance costs					$ (41,039)

Long-Term Debt (Detail) (Detail

Long-Term Debt (Detail) (Details) $ in Thousands	Sep. 12, 2014USD ($)	Jun. 30, 2014USD ($)	Jun. 27, 2014USD ($)	Sep. 18, 2013USD ($)	Jun. 13, 2013USD ($)	Mar. 31, 2016USD ($)	Mar. 31, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2013USD ($)	Dec. 31, 2015USD ($)	Feb. 27, 2015USD ($)	Jul. 18, 2014USD ($)	May. 12, 2014USD ($)	May. 31, 2013USD ($)
Long-Term Debt
Face value of debt						$ 1,750,000				$ 1,750,000
Interest expense						31,606	$ 31,558
Senior Notes 7.75 Percent Due 2021
Long-Term Debt
Face value of debt				$ 200,000	$ 400,000	$ 600,000				600,000		$ 600,000
Interest rate (as a percent)					7.75%	7.75%
Proceeds for issuance of notes, net of discount/premium and related offering expenses				$ 188,800	$ 388,000				$ 192,900
Percentage value of Additional Notes at which they are offered in private offering				96.50%
Debt issuance cost				$ 4,200
Proceeds from Interest Received									$ 4,100
Senior Notes 7.75 Percent Due 2021 | Prior to June 15, 2017
Long-Term Debt
Redemption price of debt instrument (as a percent)						100.00%
Percentage of debt instrument redeem under certain circumstances						35.00%
Senior Notes 6.125 Percent Due 2023
Long-Term Debt
Face value of debt	$ 300,000		$ 850,000			$ 1,150,000				$ 1,150,000	$ 1,150,000
Interest rate (as a percent)			6.125%			6.125%
Proceeds for issuance of notes, net of discount/premium and related offering expenses	$ 295,900		$ 829,000					$ 299,700
Percentage value of Additional Notes at which they are offered in private offering	100.75%
Debt issuance cost	$ 6,400
Proceeds from Interest Received								$ 3,800
Percentage of debt instrument redeem under certain circumstances						35.00%
Senior Notes 6.125 Percent Due 2023 | Prior to July 15, 2018
Long-Term Debt
Redemption price of debt instrument (as a percent)						100.00%
Previous First Lien Credit Agreement
Long-Term Debt
Maximum borrowing capacity														$ 500,000
Face value of debt													$ 100,000
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
Borrowing base						$ 350,000
Aggregate elected commitment amount		$ 300,000				298,500
Credit facility used						0
Percentage of increased net debt used to calculate reduction in borrowing base		25.00%
Percentage of value of asset sales and swaps terminations		10.00%
Threshold of allowed hedging		$ 10,000
Permitted capital utilization towards formation and capitalization of subsidiaries						150,000
Permitted capital utilization by subsidiaries						150,000
Accelerated repayment clause, usage of unrestricted cash in excess of threshold amount						35,000
Second Amended And Restated Credit Agreement | Minimum
Long-Term Debt
Current ratio		1
Second Amended And Restated Credit Agreement | Maximum
Long-Term Debt
Percentage of commitment fee on the unused committed amount		0.50%
Ratio of total debt outstanding to consolidated EBITDA		2
Second Amended And Restated Credit Agreement | Alternate base rate | Minimum
Long-Term Debt
Variable rate basis, spread percentage		1.00%
Second Amended And Restated Credit Agreement | Alternate base rate | Maximum
Long-Term Debt
Variable rate basis, spread percentage		2.00%
Second Amended And Restated Credit Agreement | Eurodollar rate | Minimum
Long-Term Debt
Variable rate basis, spread percentage		2.00%
Second Amended And Restated Credit Agreement | Eurodollar rate | Maximum
Long-Term Debt
Variable rate basis, spread percentage		3.00%
Letters of credit
Long-Term Debt
Maximum borrowing capacity		$ 80,000
Amount outstanding						$ 0

Derivative Instruments (Details

Derivative Instruments (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2016USD ($)MMBTU$ / bbl$ / MMBTUbbl	Mar. 31, 2015USD ($)
Reconciliation of the changes in fair value of the commodity derivatives
Beginning fair value of commodity derivatives	$ 178,283
Net premiums on derivative contracts	6,103	$ 121
Ending fair value of commodity derivatives	141,778
Crude oil
Reconciliation of the changes in fair value of the commodity derivatives
Net gains on derivatives	5,126
Net settlements on derivative contracts	(49,827)
Net premiums on derivative contracts	6,103
Natural gas
Reconciliation of the changes in fair value of the commodity derivatives
Net gains on derivatives	11,528
Net settlements on derivative contracts	$ (9,435)
Not designated as hedges | Swaps | 2016 | Crude oil
Derivative contract covering anticipated future production
Notional amount (in barrels) | bbl	1,925,000
Average price per unit | $ / bbl	70.11
Not designated as hedges | Swaps | 2016 | Natural gas
Derivative contract covering anticipated future production
Notional amount (in Mmbtu) | MMBTU	26,735,000
Average price per unit | $ / MMBTU	3.13
Not designated as hedges | Swaps | 2017 | Natural gas
Derivative contract covering anticipated future production
Notional amount (in Mmbtu) | MMBTU	27,945,000
Average price per unit | $ / MMBTU	3
Not designated as hedges | Puts | 2016 | Crude oil
Derivative contract covering anticipated future production
Notional amount (in barrels) | bbl	3,025,000
Not designated as hedges | Puts | Puts | 2016 | Crude oil
Derivative contract covering anticipated future production
Average option price per unit | $ / bbl	60
Minimum | Not designated as hedges | Swaps | 2016 | Crude oil
Derivative contract covering anticipated future production
Price per barrel/ Mmbtu | $ / bbl	62
Minimum | Not designated as hedges | Swaps | 2016 | Natural gas
Derivative contract covering anticipated future production
Price per barrel/ Mmbtu | $ / MMBTU	2.54
Minimum | Not designated as hedges | Swaps | 2017 | Natural gas
Derivative contract covering anticipated future production
Price per barrel/ Mmbtu | $ / MMBTU	2.89
Minimum | Not designated as hedges | Puts | Puts | 2016 | Crude oil
Derivative contract covering anticipated future production
Price per barrel/ Mmbtu | $ / bbl	60
Maximum | Not designated as hedges | Swaps | 2016 | Crude oil
Derivative contract covering anticipated future production
Price per barrel/ Mmbtu | $ / bbl	80.15
Maximum | Not designated as hedges | Swaps | 2016 | Natural gas
Derivative contract covering anticipated future production
Price per barrel/ Mmbtu | $ / MMBTU	3.92
Maximum | Not designated as hedges | Swaps | 2017 | Natural gas
Derivative contract covering anticipated future production
Price per barrel/ Mmbtu | $ / MMBTU	3.65
Maximum | Not designated as hedges | Puts | Puts | 2016 | Crude oil
Derivative contract covering anticipated future production
Price per barrel/ Mmbtu | $ / bbl	60

Derivative Instruments (BalShee

Derivative Instruments (BalSheet) (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	$ 141,832	$ 178,339
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(54)	(56)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	141,778	178,283
Offsetting Derivative Liabilities:
Gross Amount of Recognized Assets	(54)	(56)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	54	56
Current asset
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	136,507	172,518
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(28)	(24)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	136,479	172,494
Long-term asset
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	5,325	5,821
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(26)	(32)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	5,299	5,789
Current liability
Offsetting Derivative Liabilities:
Gross Amount of Recognized Assets	(28)	(24)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	28	24
Long-term liability
Offsetting Derivative Liabilities:
Gross Amount of Recognized Assets	(26)	(32)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	$ 26	$ 32

Investments (Details)

Investments (Details) $ in Thousands	Oct. 02, 2015USD ($)MMcfMcf	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Investments in marketable securities
Equity method gains (losses)		$ 512
Midstream Processing Plant
Investments in marketable securities
Amount committed	$ 80,000	20,000
Ownership of equity investment (as a percent)	50.00%
Equity method investment cost			$ 20,000
Equity method gains (losses)		(12)
Midstream Gathering System
Investments in marketable securities
Amount committed	$ 35,000	22,700
Ownership of equity investment (as a percent)	50.00%
Equity method investment cost			$ 22,700
Equity method gains (losses)		523
SOII Facility
Investments in marketable securities
Gas processing plant capacity per day (in MMcf) | Mcf	125,000
Amount committed	$ 12,500	$ 12,500
Ownership of equity investment (as a percent)	10.00%
Targa | SOII Facility
Investments in marketable securities
Ownership of equity investment (as a percent)	90.00%
Minimum | Midstream Processing Plant
Investments in marketable securities
Gas processing plant capacity per day (in MMcf) | MMcf	200
Maximum | Midstream Processing Plant
Investments in marketable securities
Gas processing plant capacity per day (in MMcf) | MMcf	260

Fair Value of Financial Instr51

Fair Value of Financial Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Unobservable Inputs (Level 3)
Fair Value of Financial Instruments
Derivative instruments	$ 0	$ 0
Recurring basis
Fair Value of Financial Instruments
Cash and cash equivalents	25,971	399,448
Total	167,749	577,731
Recurring basis | Active Market for Identical Assets (Level 1)
Fair Value of Financial Instruments
Cash and cash equivalents	25,971	399,448
Total	25,971	399,448
Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Total	141,778	178,283
Swaps | Crude oil | Recurring basis
Fair Value of Financial Instruments
Derivative instruments	54,520	72,887
Swaps | Crude oil | Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments	54,520	72,887
Swaps | Natural gas | Recurring basis
Fair Value of Financial Instruments
Derivative instruments	30,905	28,813
Swaps | Natural gas | Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments	30,905	28,813
Enhanced swaps | Crude oil | Recurring basis
Fair Value of Financial Instruments
Derivative instruments		76,583
Enhanced swaps | Crude oil | Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments		$ 76,583
Puts | Crude oil | Recurring basis
Fair Value of Financial Instruments
Derivative instruments	56,353
Puts | Crude oil | Recurring basis | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments	$ 56,353

Fair Value of Financial Instr52

Fair Value of Financial Instruments (Other) (Details) - USD ($) $ in Millions	Nov. 20, 2015	May. 29, 2014	Feb. 12, 2014	Mar. 31, 2016	Jun. 27, 2014	Jun. 13, 2013	Mar. 26, 2013
Senior Notes 7.75 Percent Due 2021
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Interest rate (as a percent)				7.75%		7.75%
Senior Notes 6.125 Percent Due 2023
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Interest rate (as a percent)				6.125%	6.125%
Estimated fair value | Senior Notes 7.75 Percent Due 2021 | 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
Debt fair value				$ 348
Estimated fair value | Senior Notes 6.125 Percent Due 2023 | 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
Debt fair value				$ 609.5
Preferred Class B
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Preferred stock converted into shares of common stock	4,500	210,820	756,850
Conversion ratio (in shares)	2.337		2.337				2.337
Shares of common stock issued upon conversion of preferred stock	10,517	553,980	2,021,066

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Changes in the asset retirement obligation
Abandonment liability, beginning of period	$ 25,907	$ 25,694
Liabilities incurred during period	210	6,021
Divestitures	(131)	(379)
Revisions		(7,623)
Accretion expense	481	2,194
Abandonment liability, end of period	$ 26,467	$ 25,907

Related Party Transactions (Det

Related Party Transactions (Details) $ in Thousands	1 Months Ended		3 Months Ended
	Aug. 31, 2015USD ($)item	Aug. 31, 2013USD ($)aitemshares	Mar. 31, 2016USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)
Related Party Transactions
Accounts receivable - related entities | $			$ 3,636		$ 3,697
TMS
Related Party Transactions
Number of sellers | item		3
Number of third-parties | item		2
Number of related parties | item		1
Ownership interest in total area of property (as a percent)		50.00%
Cash paid | $		$ 70,000
Common stock issued in acquisition (in shares) | shares		342,760
Company valued | $		$ 7,500
SOG
Related Party Transactions
Administrative fees | $			12,084	$ 6,252
Third-party expenses | $			3,084	766
Total included in general and administrative expenses | $			15,168	$ 7,018
Accounts receivable - related entities | $			3,600		3,700
SR | TMS
Related Party Transactions
Area of property acquired (in acres) | a		40,000
Number of wells to be drilled within Area of Mutual Interest for which the entity has obligation in working interest in well costs, gross | item		3
Number of wells to be drilled within Area of Mutual Interest for which the entity has obligation in working interest in well costs, net | item		1.5
Cash consideration | $		$ 14,400
Obligation for working interest for partner's portion of the completed well costs, on the initial wells to be drilled within the AMI (as a percent)		50.00%
Additional number of wells to be drilled within Area of Mutual Interest for which the entity has obligation in working interest in well costs, gross | item		6
Additional number of wells to be drilled within Area of Mutual Interest for which the entity has obligation in working interest in well costs, net | item		3
Amount payable in lieu of drilling the two additional wells | $	$ 8,000
Number of additional wells planned for deferred drilling | item	2
SR | TMS | Maximum
Related Party Transactions
Number of wells to be drilled within Area of Mutual Interest for which the entity has obligation in working interest in well costs, gross | item		6
Number of wells to be drilled within Area of Mutual Interest for which the entity has obligation in working interest in well costs, net | item		3
SPP
Related Party Transactions
Accounts payable - related entities | $			$ 4,600		$ 4,400

Related Party Transactions (Div

Related Party Transactions (Divestiture) (Details) - Western Catarina Midstream Divestiture	Oct. 14, 2015USD ($)abbl / dMcf / dshares
Divestiture
Common units (in shares) | shares	105,263
Term of agreement	15 years
Area under agreement (in acres) | a	35,000
Term of gas gathering agreement	5 years
Crude oil
Divestiture
Daily delivery commitment (in units) | bbl / d	10,200
Gathering and processing fees	$ 0.96
Natural gas
Divestiture
Daily delivery commitment (in units) | Mcf / d	142,000
Gathering and processing fees	$ 0.74

Accrued Liabilities (Details)

Accrued Liabilities (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Accrued Liabilities
Capital expenditures	$ 57,580	$ 51,983
General and administrative costs	3,789	5,214
Production taxes	2,059	2,532
Ad valorem taxes	2,074	886
Lease operating expenses	24,367	27,077
Interest payable	28,281	34,265
Total accrued liabilities	$ 118,150	$ 121,957

Stockholders' Equity (Details)

Stockholders' Equity (Details) $ / shares in Units, $ in Millions	Nov. 20, 2015shares	Jul. 28, 2015itemshares	Aug. 28, 2014USD ($)shares	Jun. 12, 2014USD ($)$ / sharesshares	May. 29, 2014USD ($)shares	Feb. 12, 2014USD ($)shares	Sep. 18, 2013USD ($)$ / sharesshares	Mar. 26, 2013USD ($)$ / sharesshares	Sep. 17, 2012USD ($)$ / sharesshares	Mar. 31, 2016item$ / shares	Dec. 31, 2015$ / shares
Common stock, par value (in dollars per share) | $ / shares										$ 0.01	$ 0.01
Fair value of the shares of common stock issued in excess of the carrying value of the Series A Preferred Stock and Series B Preferred Stock redeemed | $			$ 0.3		$ 3.1	$ 13.9
Number of rights declared for each common stock		1
Number of rights automatically attached | item		1
Common Stock
Number of shares issued				5,000,000			11,040,000
Number of shares issued pursuant to the exercise of over-allotment option by underwriters							1,440,000
Issue price (in dollars per share) | $ / shares				$ 35.25			$ 23
Net proceeds from public offering of shares of common stock | $				$ 167.5			$ 241.4
Payments for offering costs | $				$ 8.7			$ 12.5
Number of shares of common stock to be issued if all preferred shares are converted									4,275,640
Preferred Class A
Number of shares issued									3,000,000
Issue price (in dollars per share) | $ / shares									$ 50
Proceeds from the private placement of preferred stock | $									$ 144.5
Payments for offering costs | $									$ 5.5
Conversion ratio (in shares)						2.325			2.325
Conversion price (in dollars per share) | $ / shares									$ 21.51
Annual dividend (as a percent)										4.875%	4.875%
Liquidation preference (in dollars per share) | $ / shares										$ 50
Number of directors who can be elected upon failure to pay dividend for six or more quarters | item										2
Preferred stock converted into shares of common stock			47,500		166,025	947,490
Shares of common stock issued upon conversion of preferred stock			119,320		418,715	2,425,574
Preferred Class A | Minimum
Period of failure to pay dividend, resulting into appointment of board of directors										1 year 6 months
Condition for automatic conversion: Closing sale price of common stock as a percentage of conversion price for specified period prior to conversion										130.00%
Preferred Class B
Number of shares issued								4,500,000
Issue price (in dollars per share) | $ / shares								$ 50
Proceeds from the private placement of preferred stock | $								$ 216.6
Payments for offering costs | $								$ 8.4
Conversion ratio (in shares)	2.337					2.337		2.337
Conversion price (in dollars per share) | $ / shares								$ 21.40
Number of shares of common stock to be issued if all preferred shares are converted								8,255,055
Annual dividend (as a percent)										6.50%	6.50%
Liquidation preference (in dollars per share) | $ / shares										$ 50
Number of directors who can be elected upon failure to pay dividend for six or more quarters | item										2
Preferred stock converted into shares of common stock	4,500				210,820	756,850
Shares of common stock issued upon conversion of preferred stock	10,517				553,980	2,021,066
Preferred Class B | Minimum
Period of failure to pay dividend, resulting into appointment of board of directors										1 year 6 months
Condition for automatic conversion: Closing sale price of common stock as a percentage of conversion price for specified period prior to conversion										130.00%

Stockholders' Equity (EPS) (Det

Stockholders' Equity (EPS) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Earnings (Loss) Per Share
Net income (loss)	$ (65,774)	$ (497,345)
Preferred stock dividends	(3,987)	(3,991)
Net loss allocable to participating securities	0	0
Net loss attributable to common stockholders	$ (69,761)	$ (501,336)
Weighted average number of unrestricted outstanding common shares used to calculate basic net earnings (loss) per share	58,099,000	56,805,000
Denominator for diluted net earnings (loss) per common share	58,099,000	56,805,000
Net income (loss) per common share - basic and diluted (in dollars per share)	$ (1.20)	$ (8.83)
Restricted stock
Earnings (Loss) Per Share
Anti-dilutive common stock	685,597	1,556,115
Convertible Preferred Stock
Earnings (Loss) Per Share
Anti-dilutive common stock	12,520,179	12,530,695

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Stock-Based Compensation
Maximum number of shares of common stock	4,000,000
Common stock available for incentive awards, as a percentage of the issued and outstanding shares of common stock	15.00%
Total stock-based compensation expense	$ 3,344	$ 7,694
Aggregate Intrinsic Value
Non-vested common stock, beginning of period (in dollars)	4,426	2,718
Granted (in dollars)	3,096	2,538
Vested (in dollars)	(1,107)	(1,083)
Forfeited (in dollars)	(363)	(60)
Non-vested common stock, end of period (in dollars)	6,052	4,113
Non-employees
Stock-Based Compensation
Total stock-based compensation expense	$ 3,112	7,412
Restricted stock
Additional disclosure related to compensation cost
Closing price of common stock (in dollars per share)	$ 5.49
Unrecognized compensation costs related to non-vested restricted shares outstanding	$ 32,800
Expected average period for recognition of unrecognized compensation costs related to non-vested shares	2 years 3 months 18 days
Number of Non-Vested Shares
Shares available for future issuance to participants	4,900,000
Restricted stock | Employees of SOG, with whom the company has a services agreement
Stock-Based Compensation
Vesting period	3 years
Number of Non-Vested Shares
Granted (in shares)	3,100,000
Restricted stock | Directors
Stock-Based Compensation
Total stock-based compensation expense	$ 232	$ 282
Number of Non-Vested Shares
Granted (in shares)	0
PARS, PAPS, and Phantom Stock award shares
Additional disclosure related to compensation cost
Closing price of common stock (in dollars per share)	$ 5.49
Unrecognized compensation costs related to non-vested restricted shares outstanding	$ 13,900
Expected average period for recognition of unrecognized compensation costs related to non-vested shares	2 years 8 months 23 days

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Taxes
Effective tax rate (as a percent)	0.00%	(1.50%)
Federal statutory corporate income tax rate (as a percent)	35.00%	35.00%
Net operating loss carryforwards	$ 863.7
Valuation allowance	537
Net deferred tax assets	$ 0

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	Feb. 05, 2015	Dec. 16, 2013claim	Mar. 31, 2016USD ($)aitem	Dec. 31, 2015USD ($)	Oct. 02, 2015USD ($)
Operating leases
Lease payment obligation			$ 253.2
Catarina
Commitments and contingencies
Area of undeveloped acreage acquired (in acres) | a			77,000
Maximum number of wells to be drilled in each annual period commencing July 1, 2014 | item			50
Minimum number of wells to be drilled in any consecutive 120 days period in order to continue to maintain rights to any future undeveloped acreage | item			1
Consecutive period over which at least one well can be drilled in order to continue to maintain rights to any future undeveloped acreage			120 days
Maximum number of wells that can be carried over to satisfy part of the 50 well requirement in the subsequent annual period on a well for well basis | item			30
Consolidated Derivative Actions
Commitments and contingencies
Number of derivative actions filed | claim		3
Martin v. Sanchez
Commitments and contingencies
Period for which derivative action was stayed	60 days
Corporate office Lease
Operating leases
Lease payment obligation			$ 49.5
Land Lease
Operating leases
Lease payment obligation			$ 7.1
Advanced written notice required to terminate lease obligation			180 days
Lease termination penalty			$ 1
Acreage Lease
Operating leases
Lease payment obligation			$ 6.3
Term of lease			10 years
Advanced written notice required to terminate lease obligation			6 months
Permanent improvements
Operating leases
Lease payment obligation			$ 4
Term of lease			10 years
Western Catarina Midstream Divestiture
Operating leases
Lease payment obligation			$ 190.2
Midstream Processing Plant
Investment
Amount committed			20		$ 80
Ownership of equity investment (as a percent)					50.00%
Equity method investment cost				$ 20
Remaining amount committed			60
Estimated cost of project					$ 160
Minimum ownership (as a percent)					20.00%
Midstream Gathering System
Investment
Amount committed			22.7		$ 35
Ownership of equity investment (as a percent)					50.00%
Equity method investment cost				$ 22.7
Remaining amount committed			$ 12.3

Subsidiary Guarantors (Details)

Subsidiary Guarantors (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	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
Senior Notes 7.75 Percent Due 2021
Ownership interest in Subsidiaries (as a percent)	100.00%
Interest rate (as a percent)	7.75%		7.75%
Senior Notes 6.125 Percent Due 2023
Ownership interest in Subsidiaries (as a percent)	100.00%
Interest rate (as a percent)	6.125%	6.125%

Condensed Consolidating Finan63

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

Condensed Consolidating Finan64

Condensed Consolidating Financial Information (BalanceSheet) (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Assets
Total current assets	$ 558,522	$ 666,618
Total oil and natural gas properties, net	779,457	756,103
Other assets	83,224	78,583
Total assets	1,421,203	1,501,304
Liabilities and Shareholders' Equity
Current liabilities	156,793	167,506
Long-term liabilities	1,787,533	1,789,967
Total shareholders' equity (deficit)	(523,123)	(456,169)
Total liabilities and stockholders’ deficit	1,421,203	1,501,304
Eliminations
Assets
Total current assets	(152,613)	(42,369)
Investment in subsidiaries	(662,487)	(700,053)
Total assets	(815,100)	(742,422)
Liabilities and Shareholders' Equity
Current liabilities	(152,613)	(42,369)
Total shareholders' equity (deficit)	(662,487)	(700,053)
Total liabilities and stockholders’ deficit	(815,100)	(742,422)
Parent Company
Assets
Total current assets	628,323	671,278
Investment in subsidiaries	662,487	700,053
Other assets	13,727	14,481
Total assets	1,304,537	1,385,812
Liabilities and Shareholders' Equity
Current liabilities	67,515	78,840
Long-term liabilities	1,761,065	1,764,060
Total shareholders' equity (deficit)	(524,043)	(457,088)
Total liabilities and stockholders’ deficit	1,304,537	1,385,812
Combined Guarantor Subsidiaries
Assets
Total current assets	10,007	37,005
Total oil and natural gas properties, net	779,457	756,103
Other assets	17,524	17,737
Total assets	806,988	810,845
Liabilities and Shareholders' Equity
Current liabilities	121,846	88,666
Long-term liabilities	26,468	25,907
Total shareholders' equity (deficit)	658,674	696,272
Total liabilities and stockholders’ deficit	806,988	810,845
Combined Non-Guarantor Subsidiaries
Assets
Total current assets	72,805	704
Other assets	51,973	46,365
Total assets	124,778	47,069
Liabilities and Shareholders' Equity
Current liabilities	120,045	42,369
Total shareholders' equity (deficit)	4,733	4,700
Total liabilities and stockholders’ deficit	$ 124,778	$ 47,069

Condensed Consolidating Finan65

Condensed Consolidating Financial Information (IncomeStatement) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Condensed Income Statements, Captions [Line Items]
Total revenues	$ 79,816	$ 110,593
Total operating costs and expenses	137,165	608,417
Other income (expense)	(8,425)	7,921
Income (loss) before income taxes	(65,774)	(489,903)
Income tax expense		7,442
Net loss	(65,774)	(497,345)
Eliminations
Condensed Income Statements, Captions [Line Items]
Equity in income (loss) of subsidiaries	37,566	476,002
Net loss	37,566	476,002
Parent Company
Condensed Income Statements, Captions [Line Items]
Total operating costs and expenses	19,684	21,786
Other income (expense)	(8,524)	7,885
Income (loss) before income taxes	(28,208)	(13,901)
Income tax expense		(40,275)
Equity in income (loss) of subsidiaries	(37,566)	(476,002)
Net loss	(65,774)	(449,628)
Combined Guarantor Subsidiaries
Condensed Income Statements, Captions [Line Items]
Total revenues	79,816	110,593
Total operating costs and expenses	117,002	586,315
Other income (expense)	(413)	36
Income (loss) before income taxes	(37,599)	(475,686)
Income tax expense		48,112
Net loss	(37,599)	(523,798)
Combined Non-Guarantor Subsidiaries
Condensed Income Statements, Captions [Line Items]
Total operating costs and expenses	479	316
Other income (expense)	512
Income (loss) before income taxes	33	(316)
Income tax expense		(395)
Net loss	$ 33	$ 79

Condensed Consolidating Finan66

Condensed Consolidating Financial Information (CashFlows) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	$ 24,137	$ 63,800
Net cash provided by (used in) investing activities	(91,219)	(187,785)
Net cash provided by (used in) financing activities	(5,745)	(4,391)
Decrease in cash and cash equivalents	(72,827)	(128,376)
Cash and cash equivalents, beginning of period	435,048	473,714
Cash and cash equivalents, end of period	362,221	345,338
Eliminations
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) investing activities	142,849	96,901
Net cash provided by (used in) financing activities	(142,849)	(96,901)
Parent Company
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	3,705	(27,868)
Net cash provided by (used in) investing activities	(143,077)	(96,118)
Net cash provided by (used in) financing activities	(5,745)	(4,390)
Decrease in cash and cash equivalents	(145,117)	(128,376)
Cash and cash equivalents, beginning of period	434,933	473,714
Cash and cash equivalents, end of period	289,816	345,338
Combined Guarantor Subsidiaries
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	20,620	91,687
Net cash provided by (used in) investing activities	(85,767)	(188,568)
Net cash provided by (used in) financing activities	65,147	96,881
Combined Non-Guarantor Subsidiaries
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	(188)	(19)
Net cash provided by (used in) investing activities	(5,224)
Net cash provided by (used in) financing activities	77,702	$ 19
Decrease in cash and cash equivalents	72,290
Cash and cash equivalents, beginning of period	115
Cash and cash equivalents, end of period	$ 72,405

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Millions	Mar. 31, 2016	Oct. 02, 2015
Midstream Processing Plant
Variable Interest Entity [Line Items]
Ownership of equity investment (as a percent)		50.00%
Amount committed	$ 20	$ 80
Midstream Gathering System
Variable Interest Entity [Line Items]
Ownership of equity investment (as a percent)		50.00%
Amount committed	22.7	$ 35
SOII Facility
Variable Interest Entity [Line Items]
Ownership of equity investment (as a percent)		10.00%
Amount committed	$ 12.5	$ 12.5
Targa | SOII Facility
Variable Interest Entity [Line Items]
Ownership of equity investment (as a percent)		90.00%

Variable Interest Entities (Car

Variable Interest Entities (Carrying Amounts) (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Variable Interest Entities
Capital investments	$ 55,209	$ 49,985
Earnings in equity investments	512
Equity in equity investments	55,721	49,985
Guarantees of capital investments	59,817	65,015
Maximum exposure to loss	$ 115,538	$ 115,000