Sanchez Energy (SNECQ) 10-Q 9 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Nov. 06, 2015
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	Sep. 30, 2015
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		61,914,572
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 196,884	$ 473,714
Oil and natural gas receivables	34,686	69,795
Joint interest billings receivables	1,662	14,676
Accounts receivable - related entities	3,790	386
Fair value of derivative instruments	131,991	100,181
Other current assets	19,210	23,002
Total current assets	388,223	681,754
Oil and natural gas properties, at cost, using the full cost method:
Unproved oil and natural gas properties	322,149	385,827
Proved oil and natural gas properties	3,052,929	2,582,441
Total oil and natural gas properties	3,375,078	2,968,268
Less: Accumulated depreciation, depletion, amortization and impairment	(2,365,396)	(706,590)
Total oil and natural gas properties, net	1,009,682	2,261,678
Other assets:
Debt issuance costs, net	43,256	48,168
Fair value of derivative instruments	30,442	24,024
Deferred tax asset	39,840	40,685
Investments	1,136
Other assets	19,641	19,101
Total assets	1,532,220	3,075,410
Current liabilities:
Accounts payable	16,542	29,487
Other payables	3,458	4,415
Accrued liabilities:
Capital expenditures	72,094	162,726
Other	65,981	67,162
Deferred premium liability	18,377
Deferred tax liability	39,840	33,242
Other current liabilities		5,166
Total current liabilities	216,292	302,198
Long term debt, net of premium (discount)	1,746,807	1,746,263
Asset retirement obligations	34,559	25,694
Deferred premium liability	6,170
Fair value of derivative instruments		889
Other liabilities	1,969	779
Total liabilities	$ 2,005,797	$ 2,075,823
Commitments and Contingencies (Note 16)
Stockholders' equity (deficit):
Preferred stock ($0.01 par value, 15,000,000 shares authorized; 1,838,985 shares issued and outstanding as of September 30, 2015 and December 31, 2014 of 4.875% Convertible Perpetual Preferred Stock, Series A; 3,532,330 shares issued and outstanding as of September 30, 2015 and December 31, 2014 of 6.500% Convertible Perpetual Preferred Stock, Series B)	$ 53	$ 53
Common stock ($0.01 par value, 150,000,000 shares authorized; 61,885,306 and 58,580,870 shares issued and outstanding as of September 30, 2015 and December 31, 2014, respectively)	619	586
Additional paid-in capital	1,080,558	1,064,667
Accumulated deficit	(1,554,807)	(65,719)
Total stockholders’ equity (deficit)	(473,577)	999,587
Total liabilities and stockholders’ equity	$ 1,532,220	$ 3,075,410

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - $ / shares	9 Months Ended	12 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	15,000,000	15,000,000
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	61,885,306	58,580,870
Common stock, shares outstanding	61,885,306	58,580,870
Preferred Class A
Preferred stock, shares issued	1,838,985	1,838,985
Preferred stock, shares outstanding	1,838,985	1,838,985
Dividend rate (as a percent)	4.875%	4.875%
Preferred Class B
Preferred stock, shares issued	3,532,330	3,532,330
Preferred stock, shares outstanding	3,532,330	3,532,330
Dividend rate (as a percent)	6.50%	6.50%

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
REVENUES:
Oil sales	$ 69,532	$ 157,907	$ 244,554	$ 414,484
Natural gas liquid sales	17,055	27,309	48,602	43,918
Natural gas sales	27,939	22,134	73,091	35,171
Total revenues	114,526	207,350	366,247	493,573
OPERATING COSTS AND EXPENSES:
Oil and natural gas production expenses	40,345	34,380	110,166	64,203
Production and ad valorem taxes	3,038	10,916	20,011	29,161
Depreciation, depletion, amortization and accretion	89,167	93,463	296,541	225,297
Impairment of oil and natural gas properties	454,628	0	1,365,000	0
General and administrative (inclusive of stock-based compensation expense of $355 and $10, respectively, for the three months ended September 30, 2015 and 2014, and $15,924 and $25,888, respectively, for the nine months ended September 30, 2015 and 2014)	15,851	12,821	59,290	60,999
Total operating costs and expenses	603,029	151,580	1,851,008	379,660
Operating income (loss)	(488,503)	55,770	(1,484,761)	113,913
Other income (expense):
Interest income and other income (expense)	(753)	82	(1,804)	97
Interest expense	(31,442)	(27,612)	(94,500)	(58,145)
Net gains on commodity derivatives	103,996	47,416	111,550	6,399
Total other expense	71,801	19,886	15,246	(51,649)
Loss before income taxes	(416,702)	75,656	(1,469,515)	62,264
Income tax expense	158	26,625	7,600	21,946
Net loss	(416,860)	49,031	(1,477,115)	40,318
Less:
Preferred stock dividends	(3,991)	(4,274)	(11,973)	(29,599)
Net loss allocable to participating securities	0	(2,068)	0	(495)
Net income (loss) attributable to common stockholders	$ (420,851)	$ 42,689	$ (1,489,088)	$ 10,224
Net income (loss) per common share - basic (in dollars per share)	$ (7.33)	$ 0.77	$ (26.06)	$ 0.20
Weighted average number of shares used to calculate net income (loss) attributable to common stockholders - basic (in shares)	57,426	55,732	57,141	51,153
Net income (loss) per common share - diluted ( in dollars per share)	$ (7.33)	$ 0.69	$ (26.06)	$ 0.20
Weighted average number of shares used to calculate net income (loss) attributable to common stockholders - diluted (in shares)	57,426	68,340	57,141	51,153

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Operations (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Condensed Consolidated Statements of Operations
General and administrative, stock-based compensation expense (in dollars)	$ 355	$ 10	$ 15,924	$ 25,888

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Stockholders' Equity (Deficit) - 9 months ended Sep. 30, 2015 - 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, 2014	$ 18	$ 35	$ 586	$ 1,064,667	$ (65,719)	$ 999,587
Balance (in shares) at Dec. 31, 2014	1,839	3,532	58,581
Increase (Decrease) in Stockholders' Equity (Deficit)
Preferred stock dividends					(11,973)	(11,973)
Restricted stock awards, net of forfeitures			$ 33	(33)
Restricted stock awards, net of forfeitures (in shares)			3,304
Stock-based compensation				15,924		15,924
Net loss					(1,477,115)	(1,477,115)
Balance at Sep. 30, 2015	$ 18	$ 35	$ 619	$ 1,080,558	$ (1,554,807)	$ (473,577)
Balance (in shares) at Sep. 30, 2015	1,839	3,532	61,885

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (1,477,115)	$ 40,318
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion	296,541	225,297
Impairment of oil and natural gas properties	1,365,000	0
Stock-based compensation expense	15,924	25,888
Net gains on commodity derivative contracts	(111,550)	(6,399)
Net cash settlement received (paid) on commodity derivative contracts	89,558	(9,652)
Cash reimbursements received for operating leasehold improvements	2,650
Premiums paid on derivative contracts	(121)	(241)
Loss on investment in SPP	864
Amortization of debt issuance costs	5,312	7,215
Accretion of debt discount (premium)	544	654
Deferred taxes	7,443	21,946
Changes in operating assets and liabilities:
Accounts receivable	52,138	(52,957)
Other current assets	3,792	(10,734)
Accounts payable	(12,945)	(29,594)
Accounts receivable - related entities	(3,404)	257
Other payables	(836)	1,818
Accrued liabilities	(1,181)	58,864
Other current liabilities	(5,166)
Other liabilities	1,190
Net cash provided by operating activities	228,638	272,680
CASH FLOWS FROM INVESTING ACTIVITIES:
Payments for oil and natural gas properties	(562,599)	(532,300)
Payments for other property and equipment	(4,572)	(9,581)
Proceeds from sale of oil and natural gas properties	81,734
Acquisition of oil and natural gas properties	(7,658)	(558,113)
Net cash used in investing activities	(493,095)	(1,099,994)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		100,000
Repayment of borrowings		(100,000)
Issuance of senior notes, net of premium and discount		1,152,250
Issuance of common stock		176,250
Payments for offering costs		(8,731)
Financing costs	(400)	(37,412)
Preferred dividends paid	(11,973)	(12,302)
Net cash provided by (used in) financing activities	(12,373)	1,270,055
Increase (decrease) in cash and cash equivalents	(276,830)	442,741
Cash and cash equivalents, beginning of period	473,714	153,531
Cash and cash equivalents, end of period	196,884	596,272
NON-CASH INVESTING AND FINANCING ACTIVITIES:
Asset retirement obligations	7,451	19,236
Change in accrued capital expenditures	(90,632)	34,789
Common stock issued in exchange for preferred stock		123,731
SUPPLEMENTAL DISCLOSURE:
Cash paid for interest	$ 98,104	$ 24,527

Organization

Organization	9 Months Ended
	Sep. 30, 2015
Organization
Organization	Note 1. Organization Sanchez Energy Corporation (together with our consolidated subsidiaries, the “Company,” “we,” “our,” “us” or similar terms) is an independent exploration and production company, formed in August 2011 as a Delaware corporation, focused on the exploration, acquisition and development of unconventional oil and natural gas resources in the onshore U.S. Gulf Coast, with a current focus on the Eagle Ford Shale in South Texas and the Tuscaloosa Marine Shale (“TMS”) in Mississippi and Louisiana. We have accumulated net leasehold acreage in the oil and condensate, or black oil and volatile oil, windows of the Eagle Ford Shale and in what we believe to be the core of the TMS. We are currently focused on the horizontal development of significant resource potential from the Eagle Ford Shale.

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2015
Basis of Presentation and Summary of Significant Accounting Policies
Basis of Presentation and Summary of Significant Accounting Policies	Note 2. Basis of Presentation and Summary of Significant Accounting Policies 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, 2014 from the audited financial statements filed in its Annual Report on Form 10-K for the fiscal year ended December 31, 2014 (the “2014 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 2014 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 September 30, 2015, 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 2014 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 July 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-11, “ Simplifying the Measurement of Inventory ,” effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. In April 2015, the FASB issued ASU 2015-03, “Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” This guidance is intended to more closely align the presentation of debt issuance costs under U.S. GAAP with the presentation requirements under the International Financial Reporting Standards. Under this new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented. This guidance is effective for fiscal years and interim periods beginning after December 15, 2015. The guidance is to be applied retrospectively to each prior period presented. Early adoption is permitted. The effects of this accounting standard on our financial position, results of operations and cash flows are not expected to be material. In February 2015, the FASB issued ASU 2015-02, “Consolidation—Amendments to the Consolidation Analysis.” This ASU will simplify existing requirements by reducing the number of acceptable consolidation models and placing more emphasis on risk of loss when determining a controlling financial interest. The provisions of this new standard will affect how limited partnerships and similar entities are assessed for consolidation, including the elimination of the presumption that a general partner should consolidate a limited partnership. This ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective or modified retrospective approach, with early adoption permitted. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is not permitted. The guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material.

Acquisitions and Divestitures

Acquisitions and Divestitures	9 Months Ended
	Sep. 30, 2015
Acquisitions and Divestitures
Acquisitions and Divestitures	Note 3. Acquisitions and Divestitures Our acquisitions are accounted for under the acquisition method of accounting in accordance with 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 issuance of the $850 million senior unsecured 6.125% notes due 2023 (the “Original 6.125% Notes”) 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 completed our disposition to a subsidiary of Sanchez Production Partners LP (“SPP”) of escalating amounts of partial working interests in 59 wellbores located in Gonzales County, Texas (the “Palmetto disposition”) for an adjusted purchase price of approximately $83.4 million. The effective date of the transaction was January 1, 2015. The aggregate average working interest percentage initially conveyed was 18.25% per wellbore and, upon January 1 of each subsequent year after the closing, the purchaser’s working interest will automatically increase in incremental amounts according to the purchase agreement until January 1, 2019, at which point the purchaser will own a 47.5% working interest and we will own a 2.5% working interest in each of the wellbores. We received consideration consisting of approximately $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. Pro Forma Operating Results The following unaudited pro forma combined results for the three and nine months ended September 30, 2015 and 2014 reflect the consolidated results of operations of the Company as if the Catarina acquisition and related financing had occurred on January 1, 2013 and the Palmetto disposition had occurred on January 1, 2014. The pro forma information includes adjustments primarily for revenues and expenses from the acquired and disposed properties, depreciation, depletion, amortization and accretion, impairment, interest expense and debt issuance cost amortization for acquisition debt, consideration received including cash and common stock, and stock dividends for the issuance of preferred stock. The unaudited pro forma combined financial statements give effect to the events set forth below: · The Catarina acquisition completed on June 30, 2014. · The Palmetto disposition completed on March 31, 2015. · Issuance of the Original 6.125% Notes (as discussed in Note 6, “Long-Term Debt”) to finance a portion of the Catarina acquisition and the related adjustments to interest expense. Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Revenues $ $ $ $ Net income (loss) attributable to common stockholders $ $ $ $ Net income (loss) per common share, basic and diluted $ $ $ $ The unaudited pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the Catarina acquisition and related financings and Palmetto disposition been completed as of the dates set forth in this unaudited pro forma combined financial information and should not be taken as indicative of the Company’s future combined results of operations. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma combined financial information and actual results.

Cash and Cash Equivalents

Cash and Cash Equivalents	9 Months Ended
	Sep. 30, 2015
Cash and Cash Equivalents
Cash and Cash Equivalents	Note 4. Cash and Cash Equivalents As of September 30, 2015 and December 31, 2014, cash and cash equivalents consisted of the following (in thousands): September 30, December 31, 2015 2014 Cash at banks $ $ Money market funds Total cash and cash equivalents $ $

Oil and Natural Gas Properties

Oil and Natural Gas Properties	9 Months Ended
	Sep. 30, 2015
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 and nine month periods ended September 30, 2015, the Company recorded a full cost ceiling test impairment after income taxes of $454.6 million and $1,365.0 million, respectively. Based on the sustained decline in average prices throughout the first three quarters of 2015 and a current expectation that prices will remain unfavorable during the remainder of 2015 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 2015. No impairment expense was recorded for the three and nine month periods ended September 30, 2014. 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	9 Months Ended
	Sep. 30, 2015
Long-Term Debt
Long-Term Debt	Note 6. Long ‑Term Debt Long-term debt on September 30, 2015, consisted of $1.15 billion face value of 6.125% senior notes (the “6.125% Notes,” consisting of $850 million in Original 6.125% Notes and $300 million in Additional 6.125% Notes (defined below), which were issued at a premium to face value of approximately $2.3 million) maturing on January 15, 2023, and $600 million principal amount of 7.75% senior notes (the “7.75% Notes,” consisting of $400 million in Original 7.75% Notes (defined below) and $200 million in Additional 7.75% Notes (defined below), which were issued at a discount to face value of approximately $7.0 million), maturing on June 15, 2021. As of September 30, 2015, and December 31, 2014, the Company’s long ‑term debt consisted of the following: Amount Outstanding (in thousands) as of September 30, December 31, Interest Rate Maturity date 2015 2014 Second Amended and Restated Credit Agreement Variable June 30, 2019 $ — $ — 7.75% Notes 7.75% June 15, 2021 6.125% Notes 6.125% January 15, 2023 Unamortized discount on Additional 7.75% Notes Unamortized premium on Additional 6.125% Notes Total long-term debt $ $ The components of interest expense are (in thousands): Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Interest on Senior Notes $ $ $ $ Interest expense and commitment fees on credit agreement Amortization of debt issuance costs Amortization of discount on Additional 7.75% Notes Amortization of premium on Additional 6.125% Notes Total interest expense $ $ $ $ Credit Facility Previous Credit Agreement: On May 31, 2013, we and our subsidiaries, SEP Holdings III, LLC (“SEP III”), SN Marquis LLC (“SN Marquis”) and SN Cotulla 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, each of SEP III, SN Marquis, SN Cotulla, SN Operating LLC (“SN Operating”), SN TMS, LLC (“SN TMS”), and SN Catarina, LLC (“SN Catarina” and together with SEP III, SN Marquis, SN Cotulla, SN Operating and SN TMS, collectively, the “Guarantors” and the Guarantors and the Company collectively, the “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 (the “Administrative Agent”), Capital One, National Association as the syndication agent, Compass Bank and SunTrust Bank as documentation agents, RBC Capital Markets as sole lead arranger and sole book runner and the lenders party thereto (the “Second Amended and Restated Credit Agreement”). The Company has elected an aggregate elected 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 to an aggregate amount of the lesser of $80 million and the total availability thereunder. As of September 30, 2015, there were no borrowings and no letters of credit outstanding under the Second Amended and Restated Credit Agreement. Availability under the Second Amended and Restated Credit Agreement is at all times subject to customary conditions and the then applicable borrowing base and aggregate elected commitment amount. The borrowing base under the Second Amended and Restated Credit Agreement was set at $362.5 million upon issuance of the Additional 6.125% Notes and was increased to $650 million in connection with the October 1, 2014 redetermination. However, the Company’s aggregate elected commitment amount remained $300 million and the Company retained the ability to increase the aggregate elected commitment up to the $650 million approved borrowing base upon written notice from the Company and compliance with certain conditions, including the consent of any lender whose elected commitment is increased. On March 31, 2015, pursuant to an amendment of the Second Amended and Restated Credit Agreement, the borrowing base under such agreement was changed to $550 million, with the aggregate elected commitment amount of $300 million remaining unchanged. The borrowing base was reduced as a result of several factors that included the decrease in reserve value from the decline in commodity prices along with the reduction in reserves in connection with the Palmetto disposition discussed above partially offset by underlying new reserve growth through drilling. All of the aggregate elected commitment was available for future revolver borrowings as of September 30, 2015. The Second Amended and Restated Credit Agreement matures on June 30, 2019. The borrowing base under the Second Amended and Restated Credit Agreement can be subsequently re-determined up or down by the lenders based on, among other things, their evaluation of the Company’s and its restricted subsidiaries’ oil and natural gas reserves. Redeterminations of the borrowing base are scheduled to occur semi-annually on or before April 1 and October 1 of each year. The borrowing base is also subject to (i) automatic reduction by 25% of the amount of any increase in the Company’s high yield debt, (ii) interim redetermination at the election of the Company once between each scheduled redetermination, (iii) interim redetermination at the election of the administrative agent at the direction of a majority of the credit exposures or, if none, the elected commitments of the lenders once between each scheduled re-determination and (iv) if the required lenders so direct in connection with asset sales and swap terminations involving more than 10% of the value of the proved developed oil and gas properties included in the most recent reserve report, reduction in an amount equal to the borrowing base value, as determined by the administrative agent in its reasonable judgment, of the assets so sold and swaps so terminated. The Company’s obligations under the Second Amended and Restated Credit Agreement are secured by a first priority lien on substantially all of the Company’s assets and the assets of its existing and future subsidiaries not designated as “unrestricted subsidiaries,” including a first priority lien on all ownership interests in existing and future subsidiaries not designated as “unrestricted subsidiaries.” The obligations under the Second Amended and Restated Credit Agreement are guaranteed by all of the Company’s existing and future subsidiaries not designated as ‘‘unrestricted subsidiaries.’’ At the Company’s election, borrowings under the Second Amended and Restated Credit Agreement may be made on an alternate base rate or an adjusted eurodollar rate basis, plus an applicable margin. The applicable margin varies from 0.50% to 1.50% for alternate base rate borrowings and from 1.50% to 2.50% for eurodollar borrowings, depending on the utilization of the borrowing base. Furthermore, the Company is also required to pay a commitment fee on the unused committed amount at a rate varying from 0.375% to 0.50% per annum, depending on the utilization of the elected commitment. The Second Amended and Restated Credit Agreement contains various affirmative and negative covenants and events of default that limit the Company’s ability to, among other things, incur indebtedness, make restricted payments, grant liens, consolidate or merge, dispose of certain assets, make certain investments, engage in transactions with affiliates, hedge transactions and make certain acquisitions. The Second Amended and Restated Credit Agreement also provides for cross default between the Second Amended and Restated Credit Agreement and the other debt (including debt under the 6.125% Notes and the 7.75% Notes) and obligations in respect of hedging agreements (on a mark-to-market basis), of the Company and its restricted subsidiaries, in an aggregate principal amount in excess of $10 million. Furthermore, the Second Amended and Restated Credit Agreement contains financial covenants that require the Company to satisfy the following tests: (i) current assets plus undrawn borrowing capacity on the Second Amended and Restated Credit Agreement to current liabilities of at least 1.0 to 1.0 at all times, and (ii) senior secured debt to consolidated last twelve months (“LTM”) EBITDA of not greater than 2.25 to 1.0 as of the last day of any fiscal quarter On July 20, 2015, the Company, the Guarantors, the Administrative Agent and the other agents and lenders party thereto entered into the Third Amendment to the Second Amended and Restated Credit Agreement (the “Third Amendment”) which amended the Second Amended and Restated Credit Agreement, among other things, to (a) permit one or more of the Loan Parties to (i) make direct and indirect investments of up to $10 million in an unrestricted subsidiary in connection with a joint venture to develop a midstream facility and (ii) enter into and perform certain commercial and financial support agreements with such joint venture and the other party to such joint venture on terms acceptable to the Administrative Agent, (b) permits the Loan Parties to (i) acquire an undivided interest in a midstream facility, (ii) make up to $80 million of direct and indirect investments in an unrestricted subsidiary in connection with a joint venture to develop, own and operate midstream assets to be entered into by such unrestricted subsidiary, (iii) enter into and perform midstream services agreements with the other party to such joint venture on terms acceptable to the Administrative Agent, (iv) enter into and perform financial support agreements with such joint venture and the other party to such joint venture on terms acceptable to the Administrative Agent, (v) if the Loan Party that acquires such undivided interest in a midstream facility so elects, exchange such undivided interest in whole or in part for equity interests in such joint venture in an amount equal to the lesser of (X) 2% of the equity interests in such joint venture and (Y) equity interests having a value no greater than $5 million, as determined by the Company in good faith at such time and (vi) retain and grant security interests over any such equity interests so acquired, (c) permits the Loan Parties to (i) dispose of certain midstream assets to an unrestricted subsidiary, (ii) dispose of such midstream assets or equity interests in such unrestricted subsidiary in exchange for consideration, up to 25% by value of which may include equity interests in the transferee and payment-in-kind notes issued by the transferee or, if equity interests in such transferee are not publicly traded, its parent entity that has issued publicly traded equity interests, (iii) retain such equity interests and payment-in-kind notes, (iv) retain joint and several liability in connection with such midstream assets to the extent required under the terms of the lease under which they were acquired and (v) enter into midstream services agreements with such transferee on terms acceptable to the Administrative Agent, (d) eliminate the covenant requiring that the Borrower maintain a ratio of consolidated EBITDA to consolidated net interest expense of not less than 2.25 to 1.0, (e) adjust the limits on the Loan Parties entering into swap agreements relative to expected production from proved developed producing reserves and total proved reserves and permit the Loan Parties, within stated limits, to enter into swap agreements in connection with the contemplated acquisition of proved developed producing reserves and total proved reserves and (f) provide for other technical amendments. On September 29, 2015, the Company, the Guarantors, the Administrative Agent and the other agents and lenders party thereto entered into the Fourth Amendment to the Second Amended and Restated Credit Agreement (the “Fourth Amendment”) which amended the Second Amended and Restated Credit Agreement, among other things, to (a) permit one or more lenders in addition to Royal Bank of Canada to act as issuing bank upon agreement with such lenders, (b) increase the letter of credit sublimit to $80 million, (c) permit the Loan Parties to enter into and perform certain commercial and financial support agreements in connection with one of the joint ventures to develop a midstream facility permitted by the Third Amendment, (d) substitute references to Catarina Midstream, LLC (“Catarina Midstream”) in place of references to the “DW Midstream Unrestricted Subsidiary” and update the organizational chart and subsidiary list in the schedules to the Second Amended and Restated Credit Agreement to reflect Catarina Midstream’s existence and status as an unrestricted subsidiary until such time as it is disposed of in accordance with the Second Amended and Restated Credit Agreement, (e) permit the disposition of units in SPP by a Loan Party to Catarina Midstream, (f) permit certain repurchases of equity interests in the Company by the Loan Parties and (g) provide for other technical amendments, clarifications and corrections. Subsequent to quarter end, on October 30, 2015, the Company, the Guarantors, the Administrative Agent and the other agents and lenders party thereto entered into the Fifth Amendment to the Second Amended and Restated Credit Agreement (the “Fifth Amendment”) to modify certain representations, covenants, exhibits and schedules and to waive any existing breaches of, and any resulting defaults or events of default with respect to certain covenants of the Second Amended and Restated Credit Agreement, all as further discussed in Note 18, “Subsequent Events.” From time to time, the agents, arrangers, book runners and lenders under the Second Amended and Restated Credit Agreement and their affiliates have provided, and may provide in the future, investment banking, commercial lending, hedging and financial advisory services to the Company and its affiliates in the ordinary course of business, for which they have received, or may in the future receive, customary fees and commissions for these transactions. As of September 30, 2015, the Company was in compliance with the covenants of the Second Amended and Restated Credit Agreement. 7.75% Senior Notes Due 2021 On June 13, 2013, we completed a private offering of $400 million in aggregate principal amount of the Company’s 7.75% senior notes that will mature on June 15, 2021 (the “Original 7.75% Notes”). Interest is payable on each June 15 and December 15. We received net proceeds from this offering of approximately $388 million, after deducting initial purchasers’ discounts and offering expenses, which we used to repay outstanding indebtedness under our credit facilities. The Original 7.75% Notes are 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 approximately $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 debt securities under the indenture. We used the net proceeds from the offering to partially fund the Wycross acquisition completed in October 2013, a portion of the 2013 and 2014 capital budgets and for general corporate purposes. The 7.75% Notes are senior unsecured obligations and rank equally in right of payment with all of our existing and future senior unsecured indebtedness. The 7.75% Notes rank senior in right of payment to our future subordinated indebtedness. The 7.75% Notes are effectively junior in right of payment to all of our existing and future secured debt (including under our Second Amended and Restated Credit Agreement) to the extent of the value of the assets securing such debt. The 7.75% Notes are fully and unconditionally guaranteed (except for customary release provisions) on a joint and several senior unsecured basis by the subsidiary guarantors party to the indenture governing the 7.75% Notes. To the extent set forth in the indenture governing the 7.75% Notes, certain of our subsidiaries will be required to fully and unconditionally guarantee the 7.75% Notes on a joint and several senior unsecured basis in the future. The indenture governing the 7.75% Notes, among other things, restricts our ability and our restricted subsidiaries’ ability to: (i) incur, assume, or guarantee additional indebtedness or issue certain types of equity securities; (ii) pay distributions on, purchase or redeem 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; (vii) restrict distributions or other payments from the Company’s restricted subsidiaries; and (ix) designate subsidiaries as unrestricted subsidiaries. We have the option to redeem all or a portion of the 7.75% Notes at any time on or after June 15, 2017 at the applicable redemption prices specified in the indenture plus accrued and unpaid interest. We may also redeem the 7.75% Notes, in whole or in part, at a redemption price equal to 100% of their principal amount plus a make whole premium, together with accrued and unpaid interest and additional interest, if any, to the redemption date, at any time prior to June 15, 2017. In addition, we may redeem up to 35% of the 7.75% Notes prior to June 15, 2016 under certain circumstances with an amount not greater than the net cash proceeds of one or more equity offerings at the redemption price specified in the indenture. We may also be required to repurchase the 7.75% Notes upon a change of control or if we sell certain of our assets. On July 18, 2014, we completed an exchange offer of $600 million aggregate principal amount of the 7.75% Notes that had been registered under the Securities Act of 1933, as amended (the “Securities Act”), for an equal amount of the 7.75% Notes that had not been registered under the Securities Act. 6.125% Senior Notes Due 2023 On June 27, 2014, the Company completed a private offering of the Original 6.125% Notes. Interest is payable on each July 15 and January 15. The Company received net proceeds from this offering of approximately $829 million, after deducting initial purchasers’ discounts and 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 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 our future subordinated indebtedness. The 6.125% Notes are effectively junior in right of payment to all of our 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. We have 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, we 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. We may also be required to repurchase the 6.125% Notes upon a change of control or if we sell certain of our 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	9 Months Ended
	Sep. 30, 2015
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, or to protect the economics of property acquisitions, the Company periodically enters into derivative contracts with respect to a portion of its projected oil and natural gas production through various transactions that fix or, through options, modify the future prices to be realized. These transactions may include price swaps whereby the Company will receive a fixed price for its production and pay a variable market price to the contract counterparty. 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. In addition, the Company enters into option transactions, such as puts or put spreads, as a way to manage its exposure to fluctuating prices. The Company further uses enhanced swaps for a portion of its commodity price hedging activities. An enhanced swap is a product created by simultaneously selling an out of the money put and using the premium value from the sale to modify or “enhance” the value of a swap executed at the same time. The transaction provides an absolute minimum price at the enhanced swap strike price until the put strike price level is reached at which point the Company receives the market price plus the difference between the enhanced swap price and the put strike price. The Company also enters into puts to hedge production at a floor price, but allows the Company to realize revenue upside if oil prices on the hedged volumes increase above the floor price. In order to enter into these put derivative transactions, the Company pays a fixed deferred premium when each trade is settled. 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 September 30, 2015, 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 October - December 2015 $ $ - $ 2016 $ $ - $ Calendar Year Volumes (Bbls) Put Price per Bbl Put Price Range per Bbl 2016 $ $ - $ As of September 30, 2015, the Company had the following NYMEX Henry Hub natural gas swaps, three-way collars, and enhanced swaps, respectively, covering anticipated future production: Calendar Year Swap Volumes (Mmbtu) Average Price per Mmbtu Price Range per Mmbtu October - December 2015 $ $ 3.54 - $ 2016 $ $ 3.80 - $ 2017 $ $ Three-way Average Short Put Price Average Long Put Price Average Short Call Calendar Year Collar Volumes (Mmbtu) per Mmbtu per Mmbtu Price per Mmbtu October - December 2015 $ $ $ Enhanced Swap Average Swap Price Average Put Price Calendar Year Volumes (Mmbtu) per Mmbtu per Mmbtu October - December 2015 $ $ The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the nine months ended September 30, 2015 and the year ended December 31, 2014 (in thousands): Nine Months Ended Year Ended September 30, December 31, 2015 2014 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): September 30, 2015 Gross Amounts Net Amounts Gross Amount Offset in the Presented in the of Recognized Consolidated Consolidated Assets Balance Sheets Balance Sheets Offsetting Derivative Assets: Current asset $ $ $ Long-term asset — Total asset $ $ $ Offsetting Derivative Liabilities: Current liability $ $ $ — Long-term liability — — — Total liability $ $ $ — December 31, 2014 Gross Amounts Net Amounts Gross Amount Offset in the Presented in the of Recognized Consolidated Consolidated Assets Balance Sheets Balance Sheets Offsetting Derivative Assets: Current asset $ $ $ Long-term asset — Total asset $ $ $ Offsetting Derivative Liabilities: Current liability $ $ $ — Long-term liability — Total liability $ $ $

Investments

Investments	9 Months Ended
	Sep. 30, 2015
Investments.
Investments	Note 8. Investments On March 31, 2015, a subsidiary of the Company received approximately $2 million in common units of SPP as part of the consideration paid for the Palmetto disposition described in Note 3, “Acquisitions and Divestitures.” Rather than accounting for the investment under the equity method, the Company elected the fair value option to account for its interest in SPP. The Company records the equity investment in SPP at fair value at the end of each reporting period. Any gains or losses are recorded as a component of other income (expense) in the consolidated statement of operations. The Company recorded losses related to the investment in SPP for the three and nine months ended September 30, 2015 of $0. 9 million and $0.8 million, respectively. Subsequent to the qu arter end, t he Company contributed all of the 1,052,632 common units of SPP (105,263 common units after a 1 -for-10 reverse split completed by SPP on August 3, 2015) received in connection with the Palmetto disposition as described above. Please see additional discussion on this transaction in Note 18, “Subsequent Events.”

Fair Value of Financial Instrum

Fair Value of Financial Instruments	9 Months Ended
	Sep. 30, 2015
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. 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 September 30, 2015 and December 31, 2014 (in thousands): As of September 30, 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 $ $ — $ — $ Equity investment: Investment in SPP — — Oil derivative instruments: Swaps — — Puts — — Gas derivative instruments: Swaps — — Enhanced Swaps — — Three-way collars — — Total $ $ $ — $ As of December 31, 2014 Active Market for Identical Observable Unobservable Total Assets Inputs Inputs Carrying (Level 1) (Level 2) (Level 3) Value Cash and cash equivalents: Money market funds $ $ — $ — $ Oil derivative instruments: Swaps — — Enhanced Swaps — — Three-way collars — — Gas derivative instruments: Swaps — — Enhanced Swaps — — Three-way collars — — Total $ $ $ $ Financial Instruments : The Level 1 instruments presented in the tables above consist of money market funds included in cash and cash equivalents and equity investment on the Company’s condensed consolidated balance sheets at September 30, 2015, and December 31, 2014. The Company’s money market funds represent cash equivalents backed by the assets of high-quality banks and financial institutions. The Company identified the money market funds as Level 1 instruments due to the fact that the money market funds have daily liquidity, quoted prices for the underlying investments can be obtained and there are active markets for the underlying investments. A subsidiary of the Company received common units in SPP as part of the consideration received for the Palmetto disposition discussed in Note 3, “Acquisitions and Divestitures.” The Company is accounting for these units as an equity method investment utilizing the fair value accounting method. The Company identified the common units as Level 1 instruments due to the fact that SPP is a publicly traded company on the NYSE MKT with daily quoted prices that can be easily obtained. The Company’s derivative instruments, which consist of swaps, enhanced swaps, collars and puts, are classified as Level 2 as of September 30, 2015, and either Level 2 or Level 3 as of December 31, 2014, in the table above. The fair values of the Company’s derivatives are based on third-party pricing models which utilize inputs that are either readily available in the public market, such as forward curves, or can be corroborated from active markets of broker quotes. Since swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. As of December 31, 2014, the Company’s enhanced swaps, puts, collars and three-way collars included some level of unobservable inputs, such as volatility curves, and were therefore classified as Level 3. As of September 30, 2015, the Company believes that substantially all of the inputs required to calculate the fair value of enhanced swaps, puts, collars, and three-way collars are observable in the marketplace throughout the term of these derivative instruments or supported by observable levels at which transactions are executed in the marketplace, and are therefore classified as Level 2. 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 September 30, 2015. The fair values of the Company’s derivative instruments classified as Level 3 as of December 31, 2014 were $75.5 million. The significant unobservable inputs for Level 3 contracts as of December 31, 2014 include unpublished forward prices of commodities, market volatility and credit risk of counterparties. The following table sets forth a reconciliation of changes in the fair value of the Company’s derivative instruments classified as Level 3 in the fair value hierarchy (in thousands): Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Beginning balance $ — $ $ $ Total gains included in earnings — Net settlements on derivative contracts(1) — Derivative contracts transferred to Level 2 — — — Ending balance $ — $ $ — $ Gains (losses) included in earnings related to derivatives still held as of September 30, 2015 and 2014 $ — $ $ $ (1) Includes ($12,919) of net settlements in Level 2 that were transferred from Level 3 during the nine months ended September 30, 2015. In February 2015, the Company modified certain of its crude oil enhanced swap and three-way collar transactions to create crude oil swaps on a costless transactional basis. As of December 31, 2014, these crude oil enhanced swaps and three way collar transactions had fair values classified as Level 3. When the transactions were modified to swaps during the first quarter of 2015, the fair values of the transactions were classified as Level 2. As of September 30, 2015, the Company believes that substantially all of the inputs required to calculate the fair value of enhanced swaps, puts, collars, and three-way collars are Level 2 and were moved out of Level 3 fair value classification. Fair Value on a Non ‑Recurring Basis The Company follows the provisions of ASC 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. Fair value measurements of assets acquired and liabilities assumed in business combinations are based on inputs that are not observable in the market and thus represent Level 3 inputs. The fair value of acquired properties is based on market and cost approaches. Our purchase price allocation for the 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. 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 and 6.125% Notes are traded in an active market, and as such, are classified as Level 1 financial instruments. The estimated fair values of the 7.75% Notes and 6.125% Notes were $447.0 million and $747.5 million, respectively, as of September 30, 2015, and were calculated using quoted market prices based on trades of such debt as of that date.

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2015
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. The changes in the asset retirement obligation for the nine months ended September 30, 2015 and the year ended December 31, 2014 were as follows (in thousands): Nine Months Ended Year Ended September 30, 2015 December 31, 2014 Abandonment liability, beginning of period $ $ Liabilities incurred during period Acquisitions — Divestitures — Revisions Accretion expense Abandonment liability, end of period $ $ During the third quarter of 2015, the Company reviewed its asset retirement obligation cost estimates, and made revisions to increase cost estimates of future asset retirement obligations from $120,000 per well to $150,000 per well to more accurately reflect current market costs. The Company reduced the future asset retirement obligations by approximately $379,000 due to the sale of working interests in properties associated with the Palmetto disposition on March 31, 2015.

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2015
Related Party Transactions
Related Party Transactions	Note 11. Related Party Transactions Sanchez Oil & Gas Corporation (“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 benefit costs of SOG employees are allocated to the Company based on the actual time spent by the professional staff on the properties and business activities of the Company. General and administrative costs, such as office rent, utilities, supplies, and other overhead costs, are allocated to the Company based on a fixed percentage that is reviewed quarterly and adjusted, if needed, based on the activity levels of services provided to the Company. General and administrative costs that are specifically incurred by or for the specific benefit of the Company are charged directly to the Company. Expenses allocated to the Company for general and administrative expenses for the three and nine months ended September 30, 2015 and 2014 are as follows (in thousands): Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Administrative fees $ $ $ $ Third-party expenses Total included in general and administrative expenses $ $ $ $ As of September 30, 2015 and December 31, 2014, the Company had a net receivable from SOG and other members of the Sanchez Group of $3.8 million and $0.4 million, respectively, which are reflected as “Accounts receivable—related entities” in the condensed consolidated balance sheets. The net receivable as of September 30, 2015 and December 31, 2014 consists primarily of advances paid related to leasehold and other costs paid to SOG. Palmetto Disposition On March 31, 2015, we completed the Palmetto disposition discussed above to a subsidiary of SPP, which is a related party. SPP is a related party of the Company in accordance with GAAP as the common units of SPP received in connection with the Palmetto disposition constitutes an equity method investment, which the Company has elected to account for using the fair value option (see further discussion in Note 8, “Investments”). 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. Eduardo Sanchez, our President who is also the brother of our Chief Executive Officer and the son of our Executive Chairman of the Company’s Board of Directors (the “Board”), owns 24.05% of Sanchez Resources and is its President and Chief Executive Officer. Sanchez Resources is also indirectly owned, in part, by our Chief Executive Officer and our Executive Chairman of the Board, who each also serve on our Board. Additionally, Patricio Sanchez and Ana Lee Sanchez Jacobs, each an immediate family member of our President, Chief Executive Officer and Executive Chairman of the Board, either directly or indirectly, own equity interests in Sanchez Resources. 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. We plan to defer drilling on the gross Additional Wells originally planned for 2015. We do not anticipate that the plan for deferral will materially impact our ability to maintain our core acreage in the play under our leases. Western Catarina Midstream Divestiture On October 14, 2015, the Company and 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 owned (i) certain midstream gathering lines and associated assets and interests located in Dimmit County and Webb County, Texas and (ii) 105,263 common units of SPP, to SPP for approximately $345.8 million in cash, subject to post-closing adjustments (the “Western Cat arina Midstream Divestiture”). In connection with the closing of the Western Catarina Midstream Divestiture, SN Catarina and Catarina Midstream entered into a Firm Gathering and Processing Agreement (the “Gathering Agreement”) on October 14, 2015 for an initial term of 15 years under which production from approximately 35,000 acres in Dimmit County and Webb County, Texas will be dedicated for gathering by Catarina Midstream. In addition, for the first five years of the Gathering Agreement, SN Catarina will be required to meet a minimum quarterly volume delivery commitment of 10,200 barrels per day of crude oil and condensate and 142,000 Mcf per day of natural gas, subject to certain adjustments. SN Catarina will be required to pay gathering and processing fees of $0.96 per barrel for crude oil and condensate and $0.74 per Mcf for natural gas that are tendered through the gathering system, in each case, subject to an annual escalation for a positive increase in the consumer price index. In addition, SN Catarina has, under certain circumstances, a right of first refusal during the term of the agreement and afterwards with respect to dispositions by Catarina Midstream of its ownership interest in the gathering system. The Company has accounted for the Western Catarina Midstream Divestiture as a sale of assets and subsequent leaseback of the assets over the 15 year Gathering Agreement term. The Company has recorded a deferred gain upon closing of the transaction that will be amortized straight-line over five years resulting in a reduction to lease operating expense.

Accrued Liabilities

Accrued Liabilities	9 Months Ended
	Sep. 30, 2015
Accrued Liabilities
Accrued Liabilities	Note 12. Accrued Liabilities The following information summarizes accrued liabilities as of September 30, 2015 and December 31, 2014 (in thousands): September 30, December 31, 2015 2014 Capital expenditures $ $ Other: General and administrative costs Production taxes Ad valorem taxes Lease operating expenses Interest payable Leasehold improvements — Total accrued liabilities $ $

Stockholders' Equity

Stockholders' Equity	9 Months Ended
	Sep. 30, 2015
Stockholders' Equity
Stockholders' Equity	Note 13. Stockholders’ Equity Common Stock Offerings —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. 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 September 30, 2015, all dividends accumulated through that date had been paid. Except as required by law or the Company’s Amended and Restated Certificate of Incorporation (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 September 30, 2015, 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 shareholders in our condensed consolidated financial statements. NOL Rights Plan —On July 28, 2015, the Company entered into a net operating loss carryforwards (“NOLs”) rights plan (the “Rights Plan”) with Continental Stock Transfer & Trust Company, as rights agent. In connection therewith, the Board declared a dividend of one preferred share purchase right (“Right”) for each outstanding share of the Company’s common stock. The dividend was paid on August 10, 2015 to stockholders of record as of the close of business on August 7, 2015 (the “NOL Record Date”). In addition, one Right automatically attached to each share of common stock issued between the NOL Record Date and such date as when the Rights become exercisable. The Board adopted the Rights Plan in an effort to prevent the imposition of significant limitations under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), on its ability to utilize its current NOLs to reduce its future tax liabilities. If the Company experiences an “ownership change,” as defined in Section 382 of the Code, the Company’s ability to fully utilize the NOLs on an annual basis will be substantially limited, and the timing of the usage of the NOLs could be substantially delayed, which could therefore significantly impair the value of those benefits. In general terms, the Rights Plan works by imposing a significant penalty upon any person or group that acquires 4.9% or more of the outstanding common stock without the approval of the Board (an “Acquiring Person”). The Rights Plan also gives discretion to the Board to determine that someone is an Acquiring Person even if they do not own 4.9% or more of the outstanding common stock but do own 4.9% or more in value of the Company’s outstanding stock, as determined pursuant to Section 382 of the Code and the regulations promulgated thereunder. Stockholders who currently own 4.9% or more of the common stock will not trigger the Rights unless they acquire additional common stock shares, subject to certain exceptions set forth in the Rights Plan. In addition, the Board has established procedures to consider requests to exempt certain acquisitions of the Company’s securities from the Rights Plan if the Board determines that doing so would not limit or impair the availability of the NOLs or is otherwise in the best interests of the Company. Earnings (Loss) Per Share— The following table shows the computation of basic and diluted net loss per share for the three and nine months ended September 30, 2015 and 2014 (in thousands, except per share amounts): Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Net income (loss) $ $ $ $ Less: Preferred stock dividends Net loss allocable to participating securities (1) — — 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 (2)(3)(4) — — — Denominator for diluted earnings (loss) per common share Net income (loss) per common share - basic $ $ $ $ Net income (loss) per common share - diluted $ $ $ $ (1) For the three and nine months ended September 30, 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. (2) The three and nine months ended September 30, 2015 excludes 597,910 and 2,663,010 shares of weighted average restricted stock and 12,530,695 s hares 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 commo n share as these shares were anti-dilutive. (3) The nine months ended September 30, 2014 excludes 1,290,637 shares of weighted average restricted stock and 13,863,738 shares of common stock resulting from an assumed conversion of the Series A Preferred Stock and Series B Pr eferred Stock from the calculation of the denominator for diluted earnings per common share as these shares were anti-dilutive. (4) The three months ended September 30, 2014 includes 12,607,521 shares of common stock resulting fr om 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 dilutive. In addition, the related preferred stock dividends of $4,274,445 were not deducted from net income in computing the numerator used in the calculation of diluted earnings per common share.

Stock-Based Compensation

Stock-Based Compensation	9 Months Ended
	Sep. 30, 2015
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 Board or 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 shareholder approval as may be required by the exchange upon which the common shares are listed at that time, if any. No change may be made in any outstanding grant that would materially reduce the benefits of the participant without the consent of the participant. The LTIP will expire upon its termination by the Board or, if earlier, when no shares remain available under the LTIP for awards. Upon termination of the LTIP, awards then outstanding will continue pursuant to the terms of their grants. 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 and nine months ended September 30, 2015, the Company issued 0 and 95,200 shares, respectively, of restricted common stock pursuant to the LTIP to directors of the Company. During the three and nine months ended September 30, 2015, the Company also issued approximately 229,600 and 3.3 million shares, respectively, 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. These shares of restricted common stock vest in equal annual amounts over a three -year period. The Company recognized the following stock-based compensation expense (in thousands) which is included in general and administrative expense in the condensed consolidated statements of operations: Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Restricted stock awards, directors $ $ $ $ Restricted stock awards, non-employees Total stock-based compensation expense $ $ $ $ Based on the $6.15 per share closing price of the Company’s common stock on September 30, 2015, there was approximately $20.7 million of unrecognized compensation cost related to these non ‑vested restricted shares outstanding. The cost is expected to be recognized over an average period of approximately 2.1 years. A summary of the status of the non-vested shares for the nine months ended September 30, 2015 and 2014 is presented below (in thousands): Nine Months Ended September 30, September 30, 2015 2014 Non-vested common stock, beginning of period Granted Vested Forfeited Non-vested common stock, end of period As of September 30, 2015, approximately 5.3 million shares remain available for future issuance to participants.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2015
Income Taxes
Income Taxes	Note 15. Income Taxes The Company's effective tax rate for the nine months ended September 30, 2015 and 2014 was (0.5 )% and 35.3% , 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 (0.5)% for the nine months ended September 30, 2015 is primarily 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 35.3% for the nine months ended September 30, 2014 is related to non-deductible general and administrative expenses recorded during the period. The Company’s effective tax rate for the three months ended September 30, 2015 and 2014 was 0% and 35.2% , 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 September 30, 2015 is primarily 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 35.2% for the three months ended September 30, 2014 is primarily related to non-deductible general and administrative expenses recorded during the period. As of September 30, 2015, the Company had estimated NOLs of $656. 5 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 $519.2 million to reduce the net deferred tax asset to $0 at September 30, 2015. The Company will continue to assess the valuation allowance against deferred tax assets considering all available information obtained in future reporting periods. At September 30, 2015, the Company had no material uncertain tax positions.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2015
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. 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 are conferring on how to proceed with the case. 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 September 30, 2015, the Company had $65.9 million in lease payment obligations that satisfy operating lease criteria. These obligations include: (i) $52.1 million for a new corporate office lease that commenced in the fourth quarter of 2014 and has an expiration date in March 2025, (ii) $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 (iii) $6.8 million for a 10 year acreage lease agreement for a promotional ranch managed by the Company in Kenedy County, Texas. This acreage lease agreement includes a contractual requirement for the Company to spend a minimum of $4 million to make permanent improvements over the ten year life of the lease. The lease agreement does not specify the timing for such improvements to be made within the lease term. The Company’s ground lease with the Calhoun Port Authority is terminable upon 180 days written notice by the Company to the lessor in addition to a $1 million termination payment. The Company has the right to terminate its lease obligation for its acreage in Kenedy County, Texas at any time without penalty with nine months advanced written notice and payment of any accrued leasehold expenses.

Subsidiary Guarantors

Subsidiary Guarantors	9 Months Ended
	Sep. 30, 2015
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 and June 11, 2014 and registered, among other securities, debt securities. The subsidiaries of the Company named therein are co-registrants with the Company, and the registration statement registered guarantees of debt securities by such subsidiaries. As of September 30, 2015, such subsidiaries are 100 percent owned by the Company and any guarantees by these subsidiaries will be full and unconditional (except for customary release provisions). In the event that more than one of these subsidiaries provide guarantees of any debt securities issued by the Company, such guarantees will constitute joint and several obligations. The Company 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 September 30, 2015, such guarantor subsidiaries are 100 percent owned by the Company and the guarantees by these subsidiaries are full and unconditional (except for customary release provisions) and are joint and several and any non-guarantor subsidiaries of the Company are ‘‘minor’’ within the meaning of Rule 3-10 of Regulation S-X. The Company also filed a registration statement on Form S-4 with the SEC, which became effective on January 23, 2015, pursuant to which the Company completed an offering of the 6.125% Notes, which are guaranteed by its subsidiaries named therein. As of September 30, 2015, such guarantor subsidiaries are 100 percent owned by the Company and the guarantees by these subsidiaries are full and unconditional (except for customary release provisions) and are joint and several and any non-guarantor subsidiaries of the Company are ‘‘minor’’ within the meaning of Rule 3-10 of Regulation S-X. The Company has no assets or operations independent of its subsidiaries and there are no significant restrictions upon the ability of its subsidiaries to distribute funds to the Company.

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2015
Subsequent Events.
Subsequent Events	Note 18. Subsequent Events Western Catarina Midstream Divestiture On October 14, 2015, the Company and SN Catarina completed the Western Catarina Midstream Divestiture. In connection with the closing of the Western Catarina Midstream Divestiture, SN Catarina and Catarina Midstream entered into the Gathering Agreement on October 14, 2015 for an initial term of 15 years under which production from approximately 35,000 acres in Dimmit County and Webb County, Texas will be dedicated for gathering by Catarina Midstream. In addition, for the first five years of the Gathering Agreement, SN Catarina will be required to meet a minimum quarterly volume delivery commit ment of 10,200 barrels per day of crude oil and condensate and 142,000 Mcf per day of natural gas, subject to certain adjustments. SN Catarina will be required to pay gathering and processing fees of $0.96 per barrel for crude oil and condensate and $0.74 per Mcf for natural gas that are tendered through the gathering system, in each case, subject to an annual escalation for a positive increase in the consumer price index. In addition, SN Catarina has, under certain circumstances, a right of first refusal during the term of the agreement and afterwards with respect to dispositions by Catarina Midstream of its ownership interest in the gathering system. The Company has accounted for the Western Catarina Midstream Divestiture as a sale of assets and subsequent leaseback of the assets over the 15 year Gathering Agreement term. The Company has recorded a deferred gain upon closing of the transaction that will be amortized straight-line over five years resulting in a reduction to lease operating expense. Midstream Joint Venture On October 2, 2015, the Company entered into joint venture agreements with an affiliate of Targa Resources Partners LP ("Targa") to, among other things, construct a new cryogenic natural gas processing plant and an 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 joint venture agreements, the Company intends to invest approximately $115 million and receive a 50% ownership interest in the joint venture owning the plant as well as in a gathering joint venture that will own approximately 45 miles of high pressure gathering pipelines that will connect the Company's existing Catarina gathering system to the plant. Targa will hold all of the transportation capacity on the pipeline, and the gathering joint venture will receive fees for transportation. The Company has firm capacity for 125,000 Mcf per day of plant processing and associated pipeline capacity for the first five years and has dedicated the Catarina acreage and all production developed during the 15 year term. If certain conditions are met, the Company has the option to deliver additional volumes and commit additional acreage to the new plant as production increases. The natural gas processing plant and gathering pipelines will be designed, built and operated by Targa. The plant is expected to be operational by early 2017. Fifth Amendment to the Second Amended and Restated Credit Agreement On October 30, 2015, the Company, the Guarantors, the Administrative Agent and the other agents and lenders party thereto entered into the Fifth Amendment to the Second Amended and Restated Credit Agreement, dated as of June 30, 2014, by and among the Company, the Guarantors, the Administrative Agent and the other agents and lenders party thereto. The Fifth Amendment, among other things, (1) amended the Second Amended and Restated Credit Agreement and its exhibits and schedules to (a) update certain disclosures to be effective as of the date of the Fifth Amendment, including (i) the organizational chart and subsidiary list in the schedules to the Second Amended and Restated Credit Agreement to reflect the disposition of Catarina Midstream, LLC and (ii) the lists of marketing contracts and swap agreements in the schedules to the Second Amended and Restated Credit Agreement; (b) modify certain representations and the form of compliance certificate under the Second Amended and Restated Credit Agreement to reference updated disclosures provided to the Administrative Agent pursuant to the terms of the Second Amended and Restated Credit Agreement; (c) modify certain covenants to expressly (i) not require the Company to deliver fourth quarter financial statements prior to the delivery of annual financial statements, (ii) not require that certain insurance policies of the Loan Parties contain certain endorsements or loss payable provisions and (iii) permit the Loan Parties to enter into certain leases; (d) permit the Loan Parties to deliver certain financial statements and related documents required under the Second Amended and Restated Credit Agreement electronically and provide that, except in the case of compliance certificates or for other deliveries to the Administrative Agent or a lender that requests physical delivery, any such statements and documents that are filed with the SEC are deemed delivered when posted on the Company’s website or other internet or intranet website to which each lender and the Administrative Agent have access; (e)(i) specifically identify TPL South Texas Processing Company LP as the counterparty to the previously permitted Eagle Ford Midstream JV Transaction (as defined in the Fifth Amendment), (ii) separately identify and permit the “Gathering JV” component of such transaction and increase from $80 million to $115 million the permitted investment basket for investments in the Eagle Ford Midstream JV Transaction generally, thereby making the entire existing $50 million “other” permitted investment basket available for investments either in such transaction or other investments in unrestricted subsidiaries of the Company and (iii) provide that none of the transactions comprising the Eagle Ford Midstream JV Transaction shall be considered synthetic leases; (f) modify the change-in-business covenant to permit unrestricted subsidiaries to make direct or indirect investments in the oil and gas industry and related businesses and activities without restrictions on geography; (g) change the definition of “Material Adverse Effect” to (i) reference, among other things, (x) the ability of the Loan Parties to perform their obligations under the Loan Documents (as defined in the Second Amended and Restated Credit Agreement), rather than the ability of any Loan Party to perform any of its obligations under any Loan Document, (y) the validity or enforceability of the Loan Documents, rather than the validity or enforceability of any Loan Document, (z) the rights and remedies of or benefits available to the Administrative Agent, any issuing bank or any lender under the Loan Documents, rather than under any Loan Document and (ii) provide that general market or industry conditions, which do not affect the Company in a disproportionately adverse manner, shall not constitute or be taken into account in determining whether there has been a “Material Adverse Effect”; and (h) provide for other technical amendments, clarifications and corrections; and (2) waived any existing breaches of, and any resulting defaults or events of defaults under the Second Amended and Restated Credit Agreement with respect to, the Company’s covenants in the Second Amended and Restated Credit Agreement (a) to deliver fourth quarter financial statements within 45 days after the end of such fiscal quarter; (b) to provide certain loss payable clauses or provisions and endorsements with respect to certain insurance maintained by the Loan Parties; and (c) in respect of leases other than capital leases and leases of hydrocarbon interests.

Basis of Presentation and Sum26

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2015
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 July 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-11, “ Simplifying the Measurement of Inventory ,” effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. In April 2015, the FASB issued ASU 2015-03, “Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” This guidance is intended to more closely align the presentation of debt issuance costs under U.S. GAAP with the presentation requirements under the International Financial Reporting Standards. Under this new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheet as a direct deduction from the debt liability, similar to the presentation of debt discounts, rather than as a separate asset as previously presented. This guidance is effective for fiscal years and interim periods beginning after December 15, 2015. The guidance is to be applied retrospectively to each prior period presented. Early adoption is permitted. The effects of this accounting standard on our financial position, results of operations and cash flows are not expected to be material. In February 2015, the FASB issued ASU 2015-02, “Consolidation—Amendments to the Consolidation Analysis.” This ASU will simplify existing requirements by reducing the number of acceptable consolidation models and placing more emphasis on risk of loss when determining a controlling financial interest. The provisions of this new standard will affect how limited partnerships and similar entities are assessed for consolidation, including the elimination of the presumption that a general partner should consolidate a limited partnership. This ASU is effective for annual and interim periods beginning in 2016 and is required to be adopted using a retrospective or modified retrospective approach, with early adoption permitted. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. Early adoption is not permitted. The guidance may be applied retrospectively to each prior period presented or retrospectively with the cumulative effect recognized as of the date of initial application. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	9 Months Ended
	Sep. 30, 2015
Acquisitions
Schedule of unaudited pro forma combined statements of operations	Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Revenues $ $ $ $ Net income (loss) attributable to common stockholders $ $ $ $ Net income (loss) per common share, basic and diluted $ $ $ $
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)	9 Months Ended
	Sep. 30, 2015
Cash and Cash Equivalents
Schedule of cash and cash equivalents	As of September 30, 2015 and December 31, 2014, cash and cash equivalents consisted of the following (in thousands): September 30, December 31, 2015 2014 Cash at banks $ $ Money market funds Total cash and cash equivalents $ $

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2015
Long-Term Debt
Schedule of long-term debt	Amount Outstanding (in thousands) as of September 30, December 31, Interest Rate Maturity date 2015 2014 Second Amended and Restated Credit Agreement Variable June 30, 2019 $ — $ — 7.75% Notes 7.75% June 15, 2021 6.125% Notes 6.125% January 15, 2023 Unamortized discount on Additional 7.75% Notes Unamortized premium on Additional 6.125% Notes Total long-term debt $ $
Schedule of interest expense	The components of interest expense are (in thousands): Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Interest on Senior Notes $ $ $ $ Interest expense and commitment fees on credit agreement Amortization of debt issuance costs Amortization of discount on Additional 7.75% Notes Amortization of premium on Additional 6.125% Notes Total interest expense $ $ $ $

Derivative Instruments (Tables)

Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2015
Derivative contract covering anticipated future production
Schedule of reconciliation of the changes in fair value of the Company's commodity derivatives	The following table sets forth a reconciliation of the changes in fair value of the Company’s commodity derivatives for the nine months ended September 30, 2015 and the year ended December 31, 2014 (in thousands): Nine Months Ended Year Ended September 30, December 31, 2015 2014 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): September 30, 2015 Gross Amounts Net Amounts Gross Amount Offset in the Presented in the of Recognized Consolidated Consolidated Assets Balance Sheets Balance Sheets Offsetting Derivative Assets: Current asset $ $ $ Long-term asset — Total asset $ $ $ Offsetting Derivative Liabilities: Current liability $ $ $ — Long-term liability — — — Total liability $ $ $ — December 31, 2014 Gross Amounts Net Amounts Gross Amount Offset in the Presented in the of Recognized Consolidated Consolidated Assets Balance Sheets Balance Sheets Offsetting Derivative Assets: Current asset $ $ $ Long-term asset — Total asset $ $ $ Offsetting Derivative Liabilities: Current liability $ $ $ — Long-term liability — Total liability $ $ $
Crude oil
Derivative contract covering anticipated future production
Schedule of derivatives covering future production	Calendar Year Volumes (Bbls) Average Price per Bbl Price Range per Bbl October - December 2015 $ $ - $ 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 derivatives covering future production	Calendar Year Swap Volumes (Mmbtu) Average Price per Mmbtu Price Range per Mmbtu October - December 2015 $ $ 3.54 - $ 2016 $ $ 3.80 - $ 2017 $ $ Three-way Average Short Put Price Average Long Put Price Average Short Call Calendar Year Collar Volumes (Mmbtu) per Mmbtu per Mmbtu Price per Mmbtu October - December 2015 $ $ $ Enhanced Swap Average Swap Price Average Put Price Calendar Year Volumes (Mmbtu) per Mmbtu per Mmbtu October - December 2015 $ $

Fair Value of Financial Instr31

Fair Value of Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2015
Fair Value of Financial Instruments
Schedule of financial assets and liabilities measured at fair value on a recurring basis	The following tables set forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 (in thousands): As of September 30, 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 $ $ — $ — $ Equity investment: Investment in SPP — — Oil derivative instruments: Swaps — — Puts — — Gas derivative instruments: Swaps — — Enhanced Swaps — — Three-way collars — — Total $ $ $ — $ As of December 31, 2014 Active Market for Identical Observable Unobservable Total Assets Inputs Inputs Carrying (Level 1) (Level 2) (Level 3) Value Cash and cash equivalents: Money market funds $ $ — $ — $ Oil derivative instruments: Swaps — — Enhanced Swaps — — Three-way collars — — Gas derivative instruments: Swaps — — Enhanced Swaps — — Three-way collars — — Total $ $ $ $
Reconciliation of changes in the fair value of the oil derivative instruments classified as Level 3 in the fair value hierarchy	The following table sets forth a reconciliation of changes in the fair value of the Company’s derivative instruments classified as Level 3 in the fair value hierarchy (in thousands): Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Beginning balance $ — $ $ $ Total gains included in earnings — Net settlements on derivative contracts(1) — Derivative contracts transferred to Level 2 — — — Ending balance $ — $ $ — $ Gains (losses) included in earnings related to derivatives still held as of September 30, 2015 and 2014 $ — $ $ $ Includes ($12,919) of net settlements in Level 2 that were transferred from Level 3 during the nine months ended September 30, 2015.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2015
Asset Retirement Obligations
Schedule of changes in asset retirement obligation	The changes in the asset retirement obligation for the nine months ended September 30, 2015 and the year ended December 31, 2014 were as follows (in thousands): Nine Months Ended Year Ended September 30, 2015 December 31, 2014 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)	9 Months Ended
	Sep. 30, 2015
Related Party Transactions
Schedule of expenses allocated to the Company for general and administrative expenses	Expenses allocated to the Company for general and administrative expenses for the three and nine months ended September 30, 2015 and 2014 are as follows (in thousands): Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Administrative fees $ $ $ $ Third-party expenses Total included in general and administrative expenses $ $ $ $

Accrued Liabilities (Tables)

Accrued Liabilities (Tables)	9 Months Ended
	Sep. 30, 2015
Accrued Liabilities
Summary of accrued liabilities	The following information summarizes accrued liabilities as of September 30, 2015 and December 31, 2014 (in thousands): September 30, December 31, 2015 2014 Capital expenditures $ $ Other: General and administrative costs Production taxes Ad valorem taxes Lease operating expenses Interest payable Leasehold improvements — Total accrued liabilities $ $

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	9 Months Ended
	Sep. 30, 2015
Stockholders' Equity
Schedule of computation of basic and diluted net loss per share	The following table shows the computation of basic and diluted net loss per share for the three and nine months ended September 30, 2015 and 2014 (in thousands, except per share amounts): Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 Net income (loss) $ $ $ $ Less: Preferred stock dividends Net loss allocable to participating securities (1) — — 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 (2)(3)(4) — — — Denominator for diluted earnings (loss) per common share Net income (loss) per common share - basic $ $ $ $ Net income (loss) per common share - diluted $ $ $ $ (1) For the three and nine months ended September 30, 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. (2) The three and nine months ended September 30, 2015 excludes 597,910 and 2,663,010 shares of weighted average restricted stock and 12,530,695 s hares 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 commo n share as these shares were anti-dilutive. (3) The nine months ended September 30, 2014 excludes 1,290,637 shares of weighted average restricted stock and 13,863,738 shares of common stock resulting from an assumed conversion of the Series A Preferred Stock and Series B Pr eferred 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)	9 Months Ended
	Sep. 30, 2015
Stock-Based Compensation
Schedule of stock-based compensation expense	The Company recognized the following stock-based compensation expense (in thousands) which is included in general and administrative expense in the condensed consolidated statements of operations: Three Months Ended Nine Months Ended September 30, September 30, 2015 2014 2015 2014 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 nine months ended September 30, 2015 and 2014 is presented below (in thousands): Nine Months Ended September 30, September 30, 2015 2014 Non-vested common stock, beginning of period Granted Vested Forfeited Non-vested common stock, end of period

Acquisitions and Divestitures37

Acquisitions and Divestitures (Details) $ / shares in Units, $ in Thousands	Aug. 03, 2015shares	Mar. 31, 2015USD ($)itemshares	Jun. 30, 2014USD ($)item	Sep. 30, 2015USD ($)$ / shares	Sep. 30, 2014USD ($)$ / shares	Sep. 30, 2015USD ($)$ / shares	Sep. 30, 2014USD ($)$ / shares	Jun. 27, 2014
Acquisitions
Proceeds from issuance of debt							$ 100,000
Divestitures
Common units (in shares) | shares	1,052,632
Unaudited pro forma combined statements of operations
Revenues				$ 114,526	$ 195,937	$ 363,005	614,578
Net loss attributable to common stockholders				$ (421,024)	$ 42,150	$ (1,442,100)	$ 18,483
Net loss per common share, basic and diluted (in dollars per share) | $ / shares				$ (7.33)	$ 0.76	$ (25.24)	$ 0.38
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
Percentage of working interest owned		47.50%
Percentage of working interest retained per wellbore		2.50%
Consideration in cash		$ 83,000
Adjusted consideration in cash		81,400
Senior Notes 6.125 Percent Due 2023
Acquisitions
Interest rate (as a percent)				6.125%		6.125%		6.125%
Catarina
Acquisitions
Gross producing wells | item			176
Total purchase price allocated to assets purchased and liabilities assumed
Proved oil and natural gas properties			$ 446,906
Unproved properties			122,224
Other assets acquired			2,682
Fair value of assets acquired			571,812
Asset retirement obligations			(14,723)
Fair value of net assets acquired			557,089
Catarina | Senior Notes 6.125 Percent Due 2023
Acquisitions
Proceeds from issuance of debt			$ 850,000
Interest rate (as a percent)			6.125%
SPP
Divestitures
Value of equity method investment		$ 2,000
SPP | Palmetto | Disposed of by sale, not discontinued operations
Divestitures
Common units (in shares) | shares		1,052,632
Value of equity method investment		$ 2,000

Cash and Cash Equivalents (Deta

Cash and Cash Equivalents (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
Cash and cash equivalents
Total cash and cash equivalents	$ 196,884	$ 473,714	$ 596,272	$ 153,531
Cash at banks
Cash and cash equivalents
Total cash and cash equivalents	76,544	73,528
Money market funds
Cash and cash equivalents
Total cash and cash equivalents	$ 120,340	$ 400,186

Oil and Natural Gas Properties

Oil and Natural Gas Properties (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Oil and Natural Gas Properties
Impairment expense	$ 454,628	$ 0	$ 1,365,000	$ 0

Long-Term Debt (Summary) (Detai

Long-Term Debt (Summary) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Feb. 27, 2015	Dec. 31, 2014	Sep. 12, 2014	Jul. 18, 2014	Jun. 27, 2014	Sep. 18, 2013	Jun. 13, 2013
Long-Term Debt
Face value of debt	$ 1,750,000		$ 1,750,000			$ 1,750,000
Total long-term debt	1,746,807		1,746,807			1,746,263
Interest expense
Interest on Senior Notes	(29,234)	$ (25,316)	(87,704)	$ (48,999)
Interest expense and commitment fees on credit agreement	(301)	(384)	(940)	(1,277)
Amortization of debt issuance costs	(1,748)	(1,710)	(5,312)	(7,215)
Amortization of discount on additional 7.75% notes	(226)	(227)	(678)	(679)
Amortization of premium on additional 6.125% notes	67	25	134	25
Total interest expense	$ (31,442)	$ (27,612)	$ (94,500)	$ (58,145)
Senior Notes 7.75 Percent Due 2021
Long-Term Debt
Interest rate (as a percent)	7.75%		7.75%								7.75%
Face value of debt	$ 600,000		$ 600,000			600,000		$ 600,000		$ 200,000	$ 400,000
Unamortized discount on Additional 7.75% Notes	$ (5,160)		$ (5,160)			(5,837)				$ (7,000)
Senior Notes 6.125 Percent Due 2023
Long-Term Debt
Interest rate (as a percent)	6.125%		6.125%						6.125%
Face value of debt	$ 1,150,000		$ 1,150,000		$ 1,150,000	1,150,000	$ 300,000		$ 850,000
Unamortized premium on Additional 6.125% Notes	$ 1,967		$ 1,967			$ 2,100	$ 2,300

Long-Term Debt (Detail) (Detail

Long-Term Debt (Detail) (Details) $ in Thousands	Jul. 20, 2015USD ($)	Sep. 12, 2014USD ($)	Jun. 30, 2014USD ($)	Jun. 27, 2014USD ($)	Sep. 18, 2013USD ($)	Jun. 13, 2013USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2013USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Oct. 30, 2015USD ($)	Sep. 29, 2015USD ($)	Mar. 31, 2015USD ($)	Feb. 27, 2015USD ($)	Dec. 31, 2014USD ($)	Oct. 01, 2014USD ($)	Jul. 18, 2014USD ($)	May. 12, 2014USD ($)	May. 31, 2013USD ($)
Long-Term Debt
Face value of debt							$ 1,750,000			$ 1,750,000						$ 1,750,000
Interest Expense							31,442	$ 27,612		94,500	$ 58,145
Proceeds from issuance of debt											100,000
Senior Notes 7.75 Percent Due 2021
Long-Term Debt
Face value of debt					$ 200,000	$ 400,000	$ 600,000			$ 600,000						600,000		$ 600,000
Interest rate (as a percent)						7.75%	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%
Original discount and related offering expenses					$ 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	$ 1,150,000
Interest rate (as a percent)				6.125%			6.125%			6.125%
Proceeds for issuance of notes, net of discount/premium and related offering expenses		$ 295,900		$ 829,000				299,700
Percentage value of Additional Notes at which they are offered in private offering		100.75%
Original discount and related offering expenses		$ 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
Aggregate elected commitment amount			$ 300,000											$ 300,000			$ 300,000
Credit facility used							$ 0			$ 0
Borrowing base								$ 362,500			$ 362,500			$ 550,000			$ 650,000
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
Threshold on investments to develop a midstream facility	$ 10,000
Threshold on investments to develop, own and operate midstream assets	$ 80,000
Threshold percentage of equity interest to be exchanged for undivided interest	2.00%
Threshold equity interest in JV to be exchanged for undivided interest	$ 5,000
Consideration percentage for which the midstream assets could be disposed of	25.00%
Ratio of LTM EBITDA to consolidated LTM net interest expense	2.25
Second Amended And Restated Credit Agreement | Subsequent Events
Long-Term Debt
Threshold on investments to develop a midstream facility												$ 115,000
Second Amended And Restated Credit Agreement | Minimum
Long-Term Debt
Percentage of commitment fee on the unused committed amount			0.375%
Current ratio			1
Second Amended And Restated Credit Agreement | Maximum
Long-Term Debt
Percentage of commitment fee on the unused committed amount			0.50%
Ratio of total debt outstanding to consolidated EBITDA			2.25
Second Amended And Restated Credit Agreement | Alternate base rate | Minimum
Long-Term Debt
Variable rate basis, spread percentage			0.50%
Second Amended And Restated Credit Agreement | Alternate base rate | Maximum
Long-Term Debt
Variable rate basis, spread percentage			1.50%
Second Amended And Restated Credit Agreement | Eurodollar rate | Minimum
Long-Term Debt
Variable rate basis, spread percentage			1.50%
Second Amended And Restated Credit Agreement | Eurodollar rate | Maximum
Long-Term Debt
Variable rate basis, spread percentage			2.50%
Letters of credit
Long-Term Debt
Maximum borrowing capacity			$ 80,000										$ 80,000
Amount outstanding							$ 0			$ 0

Derivative Instruments (Details

Derivative Instruments (Details) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2015USD ($)MMBTU$ / bbl$ / MMBTUbbl	Sep. 30, 2014USD ($)	Dec. 31, 2014USD ($)
Reconciliation of the changes in fair value of the commodity derivatives
Net premiums on derivative contracts | $	$ (121)	$ (241)
Not designated as hedges | Commodity derivative contract
Reconciliation of the changes in fair value of the commodity derivatives
Beginning fair value of commodity derivatives | $	123,316	$ (3,397)	$ (3,397)
Ending fair value of commodity derivatives | $	162,433		123,316
Not designated as hedges | Commodity derivative contract | Crude oil
Reconciliation of the changes in fair value of the commodity derivatives
Net gains on derivatives | $	120,894		115,602
Net settlements on derivative contracts | $	(83,948)		(4,503)
Net premiums on derivative contracts | $			(4,892)
Not designated as hedges | Commodity derivative contract | Natural gas
Reconciliation of the changes in fair value of the commodity derivatives
Net gains on derivatives | $	15,204		21,603
Net settlements on derivative contracts | $	$ (13,033)		$ (1,097)
Not designated as hedges | Swaps | October to December 2015 | Crude oil
Derivative contract covering anticipated future production
Notional amount (in barrels) | bbl	1,288,000
Average price per unit | $ / bbl	73.23
Not designated as hedges | Swaps | October to December 2015 | Natural gas
Derivative contract covering anticipated future production
Notional amount (in Mmbtu) | MMBTU	2,150,000
Average price per unit	3.90
Not designated as hedges | Swaps | 2016 | Crude oil
Derivative contract covering anticipated future production
Notional amount (in barrels) | bbl	2,562,000
Average price per unit | $ / bbl	70.11
Not designated as hedges | Swaps | 2016 | Natural gas
Derivative contract covering anticipated future production
Notional amount (in Mmbtu) | MMBTU	14,640,000
Average price per unit	3.87
Not designated as hedges | Swaps | 2017 | Natural gas
Derivative contract covering anticipated future production
Notional amount (in Mmbtu) | MMBTU	3,650,000
Average price per unit	3.65
Not designated as hedges | Puts | 2016 | Crude oil
Derivative contract covering anticipated future production
Notional amount (in barrels) | bbl	4,026,000
Not designated as hedges | Puts | Puts | 2016 | Crude oil
Derivative contract covering anticipated future production
Average option price per unit | $ / bbl	60
Not designated as hedges | Three-way collar contracts | October to December 2015 | Natural gas
Derivative contract covering anticipated future production
Notional amount (in Mmbtu) | MMBTU	920,000
Not designated as hedges | Three-way collar contracts | Puts | Long | October to December 2015 | Natural gas
Derivative contract covering anticipated future production
Average option price per unit	4
Not designated as hedges | Three-way collar contracts | Puts | Short | October to December 2015 | Natural gas
Derivative contract covering anticipated future production
Average option price per unit	3.50
Not designated as hedges | Three-way collar contracts | Call | Short | October to December 2015 | Natural gas
Derivative contract covering anticipated future production
Average option price per unit	4.90
Not designated as hedges | Enhanced swaps | October to December 2015 | Natural gas
Derivative contract covering anticipated future production
Notional amount (in Mmbtu) | MMBTU	2,852,000
Average swap price per unit	4.31
Not designated as hedges | Enhanced swaps | Puts | October to December 2015 | Natural gas
Derivative contract covering anticipated future production
Average option price per unit	3.75
Minimum | Not designated as hedges | Swaps | October to December 2015 | Crude oil
Derivative contract covering anticipated future production
Average price per unit | $ / bbl	67
Minimum | Not designated as hedges | Swaps | October to December 2015 | Natural gas
Derivative contract covering anticipated future production
Average price per unit	3.54
Minimum | Not designated as hedges | Swaps | 2016 | Crude oil
Derivative contract covering anticipated future production
Average price per unit | $ / bbl	62
Minimum | Not designated as hedges | Swaps | 2016 | Natural gas
Derivative contract covering anticipated future production
Average price per unit	3.80
Minimum | Not designated as hedges | Puts | Puts | 2016 | Crude oil
Derivative contract covering anticipated future production
Average option price per unit | $ / bbl	60
Maximum | Not designated as hedges | Swaps | October to December 2015 | Crude oil
Derivative contract covering anticipated future production
Average price per unit | $ / bbl	88.35
Maximum | Not designated as hedges | Swaps | October to December 2015 | Natural gas
Derivative contract covering anticipated future production
Average price per unit	4.01
Maximum | Not designated as hedges | Swaps | 2016 | Crude oil
Derivative contract covering anticipated future production
Average price per unit | $ / bbl	80.15
Maximum | Not designated as hedges | Swaps | 2016 | Natural gas
Derivative contract covering anticipated future production
Average price per unit	3.92
Maximum | Not designated as hedges | Swaps | 2017 | Natural gas
Derivative contract covering anticipated future production
Average price per unit	3.65
Maximum | Not designated as hedges | Puts | Puts | 2016 | Crude oil
Derivative contract covering anticipated future production
Average option price per unit | $ / bbl	60

Derivative Instruments (BalShee

Derivative Instruments (BalSheet) (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	$ 166,565	$ 218,977
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(4,132)	(94,772)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	162,433	124,205
Offsetting Derivative Liabilities:
Gross Amount of Recognized Assets	(4,132)	(95,661)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	4,132	94,772
Net Amounts Presented in the Condensed Consolidated Balance Sheets		(889)
Current asset
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	136,123	194,953
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	(4,132)	(94,772)
Net Amounts Presented in the Condensed Consolidated Balance Sheets	131,991	100,181
Long-term asset
Offsetting Derivative Assets:
Gross Amount of Recognized Assets	30,442	24,024
Net Amounts Presented in the Condensed Consolidated Balance Sheets	30,442	24,024
Current liability
Offsetting Derivative Liabilities:
Gross Amount of Recognized Assets	(4,132)	(94,772)
Gross Amounts Offset in the Condensed Consolidated Balance Sheets	$ 4,132	94,772
Long-term liability
Offsetting Derivative Liabilities:
Gross Amount of Recognized Assets		(889)
Net Amounts Presented in the Condensed Consolidated Balance Sheets		$ (889)

Investments (Details)

Investments (Details) $ in Millions	Oct. 14, 2015shares	Aug. 03, 2015shares	Sep. 30, 2015USD ($)	Sep. 30, 2015USD ($)	Mar. 31, 2015USD ($)
Investments in marketable securities
Common units (in shares) | shares		1,052,632
Stock split (as a percent)		0.1
SPP
Investments in marketable securities
Value of equity method investment					$ 2
Investment gains (losses) recorded			$ (0.9)	$ (0.8)
Subsequent Events | SPP
Investments in marketable securities
Common units (in shares) | shares	105,263

Fair Value of Financial Instr45

Fair Value of Financial Instruments (Details) - Recurring basis - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Fair Value of Financial Instruments
Cash and cash equivalents	$ 120,340	$ 400,186
Investment in SPP	1,136
Total	283,909	523,502
Active Market for Identical Assets (Level 1)
Fair Value of Financial Instruments
Cash and cash equivalents	120,340	400,186
Investment in SPP	1,136
Total	121,476	400,186
Observable Inputs (Level 2)
Fair Value of Financial Instruments
Total	162,433	47,793
Unobservable Inputs (Level 3)
Fair Value of Financial Instruments
Total		75,523
Swaps | Crude oil
Fair Value of Financial Instruments
Derivative instruments	88,322	33,975
Swaps | Crude oil | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments	88,322	33,975
Swaps | Natural gas
Fair Value of Financial Instruments
Derivative instruments	20,619	13,818
Swaps | Natural gas | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments	20,619	13,818
Enhanced swaps | Crude oil
Fair Value of Financial Instruments
Derivative instruments		44,586
Enhanced swaps | Crude oil | Unobservable Inputs (Level 3)
Fair Value of Financial Instruments
Derivative instruments		44,586
Enhanced swaps | Natural gas
Fair Value of Financial Instruments
Derivative instruments	1,588	5,193
Enhanced swaps | Natural gas | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments	1,588
Enhanced swaps | Natural gas | Unobservable Inputs (Level 3)
Fair Value of Financial Instruments
Derivative instruments		5,193
Three-way collar contracts | Crude oil
Fair Value of Financial Instruments
Derivative instruments		24,264
Three-way collar contracts | Crude oil | Unobservable Inputs (Level 3)
Fair Value of Financial Instruments
Derivative instruments		24,264
Three-way collar contracts | Natural gas
Fair Value of Financial Instruments
Derivative instruments	456	1,480
Three-way collar contracts | Natural gas | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments	456
Three-way collar contracts | Natural gas | Unobservable Inputs (Level 3)
Fair Value of Financial Instruments
Derivative instruments		$ 1,480
Puts | Crude oil
Fair Value of Financial Instruments
Derivative instruments	51,448
Puts | Crude oil | Observable Inputs (Level 2)
Fair Value of Financial Instruments
Derivative instruments	$ 51,448

Fair Value of Financial Instr46

Fair Value of Financial Instruments (Level3 Rec) (Details) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Jun. 27, 2014	Jun. 13, 2013
Derivative instrument
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Beginning balance	$ (16,774)	$ 75,523	$ (519)
Total gains included in earnings	26,189	418	8,389
Net settlements on derivative contracts	200	(14,277)	1,745
Derivative contracts transferred to Level 2		(61,664)
Ending balance	9,615		9,615
Gains (losses) included in earnings related to derivatives still held	$ 26,747	(940)	$ 10,492
Observable Inputs (Level 2) | Derivative instrument
Changes in the fair value of the company s oil derivative instruments classified as Level 3 in the fair value hierarchy
Net settlements on derivative contracts		$ (12,919)
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		$ 447,000
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		$ 747,500

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended	12 Months Ended
	Sep. 30, 2015	Jun. 30, 2015	Sep. 30, 2015	Dec. 31, 2014
Changes in the asset retirement obligation
Abandonment liability, beginning of period			$ 25,694	$ 4,130
Liabilities incurred during period			4,454	3,922
Acquisitions				14,723
Divestitures			(379)
Revisions			3,273	1,658
Accretion expense			1,517	1,261
Abandonment liability, end of period	$ 34,559		$ 34,559	$ 25,694
Asset retirement obligation per well	$ 150	$ 120

Related Party Transactions (Det

Related Party Transactions (Details) $ in Thousands	1 Months Ended		3 Months Ended		9 Months Ended
	Aug. 31, 2015USD ($)item	Aug. 31, 2013USD ($)aitemshares	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Dec. 31, 2014USD ($)
Related Party Transactions
Accounts receivable - related entities | $			$ 3,790		$ 3,790		$ 386
TMS
Related Party Transactions
Number of sellers		3
Number of third-parties		2
Number of related parties		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 | $			6,694	$ 5,982	19,548	$ 18,444
Third-party expenses | $			1,534	2,452	3,550	5,135
Total included in general and administrative expenses | $			8,228	$ 8,434	23,098	$ 23,579
Accounts receivable - related entities | $			$ 3,800		$ 3,800		$ 400
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		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		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		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		3
Amount payable in lieu of drilling the two additional wells | $	$ 8,000
Number of additional wells planned for deferred drilling	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		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		3
President | SR | TMS
Related Party Transactions
Ownership of minority owner (as a percent)		24.05%

Related Party Transactions (Div

Related Party Transactions (Divestiture) (Details)	Oct. 14, 2015USD ($)abbl / dMcf / dshares	Aug. 03, 2015shares
Divestiture
Common units (in shares) | shares		1,052,632
Subsequent Events | Disposed of by sale, not discontinued operations | Western Catarina Midstream Divestiture
Divestiture
Consideration in cash	$ 345,800,000
Term of agreement	15 years
Area under agreement (in acres) | a	35,000
Term of gas gathering agreement	5 years
Subsequent Events | SPP
Divestiture
Common units (in shares) | shares	105,263
Subsequent Events | SPP | Disposed of by sale, not discontinued operations | Western Catarina Midstream Divestiture
Divestiture
Common units (in shares) | shares	105,263
Crude oil | Subsequent Events | Disposed of by sale, not discontinued operations | Western Catarina Midstream Divestiture
Divestiture
Daily delivery commitment (in units) | bbl / d	10,200
Gathering and processing fees	$ 0.96
Natural gas | Subsequent Events | Disposed of by sale, not discontinued operations | Western Catarina Midstream Divestiture
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	Sep. 30, 2015	Dec. 31, 2014
Accrued Liabilities
Capital expenditures	$ 72,094	$ 162,726
General and administrative costs	6,149	830
Production taxes	2,390	3,137
Ad valorem taxes	4,875	1,994
Lease operating expenses	24,286	22,354
Interest payable	28,281	37,743
Leasehold improvements		1,104
Total accrued liabilities	$ 138,075	$ 229,888

Stockholders' Equity (Details)

Stockholders' Equity (Details) $ / shares in Units, $ in Thousands	Jul. 28, 2015itemshares	Aug. 28, 2014USD ($)shares	Jun. 12, 2014USD ($)$ / sharesshares	May. 29, 2014USD ($)shares	Feb. 12, 2014USD ($)shares	Mar. 26, 2013USD ($)$ / sharesshares	Sep. 17, 2012USD ($)$ / sharesshares	Sep. 30, 2015item$ / shares	Sep. 30, 2014USD ($)	Dec. 31, 2014$ / shares
Common stock, par value (in dollars per share) | $ / shares								$ 0.01		$ 0.01
Payments for offering costs | $									$ 8,731
Fair value of the shares of common stock issued in excess of the carrying value of the Series A Preferred Stock and Series B Preferred Stock redeemed | $		$ 300		$ 3,100	$ 13,900
Number of rights declared for each common stock	1
Number of rights automatically attached | item	1
Threshold percentage of common stock to be qualified as an acquiring person	4.90%
Common Stock
Number of shares issued			5,000,000
Issue price (in dollars per share) | $ / shares			$ 35.25
Net proceeds from public offering of shares of common stock | $			$ 167,500
Payments for offering costs | $			$ 8,700
Number of shares of common stock to be issued if all preferred shares are converted							4,275,640
Preferred Class A
Number of shares issued							3,000,000
Issue price (in dollars per share) | $ / shares							$ 50
Proceeds from the private placement of preferred stock | $							$ 144,500
Payments for offering costs | $							$ 5,500
Conversion ratio (in shares)					2.325		2.325
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 | $						$ 216,600
Payments for offering costs | $						$ 8,400
Conversion ratio (in shares)					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				210,820	756,850
Shares of common stock issued upon conversion of preferred stock				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 ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Earnings (Loss) Per Share
Net income (loss)	$ (416,860,000)	$ 49,031,000	$ (1,477,115,000)	$ 40,318,000
Preferred stock dividends	(3,991,000)	(4,274,000)	(11,973,000)	(29,599,000)
Net loss allocable to participating securities	0	(2,068,000)	0	(495,000)
Net income (loss) attributable to common stockholders	$ (420,851,000)	$ 42,689,000	$ (1,489,088,000)	$ 10,224,000
Weighted average number of unrestricted outstanding common shares used to calculate basic net loss per share	57,426,000	55,732,000	57,141,000	51,153,000
Dilutive shares		12,608,000
Denominator for diluted net loss per common share	57,426,000	68,340,000	57,141,000	51,153,000
Net income (loss) per common share - basic ( in dollars per share)	$ (7.33)	$ 0.77	$ (26.06)	$ 0.20
Net income (loss) per common share - diluted ( in dollars per share)	$ (7.33)	$ 0.69	$ (26.06)	$ 0.20
Restricted stock
Earnings (Loss) Per Share
Anti-dilutive common stock	597,910		2,663,010	1,290,637
Convertible Preferred Stock
Earnings (Loss) Per Share
Anti-dilutive common stock		12,607,521	12,530,695	13,863,738
Dividend impact on net income		$ 4,274,445

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Stock-Based Compensation
Maximum number of shares of common stock	4,000,000		4,000,000
Common stock available for incentive awards, as a percentage of the issued and outstanding shares of common stock	15.00%		15.00%
Total stock-based compensation expense	$ 355	$ 10	$ 15,924	$ 25,888
Non-employees
Stock-Based Compensation
Total stock-based compensation expense	$ 81		$ 15,082	$ 25,157
Stock-based compensation expense true-up		$ (161)
Restricted stock
Additional disclosure related to compensation cost
Closing price of common stock (in dollars per share)	$ 6.15		$ 6.15
Unrecognized compensation costs related to non-vested restricted shares outstanding	$ 20,700		$ 20,700
Expected average period for recognition of unrecognized compensation costs related to non-vested shares			2 years 1 month 6 days
Number of Non-Vested Shares
Non-vested common stock at the beginning of the period (in shares)			2,718,000	1,758,000
Granted (in shares)			3,421,000	1,966,000
Vested (in shares)			(1,601,000)	(692,000)
Forfeited (in shares)			(117,000)	(313,000)
Non-vested common stock at the end of the period (in shares)	4,421,000	2,719,000	4,421,000	2,719,000
Shares available for future issuance to participants	5,300,000		5,300,000
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)	229,600		3,300,000
Restricted stock | Directors
Stock-Based Compensation
Total stock-based compensation expense	$ 274	$ 171	$ 842	$ 731
Number of Non-Vested Shares
Granted (in shares)	0		95,200

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Income Taxes
Effective tax rate (as a percent)	0.00%	35.20%	(0.50%)	35.30%
Federal statutory corporate income tax rate (as a percent)	35.00%	35.00%	35.00%	35.00%
Net operating loss carryforwards	$ 656.5		$ 656.5
Valuation allowance	519.2		519.2
Net deferred tax assets	$ 0		$ 0

Commitments and Contingencies (

Commitments and Contingencies (Details) $ in Millions	Dec. 16, 2013item	Sep. 30, 2015USD ($)aitem
Operating leases
Lease payment obligation		$ 65.9
Catarina
Commitments and contingencies
Area of undeveloped acreage acquired (in acres) | a		77,000
Maximum number of wells to be drilled in each annual period commencing July 1, 2014 | item		50
Minimum number of wells to be drilled in any consecutive 120 days period in order to continue to maintain rights to any future undeveloped acreage | item		1
Consecutive period over which at least one well can be drilled in order to continue to maintain rights to any future undeveloped acreage		120 days
Maximum number of wells that can be carried over to satisfy part of the 50 well requirement in the subsequent annual period on a well for well basis | item		30
Consolidated Derivative Actions
Commitments and contingencies
Number of derivative actions filed | item	3
Corporate office Lease
Operating leases
Lease payment obligation		$ 52.1
Land Lease
Operating leases
Lease payment obligation		$ 7.1
Advanced written notice required to terminate lease obligation		180 days
Lease termination penalty		$ 1
Acreage Lease
Operating leases
Lease payment obligation		$ 6.8
Term of acreage lease		10 years
Advanced written notice required to terminate lease obligation		9 months
Permanent improvements
Operating leases
Lease payment obligation		$ 4
Term of acreage lease		10 years

Subsidiary Guarantors (Details)

Subsidiary Guarantors (Details) - USD ($)	9 Months Ended
	Sep. 30, 2015	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%

Subsequent Events (Details)

Subsequent Events (Details) MMcf in Thousands	Oct. 30, 2015USD ($)	Oct. 14, 2015USD ($)abbl / dMcf / d	Oct. 02, 2015USD ($)miMMcfMcf	Jul. 20, 2015USD ($)
Subsequent Events | Midstream Joint Venture
Subsequent Events
Term of agreement			15 years
Anticipated aggregate cost			$ 115,000,000
Ownership (as a percent)			50.00%
Length of pipeline (in miles) | mi			45
Subsequent Events | Midstream Joint Venture | Initial
Subsequent Events
Term of agreement			5 years
Gas processing plant capacity (in MMcf) | Mcf			125,000
Western Catarina Midstream Divestiture | Disposed of by sale, not discontinued operations | Subsequent Events
Subsequent Events
Term of agreement		15 years
Area under agreement (in acres) | a		35,000
Term of gas gathering agreement		5 years
Crude oil | Western Catarina Midstream Divestiture | Disposed of by sale, not discontinued operations | Subsequent Events
Subsequent Events
Daily delivery commitment (in units) | bbl / d		10,200
Gathering and processing fees		$ 0.96
Natural gas | Western Catarina Midstream Divestiture | Disposed of by sale, not discontinued operations | Subsequent Events
Subsequent Events
Daily delivery commitment (in units) | Mcf / d		142,000
Gathering and processing fees		$ 0.74
Minimum | Subsequent Events | Midstream Joint Venture
Subsequent Events
Gas processing plant capacity (in MMcf) | MMcf			200
Maximum | Subsequent Events | Midstream Joint Venture
Subsequent Events
Gas processing plant capacity (in MMcf) | MMcf			260
Second Amended And Restated Credit Agreement
Subsequent Events
Threshold on investments to develop a midstream facility				$ 10,000,000
Second Amended And Restated Credit Agreement | Subsequent Events
Subsequent Events
Threshold on investments to develop a midstream facility	$ 115,000,000
Threshold on other investments	$ 50,000,000
Period allowed to file fourth quarter financials	45 days