Evolve Transition Infrastructure (SNMP) 10-K 30 Mar 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Mar. 30, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Entity Registrant Name	Sanchez Production Partners LP
Entity Central Index Key	1,362,705
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		3,031,051
Entity Public Float			$ 56,025,082
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Revenues
Natural gas sales	$ 19,809	$ 34,458
Oil sales	35,297	40,337
Natural gas liquid sales	1,597	2,477
Gathering and transportation sales	11,725
Total revenues	68,428	77,272
Operating expenses:
Lease operating expenses	19,988	21,012
Transportation operating expenses	2,176
Cost of sales	595	1,487
Production taxes	1,792	3,200
General and administrative	26,109	16,499
Exploration costs	1,866
(Gain) loss on sale of assets	(111)	223
Depreciation, depletion and amortization	14,536	17,533
Asset impairments	123,860	5,424
Accretion expense	1,099	604
Total operating expenses	191,910	65,982
Other expense (income)
Interest expense	4,207	2,076
Loss on embedded derivatives	9,982
Other income	(670)	(289)
Total other expenses	13,519	1,787
Total expenses	205,429	67,769
Income (loss) before income taxes	(137,001)	9,503
Income tax expense	55
Net income (loss)	(137,056)	9,503
Less:
Preferred unit paid-in-kind distributions	(1,425)
Preferred unit dividends	(7,418)
Preferred unit amortization	(8,919)
Net income (loss) attributable to common unitholders	$ (154,818)	9,503
Class A Unit [Member]
Other expense (income)
Net income (loss)		190
Less:
Net income (loss) attributable to common unitholders		$ 190
Income (loss) per unit
Net income (loss) per unit, basic (in dollars per unit)	$ (0.38)	$ 0.25
Net income (loss) per unit, diluted (in dollars per unit)	$ (0.38)	0.25
Net loss per unit after conversion Common units - Basic & Diluted		$ 2.50
Weighted Average Units Outstanding - Basic	48,451	76,326
Weighted Average Units Outstanding - Diluted	48,451	76,326
Class B Unit [Member]
Other expense (income)
Net income (loss)		$ 9,313
Less:
Net income (loss) attributable to common unitholders		$ 9,313
Income (loss) per unit
Net income (loss) per unit, basic (in dollars per unit)	$ (0.31)	$ 0.33
Net income (loss) per unit, diluted (in dollars per unit)	$ (0.31)	0.33
Net loss per unit after conversion Common units - Basic & Diluted		$ 3.30
Weighted Average Units Outstanding - Basic	2,879,163	2,843,159
Weighted Average Units Outstanding - Diluted	2,879,163	2,853,241
Common Units [Member]
Income (loss) per unit
Net loss per unit after conversion Common units - Basic & Diluted	$ (50.10)
Weighted Average Units Outstanding - Basic		2,919,485
Weighted Average Units Outstanding - Diluted		2,929,567
Weighted Average Units Outstanding after conversion Common units - Basic & Diluted	3,071,587

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 6,571	$ 4,238
Restricted cash	600	1,748
Accounts receivable	2,461	3,901
Accounts receivable - related entities	1,515	959
Prepaid expenses	744	1,783
Fair value of derivative instruments	21,010	14,671
Total current assets	32,901	27,300
Oil and natural gas properties and related equipment
Oil and natural gas properties, equipment and facilities (successful efforts method)	732,088	651,493
Gathering and transportation assets	147,479
Material and supplies	1,056	1,056
Less accumulated depreciation, depletion, amortization, accretion and impairments	(653,569)	(517,239)
Oil and natural gas properties and equipment, net	227,054	135,310
Other assets
Debt issuance costs	2,091	689
Intangible Assets	199,741
Fair value of derivative instruments	10,008	8,158
Other non-current assets	1,596	1,790
Total assets	473,391	173,247
Current liabilities
Accounts payable and accrued liabilities	7,288	5,759
Accounts payable and accrued liabilities - related entities	1,035
Royalties payable	689	1,134
Total current liabilities	9,012	6,893
Other liabilities
Asset retirement obligation	20,364	$ 17,031
Embedded derivatives	193,077
Long-term debt	107,000	$ 42,500
Total other liabilities	320,441	59,531
Total liabilities	329,453	66,424
Members' equity / Partners' capital
Common units	(45,285)
Total members' equity/partners' capital (deficit)	(28,173)	106,823
Total liabilities and members' equity/partners' capital	473,391	173,247
Class B Preferred [Member]
Mezzanine equity
Class B preferred units, 19,444,445 and zero units issued and outstanding as of December 31, 2015 and December 31, 2014, respectively	172,111
Class A Unit [Member]
Members' equity / Partners' capital
Common units		1,930
Total members' equity/partners' capital (deficit)		1,930
Class B Unit [Member]
Members' equity / Partners' capital
Common units		104,893
Total members' equity/partners' capital (deficit)		$ 104,893
Class A Preferred [Member]
Members' equity / Partners' capital
Class A preferred units, 11,409,131 and zero units issued and outstanding as of December 31, 2015 and December 31, 2014, respectively	17,112
Total members' equity/partners' capital (deficit)	17,112
Common Units [Member]
Members' equity / Partners' capital
Total members' equity/partners' capital (deficit)	$ (45,285)

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical)	Dec. 31, 2015shares	Dec. 31, 2014shares
Class B Preferred [Member]
Class B preferred units, issued	19,444,445	0
Class B preferred units, outstanding	19,444,445	0
Class A Unit [Member]
Common units, issued	0	48,451
Common units, outstanding	0	48,451
Class B Unit [Member]
Common units, issued	0	2,877,701
Common units, outstanding	0	2,877,701
Class A Preferred [Member]
Class A preferred units, issued	11,409,131	0
Class A preferred units, outstanding	11,409,131	0
Common Units [Member]
Common units, issued	3,240,812	0
Common units, outstanding	3,240,812	0

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Net income (loss)	$ (137,056)	$ 9,503
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	13,250	17,533
Amortization of intangible assets	2,804
Asset impairments	123,861	5,424
Amortization of debt issuance costs	1,338	271
Dryhole/exploration expenses	1,866
Accretion expense	1,099	604
Revisions to asset retirement obligation included in DD&A	(1,518)
Equity earnings in affiliate	(80)	(216)
Distributions from equity affiliate	47
Gain (loss) from disposition of property and equipment	(111)	223
Bad debt expense	122	94
Total mark-to-market on commodity derivative contracts	(25,149)	(19,855)
Cash mark-to-market settlements on commodity derivative contracts	18,996	7,626
Unit-based compensation programs	2,454	1,298
Loss on embedded derivative	9,982
Costs for plug and abandon activities	(186)
Changes in Operating Assets and Liabilities:
Decrease in accounts receivable	4,166	1,370
Increase in accounts receivable - related entities	(1,515)
Decrease in accounts payable - related entities	1,035
Decrease in prepaid expenses	1,039	764
(Increase) decrease in other assets	300	2
Decrease in accounts payable/accrued liabilities	(862)	(7,534)
Decrease in royalty payable	(445)	(108)
Net cash provided by operating activities	15,437	16,999
Cash flows from investing activities:
Cash paid for acquisitions	(427,218)	(1,351)
Development of oil and natural gas properties	(2,005)	(5,865)
Proceeds from sale of assets	470	485
Distributions from equity affiliate	13	295
Net cash used in investing activities	(428,740)	(6,436)
Cash flows from financing activities:
Proceeds from issuance of preferred units	359,500
Payments for offering costs	(1,756)
Proceeds from issuance of debt	107,000	5,750
Repayment of debt	(42,500)	(13,950)
Issuance of common units	193
Members' cash contributions	(1,219)
Repurchase of common units under repurchase program	(2,223)
Units tendered by employees for tax withholdings	(618)	(415)
Repurchase of Class A, Class C and Class D interests		(2,468)
Debt issuance costs	(2,741)	(136)
Net cash provided by (used in) financing activities	415,636	(11,219)
Net increase (decrease) in cash and cash equivalents	2,333	(656)
Cash and cash equivalents, beginning of period	4,238	4,894
Cash and cash equivalents, end of period	6,571	4,238
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	1,684	(512)
Acquisition of oil and natural gas properties in exchange for common units	935
Cash paid during the period for interest	2,380	1,841
Cash paid during the period for income taxes	$ 53	$ (73)

Consolidated Statements Of Chan

Consolidated Statements Of Changes In Members' Equity - USD ($) $ in Thousands	Class A Unit [Member]	Class B Unit [Member]	Class A Preferred [Member]	Common Units [Member]	Total
Balance at Dec. 31, 2013	$ 2,591	$ 96,314			$ 98,905
Balance (in shares) at Dec. 31, 2013	161,502	2,846,218
Units tendered by employees for tax withholding		$ (415)			(415)
Units tendered by employees for tax withholding (in shares)		(16,018)
Unit-based compensation programs		$ 1,298			1,298
Unit-based compensation programs (in shares)		49,058
Cancellation of units	$ (851)	$ (1,617)			(2,468)
Cancellation of units (in shares)	(113,051)
Net income (loss)	$ 190	9,313			9,503
Balance at Dec. 31, 2014	$ 1,930	$ 104,893			106,823
Balance (in shares) at Dec. 31, 2014	48,451	2,879,258
Units tendered by employees for tax withholding		$ (21)			(21)
Units tendered by employees for tax withholding (in shares)		(1,557)
Net income (loss)	$ (18)	$ (905)			(923)
Balance at Mar. 05, 2015	$ 1,912	$ 103,967			105,879
Balance (in shares) at Mar. 05, 2015	48,451	2,877,701
Balance at Dec. 31, 2014	$ 1,930	$ 104,893			106,823
Balance (in shares) at Dec. 31, 2014	48,451	2,879,258
Net income (loss)					(137,056)
Balance at Dec. 31, 2015			$ 17,112	$ (45,285)	(28,173)
Balance (in shares) at Dec. 31, 2015			11,409,131	3,240,813
Balance at Mar. 05, 2015	$ 1,912	$ 103,967			105,879
Balance (in shares) at Mar. 05, 2015	48,451	2,877,701
Class A Units converted to common units upon limited partnership conversion	$ (1,912)			$ 1,912
Class A Units converted to common units upon limited partnership conversion (in shares)	(48,451)			58,729
Class B Units converted to common units upon limited partnership conversion		$ (103,967)		$ 103,967
Class B Units converted to common units upon limited partnership conversion (in shares)		(2,877,701)		2,877,701
Units tendered by employees for tax withholding				$ (597)	(597)
Units tendered by employees for tax withholding (in shares)				(32,269)
Unit-based compensation programs				$ 2,454	2,454
Unit-based compensation programs (in shares)				472,972
Private placement of Class A Preferred Units, net of offering costs			$ 16,550		16,550
Private placement of Class A Preferred Units, net of offering costs (in shares)			10,859,375
Beneficial conversion feature of Class A Preferred Units			$ (863)	$ 863
Preferred unit paid-in-kind distributors			$ 1,425	(1,425)
Preferred unit paid-in-kind distributors (in shares)			549,756
Issuance of common units				$ 193	193
Issuance of common units (in shares)				6,865
Common units retired via unit repurchase program				$ (2,223)	(2,223)
Common units retired via unit repurchase program (in shares)				(143,185)
Common units issued for acquisition of properties				$ 2,000	2,000
Common units issued for acquisition of properties (in shares)				105,263
Common units received and retired for acquisition of properties				$ (1,065)	(1,065)
Common units received and retired for acquisition of properties (in shares)				(105,263)
Cash distributions				$ (1,219)	(1,219)
Distributions - Class B preferred units				(14,012)	(14,012)
Net income (loss)				(136,133)	(136,133)
Balance at Dec. 31, 2015			$ 17,112	$ (45,285)	$ (28,173)
Balance (in shares) at Dec. 31, 2015			11,409,131	3,240,813

Consolidated Statements Of Cha7

Consolidated Statements Of Changes In Members' Equity (Parenthetical) $ in Millions	Dec. 31, 2015USD ($)
Class A Unit [Member]
Offering costs	$ 0.8

Organization And Business

Organization And Business	12 Months Ended
	Dec. 31, 2015
Organization And Business [Abstract]
Organization And Business	1. ORGANIZATION AND BUSINESS Organization Sanchez Production Partners LP, a Delaware limited partnership (“SPP”, “we”, “us”, “our” or the “Partnership”), is a publicly-traded limited partnership focused on the acquisition, development, ownership and operation of midstream and other energy production assets. SPP completed its initial public offering on November 20, 2006, as Constellation Energy Partners LLC (“CEP” or the “Company”). We have entered into a shared services agreement (the “Services Agreement”) with SP Holdings, LLC (the “Manager”), the sole member of our general partner, pursuant to which Manager provides services that the Partnership requires to operate its business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance and acquisition, disposition and financing services. On March 6, 2015, the Company’s unitholders approved the conversion of Sanchez Production Partners LLC to a Delaware limited partnership and the name was changed to Sanchez Production Partners LP. Manager owns the general partner of SPP and all of SPP’s incentive distribution rights. Our common units are currently listed on the NYSE MKT under the symbol “SPP.” Historically, our operations have consisted of the exploration and production of proved reserves located in the Cherokee Basin in Oklahoma and Kansas, the Woodford Shale in the Arkoma Basin in Oklahoma, the Central Kansas Uplift in Kansas, the Eagle Ford Shale in South Texas and in other areas of Texas and Louisiana. In October 2015, we consummated the acquisition of midstream assets in the Eagle Ford Shale from Sanchez Energy Corporation (“Sanchez Energy”) and entered into a 15 -year gathering and processing agreement with Sanchez Energy. We have also commenced a process to sell our oil and gas properties in the Mid-Continent region. As a result of the acquisition of midstream assets from Sanchez Energy, our historical financial statements (including those in this Form 10-K) will differ substantially from our future financial statements beginning with the quarter ended December 31, 2015 principally because a significant portion of our revenues will come from the long-term, fee-based gathering and processing agreement with Sanchez Energy rather than from oil and natural gas production.

Basis Of Presentation And Summa

Basis Of Presentation And Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
Basis Of Presentation And Summary Of Significant Accounting Policies [Abstract]
Basis Of Presentation And Summary Of Significant Accounting Policies	2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation Accounting policies used by us conform to accounting principles generally accepted in the United States of America. The accompanying financial statements include the accounts of us and our wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. We conduct our business activities as two operating segments: the exploration and production of oil and natural gas and the midstream business, which include the Catarina gathering system. Our management evaluates performance based on these two business segments. Recent Accounting Pronouncements From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our condensed consolidated financial statements upon adoption. In February 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018, with a modified retrospective approach to be used for implementation. ASU 2016-02 updates the previous lease guidance by requiring the recognition of a right-to-use asset and lease liability on the statement of financial position for those leases previously classified as operating leases under the old guidance. In addition, ASU 2016-02 updates the criteria for a lessee’s classification of a finance lease. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In November 2015, the FASB issued ASU 2015-17, “Balance Sheet Classification of Deferred Taxes”, which simplifies the presentation of deferred income taxes. This ASU requires that deferred tax assets and liabilities be classified as non-current in a statement of financial position by jurisdiction rather than separately presented as current and non-current portions. ASU 2015-17 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for financial statements as of the beginning of an interim or annual reporting period. The Company chose to adopt ASU 2015-17 as of the quarter ended December 31, 2015 on a retrospective basis. Adoption of this guidance did not affect the balance sheet as of December 31, 2014. In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory,” effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. In April 2015, the FASB issued ASU No. 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 International Financial Reporting Standards. Under this new standard, debt issuance costs related to a recognized the 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 No. 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis” to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. We are currently assessing the impact that adopting this new accounting guidance will have on our consolidated financial statements and footnote disclosures, but we 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. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows . Reclassifications Certain reclassifications have been made to the prior period to conform to the current period presentation. These reclassifications had no effect on total unitholders’ equity, net income or net cash provided by or used in operating, investing or financing activities and an immaterial effect on total assets and total liabilities. Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying footnotes. These estimates and the underlying assumptions affect the amounts of assets and liabilities reported, disclosures about contingent assets and liabilities and reported amounts of revenues and expenses. The estimates that are particularly significant to our financial statements include estimates of our reserves of oil, natural gas and natural gas liquids (“NGLs”); future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of commodity derivatives and fair values of assets and liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an on-going basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from the estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods. Cash and Cash Equivalents All highly liquid investments with original maturities of three months or less are considered cash equivalents. Checks-in-transit are included in accounts payable or as a reduction of cash, depending on the type of bank account the checks were drawn on. There were no checks-in-transit as of December 31, 2015 and 2014. Restricted Cash Restricted cash, as of December 31, 2015 and December 31, 2014, of $0.6 million and $1.7 million, respectively, was being held in escrow. The balance as of December 31, 2015 is relat ed to a vendor dispute, and remain ed in the escrow account until the dispute was resolved in March 2016 . Accounts Receivable, Net Our accounts receivable are primarily from purchasers of oil and natural gas and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted. At December 31, 2015 and December 31, 2014, we had an allowance for doubtful accounts receivable of $0.4 million and $0.2 million, respectively. Concentration of Credit Risk and Accounts Receivable Financial instruments that potentially subject us to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and derivative financial instruments. We place our cash with high credit quality financial institutions. We place our derivative financial instruments with financial institutions that participate in our credit facility and maintain an investment grade credit rating. Substantially all of our accounts receivables are due from purchasers of oil and natural gas. These sales are generally unsecured and, in some cases, may carry a parent guarantee. As we generally have fewer than 10 large customers for our oil and natural gas sales, we routinely assess the financial strength of our customers. Bad debt expense is recognized on an account-by-account review and when recovery is not probable. Our allowance for doubtful accounts was $0.4 million during 2015 and less than $0.2 million in 2014. We have no off-balance-sheet credit exposure related to our operations or customers. For the year ended December 31, 2015, three customers accounted for approximately 41% , 33% , and 18% of our sales revenues related to upstream activities, while one customer accounted for 100% of our midstream sales revenues. For the year ended December 31, 2014, five customers accounted for approximately 33% , 30% , 16% , 14% and 7% of our sales revenues. Derivatives and Hedging Activities We use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production by reducing our exposure to price fluctuations. Additionally, we use derivative financial instruments in the form of interest rate swaps to mitigate interest rate exposure on our borrowings under our credit facility. We account for all our open derivatives as mark-to-market activities. All derivative instruments are recorded in the consolidated balance sheets as either an asset or a liability measured at fair value with changes in fair value recognized in earnings. All of our open derivatives are effective as economic hedges of our commodity price or interest rate exposure. These contracts are accounted for using the mark-to-market accounting method. Using this method, the contracts are carried at their fair value on our consolidated balance sheets under the captions “Risk management assets” and “Risk management liabilities.” We recognize all unrealized and realized gains and losses related to these contracts on our consolidated statements of operations under the caption “Oil sales” or “Natural gas sales” and settled interest rate swaps as “Interest expense.” Revenue Recognition Sales are recognized when oil, natural gas and natural gas liquids have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Oil, natural gas and NGLs are generally sold on a monthly basis. Most of the contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a specific tank battery, gathering or transmission line, quality of oil, natural gas and NGLs, and prevailing supply and demand conditions, so that the price of the oil, natural gas and NGLs fluctuates to remain competitive with other available oil, natural gas and NGLs supplies. As a result, revenues from the sale of oil, natural gas and NGLs will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our oil, natural gas and NGLs contracts are customary in the industry. Gas imbalances occur when sales are more or less than the entitled ownership percentage of total gas production. We use the entitlements method when accounting for gas imbalances. Any amount received in excess is treated as a liability. If less than the entitled share of the production is received, the excess is recorded as a receivable. There was only a minimal gas imbalance position on one of our wells in the Mid-continent region at December 31, 2015 and 2014. Revenues relating to the gathering and transportation sales of oil and natural gas are recognized in the period service is provided. Under these arrangements, the Partnership receives a fee or fees for services provided. The revenue the Partnership recognizes from gathering and transportation services is generally directly related to the volume of oil and natural gas that flows through its systems. Income Taxes SPP and each of its wholly-owned subsidiary LLCs are treated as a partnership for federal and state income tax purposes. All of our taxable income or loss, which may differ considerably from net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our members. As such, no federal income tax for these entities has been provided for in the accompanying financial statements. SPP is subject to franchise tax obligations in Kansas and Texas and state tax obligations in Alabama and Oklahoma. SPP also has informational filing requirements in Georgia, Indiana, Louisiana, Maine, Missouri, New Jersey, New York, Oregon, Pennsylvania, and West Virginia because we have resident unitholders in these states. Our wholly-owned subsidiary, CEP Services Company, Inc. is a taxable entity. For the years ended December 31, 2015, and 2014, the current and deferred income taxes for the entity were immaterial. The entity has no material deferred tax assets or liabilities . Earnings per Unit For the period prior to our conversion, the basic net income (loss) per unit was computed from the two-class method by dividing net income (loss) attributable to unitholders by the weighted average number of units outstanding during each period. To determine net income (loss) allocated to each class of ownership (Class A and Class B), we first allocated net income (loss) in accordance with the amount of distributions made for the period by each class, if any. The remaining net income (loss) was allocated to each class in proportion to the class weighted average number of units outstanding for the period, as compared to the weighted average number of units for all classes for the period. Post conversion, net income (loss) per common unit for the period is based on any distributions that are made to the unitholders (common units) plus an allocation of undistributed net income (loss), divided by the weighted average number of common units outstanding. The two-class method dictates that net income (loss) for a period be reduced by the amount of distributions and that any residual amount representing undistributed net income (loss) be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income (loss). Unit-based awards granted but unvested are eligible to receive distributions. The underlying unvested restricted unit awards are considered participating securities for purposes of determining net income (loss) per unit. Undistributed income (loss) is allocated to participating securities based on the proportional relationship of the weighted average number of common units and unit-based awards outstanding. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units. Undistributed losses are not allocated to unvested restricted unit awards as they do not participate in net losses. Distributions declared and paid in the period are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings. Environmental Cost We record environmental liabilities at their undiscounted amounts on our balance sheets in other current and long-term liabilities when our environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the federal Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods. At December 31, 2015, we had no environmental liabilities recorded, as no liabilities were deemed necessary. Unit-Based Compensation We record compensation expense for all equity grants issued under our Long-Term Incentive Plan based on the fair value at the grant date, recognized over the vesting period. Other Contingencies We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. Funds spent to remedy these contingencies are charged against the associated reserve, if one exists, or expensed. When a range of probable loss can be estimated, we accrue the most likely amount or at least the minimum of the range of probable loss.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2015
Acquisitions [Abstract]
Acquisitions	3. ACQUISITIONS Eagle Ford Acquisition On March 31, 2015, we completed an acquisition of wellbore interests in certain producing oil and natural gas properties in Gonzales County, Texas (the “Eagle Ford properties,” and such acquisition, the “Eagle Ford acquisition”) located in the Eagle Ford Shale in Gonzales County, Texas from Sanchez Energy for a purchase price of $85 million, subject to normal and customary closing adjustments. The effective date of the transaction was January 1, 2015. The acquisition included initial conveyed working interests and net revenue interests for each property which escalate on January 1 for each year from 2016 through 2019, at which point, SPP’s interests in the Eagle Ford properties will stay constant for the remainder of the respective lives of the assets. The adjusted purchase price of $83.4 million was funded at closing with net proceeds from the private placement of 10,625,000 newly created Class A Preferred Units which were issued for a cash purchase price of $1.60 per unit (pre reverse unit split), resulting in gross proceeds to SPP of $17.0 million, the issuance of 1,052,632 common units (approximately 105 ,263 common units after adjusting for reverse unit split) to Sanchez Energy, borrowings under the Partnership’s Credit Agreement (as defined in Note 6, “Long-Term Debt”), and available cash. 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 developed reserves $ Facilities Fair value of hedges assumed Fair value of assets acquired Asset retirement obligations Ad valorem tax liability Fair value of net assets acquired $ Western Catarina Midstream Acquisition On October 14, 2015, we completed an acquisition of midstream assets located in Western Catarina, in the Eagle Ford Shale in South Texas from Sanchez Energy for a purchase price of $345.8 million, subject to normal and customary closing adjustments (the “Western Catarina Midstream acquisition”). The purchase price was funded at closing with net proceeds from the sale of Class B Preferred Units to Stonepeak Catarina Holdings LLC, an affiliate of Stonepeak Infrastructure Partners (“Stonepeak”) and available cash. Additionally, as a result of the Western Catarina Midstream acquisition, we repurchased 105,263 common units previously held by a subsidiary of Sanchez Energy. 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): Fixed assets $ Contractual customer relationships Purchase of SPP common units from Sanchez Energy Fair value of assets acquired $ Results of Operations and Pro Forma Information (Unaudited) The following unaudited pro forma combined financial information for the year ended December 31, 2015 and 2014 reflect the consolidated results of operations of the Partnership as if the Western Catarina Midstream and Eagle Ford acquisitions and related financings had occurred on January 1, 2014. The pro forma information includes adjustments primarily for revenues and expenses from the acquired properties, depreciation, depletion, amortization and accretion, interest expense and debt issuance cost amortization for acquisition debt, amortization of customer contract intangible assets acquired and paid-in-kind units issued in connection with the Class A Preferred Units. The unaudited pro forma combined financial statements give effect to the events set forth below: · The Western Catarina Midstream acquisition completed on October 14, 2015. · Issuance of Class B Preferred Units to finance the Western Catarina Midstream acquisition. · Repurchase of common units issued to finance a portion of the Eagle Ford acquisition as a part of the Western Catarina Midstream acquisition, and the related effect on net income (loss) per common unit. · The Eagle Ford acquisition completed on March 31, 2015. · The increase in borrowings under the Credit Agreement to finance a portion of the Eagle Ford acquisition, and the related adjustments to interest expense. · Issuance of Class A Preferred Units to finance a portion of the Eagle Ford acquisition, and the related adjustments to preferred paid-in-kind distributions. · Issuance of common units to finance a portion of the Eagle Ford acquisition and the related effect on net income (loss) per common unit (in thousands, except per unit amounts). Year Ended December 31, 2015 2014 Revenues $ $ Net income (loss) attributable to common unitholders $ $ Net income (loss) per unit prior to conversion Class A units - Basic and diluted $ $ Class B units - Basic and diluted $ $ Net income (loss) per unit after conversion Common units - 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 Partnership would have reported had the Western Catarina Midstream and Eagle Ford acquisitions and related financings been completed as of the date set forth in this unaudited pro forma combined financial information and should not be taken as indicative of the Partnership’s future combined results of operations. The actual results may differ significantly from that reflected in the unaudited pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the unaudited pro forma combined financial information and actual results. Post-Acquisition Operating Results The amounts of revenue and excess of revenues over direct operating expenses included in the Partnership’s condensed consolidated statements of operations for the year ended December 31, 2015, for the Eagle Ford acquisition are shown in the table that follows. Direct operating expenses include lease operating expenses and production and ad valorem taxes (in thousands): Year Ended December 31, 2015 Revenues $ Excess of revenues over direct operating expenses $

Fair Value Messurements

Fair Value Messurements	12 Months Ended
	Dec. 31, 2015
Fair Value Measurements [Abstract]
Fair Value Measurements	4. FAIR VALUE MEASUREMENTS 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 Partnership's oil and natural gas production are primarily industry standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, and (c) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Although third party quotes are utilized to assess the reasonableness of the prices and valuation techniques, there is not sufficient corroborating evidence to support classifying these assets and liabilities as Level 2. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement . Management's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 (in thousands): Fair Value Measurements at December 31, 2015 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Netting Cash and Fair Value at (Level 1) (Level 2) (Level 3) Collateral December 31, 2015 Derivative assets $ — $ $ — $ — $ Derivative liabilities — — — — — Embedded derivative — — Total net assets $ — $ $ $ — $ The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 (in thousands): Fair Value Measurements at December 31, 2014 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Netting Cash and Fair Value at (Level 1) (Level 2) (Level 3) Collateral December 31, 2014 Derivative assets $ — $ $ — $ $ Derivative liabilities — — — Total net assets $ — $ $ — $ — $ As of December 31, 2015 and December 31, 2014, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets and current liabilities approximated their carrying value due to their short-term nature. Fair Value on a Non-Recurring Basis The Partnership follows the provisions of Accounting Standards Codification (“ASC”) Topic 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Our purchase price allocation for the Eagle Ford and Western Catarina Midstream acquisitions are presented in Note 3, ‘‘Acquisitions and Divestitures.” Fair value of oil and natural gas properties are presented in Note 7, “Oil and Natural Gas Properties.” A reconciliation of the beginning and ending balances of the Partnership’s asset retirement obligations is presented in Note 9, ‘‘Asset Retirement Obligations.’’ Fair Value of Financial Instruments Fair value guidance requires certain fair value disclosures, such as those on our debt and derivatives, to be presented in both interim and annual reports. The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below. Credit Agreement – We believe that the carrying value of long-term debt for our Credit Agreement approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar terms. The debt is classified as a Level 2 input in the fair value hierarchy and represents the amount at which the instrument could be valued in an exchange during a current transaction between willing parties. Our Credit Agreement is discussed further in Note 6, “Long-Term Debt.” Derivative Instruments – The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value measurements of our derivative instruments classified as Level 2 inputs. Our commodity derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of oil and natural gas prices and an appropriate discount rate. Our interest rate derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of the LIBOR interest rates and an appropriate discount rate. We did not have any interest rate derivatives as of December 31, 2015. We prioritize the use of the highest level inputs available in determining fair value such that fair value measurements are determined using the highest and best use as determined by market participants and the assumptions that they would use in determining fair value. Embedded Derivative – The Partnership entered into a contract for the sale of preferred units in October 2015 which contained provisions that must be bifurcated from the contract and valued as a derivative. The embedded derivative is valued through the use of a Monte Carlo model which utilizes observable inputs, the Partnership’s unit prices a t various timelines, as well as unobservable inputs related to the weighted probabilities of certain redemption scenarios. We have therefore classified the fair value measurements of our embedded derivative as Level 3 inputs. The Partnership has marked this derivative to market as of December 31, 2015, and incurred approximately $10.0 million loss as a result. The fair value of the Partnership’s embedded derivative classified as Level 3 as of December 31, 2015 was $193.1 million. Changes in the unobservable inputs will impact the fair value measurement of the Partnership's embedded derivative contract. The following table sets forth a reconciliation of changes in the fair value of the Partnership's embedded derivative classified as Level 3 in the fair value hierarchy (in thousands): Significant Unobservable Inputs (Level 3) Year Ended December 31, 2015 2014 Beginning balance $ — $ — Initial fair value of embedded derivative - bifurcated from mezzanine equity — Total (losses) included in earnings — Ending balance $ $ — (Losses) included in earnings related to derivatives still held as of December 31, 2015, and 2014 $ $ —

Derivative And Financial Instru

Derivative And Financial Instruments	12 Months Ended
	Dec. 31, 2015
Derivative And Financial Instruments [Abstract]
Derivative And Financial Instruments	5. DERIVATIVE AND FINANCIAL INSTRUMENTS To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that fix or modify the future prices to be realized. These transactions are normally price swaps whereby we will receive a fixed price for our production and pay a variable market price to the contract counterparty. 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 our intention to enter into derivative contracts for speculative trading purposes. Under ASC Topic 815, “ Derivatives and Hedging ,” all derivative instruments are recorded on the consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We will net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met. We have not elected to designate any of our current derivative contracts as hedges; however, changes in the fair value of all of our derivative instruments are recognized in earnings and included as realized and unrealized gains (losses) on derivative instruments in the consolidated statements of operations. As of December 31, 2015, we had the following derivative contracts in place for the periods indicated, all of which are accounted for as mark-to-market activities: MTM Fixed Price Swaps – NYMEX (Henry Hub) For the Year Ended December 31, 2015 (in Bbls) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2016 $ $ $ $ $ 2017 $ $ $ $ $ 2018 $ $ $ $ $ 2019 $ $ $ $ $ MTM Fixed Price Basis Swaps – West Texas Intermediate (WTI) For the Year Ended December 31, 2015 (in Bbls) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2016 $ $ $ $ $ 2017 $ $ $ $ $ 2018 $ $ $ $ $ 2019 $ $ $ $ $ The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the year ended December 31, 2015 and the year ended December 31, 2014 (in thousands): December 31, 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 Ending fair value of commodity derivatives $ $ The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands): Amount of Gain in Income Location of Gain For the Year Ended December 31, Derivative Type in Income 2015 2014 Commodity – Mark-to-Market Oil sales $ $ Commodity – Mark-to-Market Natural gas sales - $ $ Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently contracted with four counterparties. We generally execute commodity derivative instruments under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. We include a measure of counterparty credit risk in our estimates of the fair values of derivative instruments. As of December 31, 2015 and December 31, 2014, the impact of non-performance credit risk on the valuation of our derivative instruments was not significant. Hedges Novated in the Eagle Ford Acquisition As a part of the Eagle Ford acquisition, we received by novation from the seller certain hedges covering approximately 95% , 90% , 85% , 85% and 80% of estimated 2015, 2016, 2017, 2018 and 2019 oil and natural gas production from the acquired assets, respectively. The counterparty for the hedges is a lender in the Partnership’s Credit Agreement. The Partnership is responsible for all future periodic settlements of these transactions. As of December 31, 2015, the fair value of the hedges assumed resulted in a $15 million asset in our consolidated balance sheet . Embedded Derivative The Partnership entered into a contract for the sale of preferred units in October 2015 which contained provisions that must be bifurcated from the contract and valued as a derivative. The embedded derivative is valued through the use of a Monte Carlo model which utilizes observable inputs, the Partnership’s unit prices at various timelines, as well as unobservable inputs related to the weighted probabilities of certain redemption scenarios. The Partnership has marked this derivative to market as of December 31, 2015, and incurred approximately $10.0 million loss as a result. The following table sets forth a reconciliation of the changes in fair value of the Partnership’s embedded derivative for the year ended December 31, 2015, and the year ended December 31, 2014 (in thousands): For the Year Ended December 31, 2015 2014 Beginning fair value of embedded derivative $ — $ — Initial fair value of embedded derivative - bifurcated from mezzanine equity — (Losses) on embedded derivative — Ending fair value of embedded derivative $ $ —

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2015
Long-Term Debt [Abstract]
Long-Term Debt	6. LONG-TERM DEBT Credit Agreement We have entered into a credit facility with Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto. The credit facility provides a maximum commitment of $500,000,000 and has a maturity date of March 31, 2020. Borrowings under the credit facility are secured by various mortgages of oil and natural gas properties that we own as well as various security and pledge agreements among the Partnership and certain of its subsidiaries and the administrative agent. The amount available for borrowing at any one time under the credit facility is limited to the borrowing base for our oil and natural gas properties and our midstream assets. Borrowings under the credit facility are available for direct investment in oil and gas properties, acquisitions, and working capital and general business purposes. The credit facility has a sub-limit of $15,000,000 which may be used for the issuance of letters of credit. The initial borrowing base under the credit facility was $200,000,000 . The borrowing base for the credit available for the upstream oil and gas properties is re-determined semi-annually in the second and fourth quarters of the year, and may be re-determined at our request more frequently and by the lenders, in their sole discretion, based on reserve reports as prepared by petroleum engineers, using, among other things, the oil and natural gas pricing prevailing at such time. The borrowing base for the credit available for our midstream properties is equal to the rolling four quarter EBITDA of our midstream operations multiplied by 5.0 initially, 4.75 for the second full quarter after the acquisition of the Catarina gathering system and 4.5 thereafter. Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral. We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months. Any increase in our borrowing base must be approved by all of the lenders. At our election, interest for borrowings under the credit facility are determined by reference to (i) the London interbank rate (“LIBOR”) plus an applicable margin between 1.75% and 2.75% per annum based on utilization or (ii) a domestic bank rate (“ABR”) plus an applicable margin between 0.75% and 1.75% per annum based on utilization plus (iii) a commitment fee between 0.375% and 0.500% per annum based on the unutilized borrowing base. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans are generally payable at the applicable maturity date. The credit facility contains various covenants that limit, among other things, our ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets, make certain loans, acquisitions, capital expenditures and investments, and pay distributions. In addition, we are required to maintain the following financial covenants: · current assets to current liabilities of at least 1.0 to 1.0 at all times; · senior secured net debt to consolidated adjusted EBITDA for the last twelve months, as of the last day of any fiscal quarter, of not greater than 4.5 to 1.0 if the adjusted EBITDA of our midstream operations equals or exceeds one-third of total Adjusted EBITDA or 4.0 to 1.0 if the adjusted EBITDA of our midstream operations is less than one-third of total adjusted EBITDA; and · minimum interest coverage ratio of at least 2.5 to 1.0 if the adjusted EBITDA of our midstream operations is greater than one-third of our total adjusted EBITDA. The credit facility also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, loan documents not being valid and a change in control. A change in control is generally defined as the occurrence of one of the following events: (i) our existing general partner ceases to be our sole general partner or (ii) certain specified persons shall cease to own more than 50% of the equity interests of our general partner or shall cease to control our general partner. If an event of default occurs, the lenders will be able to accelerate the maturity of the credit facility Agreement and exercise other rights and remedies. The credit facility limits our ability to pay distributions to unitholders. We have the ability to pay distributions to unitholders from available cash, including cash from borrowings under the credit facility, as long as no event of default exists and provided that no distributions to unitholders may be made if the borrowings outstanding, net of available cash, under the credit facility exceed 90% of the borrowing base, after giving effect to the proposed distribution. Our available cash is reduced by any cash reserves established by the board of directors of our general partner for the proper conduct of our business and the payment of fees and expenses. At December 31, 2015, we were in compliance with the financial covenants contained in the credit facility. We monitor compliance on an ongoing basis. If we are unable to remain in compliance with the financial covenants contained in our credit facility or maintain the required ratios discussed above, the lenders could call an event of default and accelerate the outstanding debt under the terms of the credit facility, such that our outstanding debt could become then due and payable. We may request waivers of compliance from the violated financial covenants from the lenders, but there is no assurance that such waivers would be granted. Debt Issuance Costs As of December 31, 2015, our unamortized debt issuance costs were $2 million. These costs are amortized to interest expense in our consolidated statement of operations over the life of our Credit Agreement. At December 31, 2014, our unamortized debt issuance costs were $0.7 million.

Oil And Natural Gas Properties

Oil And Natural Gas Properties	12 Months Ended
	Dec. 31, 2015
Oil And Natural Gas Properties [Abstract]
Oil And Natural Gas Properties	7. OIL AND NATURAL GAS PROPERTIES Oil and Natural Gas Properties We follow the successful efforts method of accounting for our oil and natural gas exploration, development and production activities. Leasehold acquisition costs, property acquisition and the costs of development of proved areas are capitalized. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred. Accounting rules require that we price our oil and natural gas proved reserves at the preceding twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Such SEC-required prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Our proved reserve estimates exclude the effect of any derivatives we have in place. Our estimate of proved reserves is based on the quantities of oil, natural gas and natural gas liquids that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Proved reserves are calculated based on various factors, including consideration of an independent reserve engineers’ report on proved reserves and an economic evaluation of all of our properties on a well-by-well basis. The process used to complete the estimates of proved reserves at December 31, 2015 and 2014 is described in detail in Note 1 6 . Reserves and their relation to estimated future net cash flows impact depletion and impairment calculations. As a result, adjustments to depletion and impairments are made concurrently with changes to reserve estimates. The accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. Proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered. Oil and natural gas properties consist of the following (in thousands): December 31, 2015 2014 Oil and natural gas properties and related equipment (successful efforts method) Property costs Proved property $ $ Unproved property Land Total property costs Materials and supplies Total Less: Accumulated depreciation, depletion, amortization and impairments Oil and natural gas properties and equipment, net $ $ Gathering and transportation assets consist of the following (in thousands): December 31, 2015 2014 Gathering and transportation assets Catarina midstream assets $ $ — Less: Accumulated depreciation, depletion, amortization — Total gathering and transportation assets $ $ — Depreciation, Depletion and Amortization . Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (including wells and related equipment and facilities) are amortized on the basis of proved developed reserves. It has been our historical practice to use our year-end reserve report to adjust our depreciation, depletion, and amortization expense for the fourth quarter. Depreciation, depletion, and amortization expense is calculated using year-end reserve reports based on the SEC-required price. As more fully described in Note 16, proved reserves estimates are subject to future revisions when additional information becomes available. All other properties, including the gathering and transportation assets, are stated at historical acquisition cost, net of any impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, and up to 36 years for gathering facilities. Depreciation, depletion, amortization and impairments consisted of the following (in thousands): Year Ended December 31, 2015 2014 DD&A of oil and natural gas-related assets $ $ DD&A of gathering and transportation related assets — Total DD&A Asset impairments Total $ $ Impairment of Oil and Natural Gas Properties and Other Non-Current Assets Oil and natural gas properties are reviewed for impairment on a field by field basis when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. The cash flow estimates are based upon third party reserve reports using future expected oil and natural gas prices adjusted for basis differentials. Other significant inputs, besides reserves, used to determine the fair values of proved properties include estimates of: (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Cash flow estimates for the impairment testing exclude derivative instruments. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the estimated economic chance of success and the length of time that we expect to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. The valuation allowances are reviewed at least annually. For the year ended December 31, 2015, we recorded non-cash charges of $123.9 million, to impair the value of our Cherokee Basin properties, Woodford Shale properties and our Texas and Louisiana properties acquired prior to the Eagle Ford acquisition. For the year ended December 31, 2014, we recorded non-cash impairment charge of $5.4 million to impair the value of our oil and natural gas fields in Texas and Louisiana . The carrying values of the impaired proved properties were reduced to fair value of $81 million, estimated using inputs characteristic of a Level 3 fair value measurement. Asset Retirement Obligation As described in Note 9, estimated asset retirement costs are recognized when the asset is acquired or placed in service, and are amortized over proved developed reserves using the units-of-production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates. Exploration and Dry Hole Costs Exploration and dry hole costs represent abandonments of drilling locations, dry hole costs, delay rentals, geological and geophysical costs and the impairment, amortization and abandonment associated with leases on our unproved properties. All such costs on oil and natural gas properties relating to unsuccessful exploratory wells are charged to expense as incurred. We recorded no exploration or dry hole costs for the years ended December 31, 2015 and 2014, however, we did record $1.9 million for impairments of unproved properties, which is classified as exploration costs on the statement of operations for the year ended December 31, 2015. Materials and Supplies Materials and supplies consist of well equipment, parts and supplies. They are valued at the lower of cost or market, using either the specific identification or first-in first-out method, depending on the inventory type. Materials and supplies are capitalized as used in the development or support of our oil and natural gas properties.

Provision For Income Taxes

Provision For Income Taxes	12 Months Ended
	Dec. 31, 2015
Provision For Income Taxes [Abstract]
Provision For Income Taxes	8. PROVISION FOR INCOME TAXES Publicly traded partnerships like ours are treated as corporations unless they have 90% or more in qualifying income (as that term is defined in the Internal Revenue Code). We satisfied this requirement in each of th e years ended December 31, 2015 and 2014 and , as a result, are not subject to federal income tax. However, our partners are individually responsible for paying federal income taxes on their share of our taxable income. Net earnings for financial reporting purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and financial reporting basis of certain assets and liabilities and other factors. We do not have access to information regarding each partner's individual tax basis in our limited partner interests. Provision for income taxes primarily reflects our state tax obligations under the Revised Texas Franchise Tax (the "Texas Margin Tax"). Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes. Our federal, state and foreign income tax provision (benefit) is summarized below (in thousands) : For the Year Ended December 31, 2015 2014 Current: Federal $ $ — State — Total current — Deferred: Federal — — State — — Total deferred — — Total provision for income taxes $ $ — A reconciliation of the provision for (benefit from) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows (in thousands): For the Year Ended December 31, 2015 2014 Pre-Tax Net Book Loss "NBI" $ $ — Texas Margin Tax (a) — Return to Accrual — Valuation Allowance — Provision for income taxes $ $ — Effective income tax rate % - % (a) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses. The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated (in thousands): For the Year Ended December 31, 2015 2014 Deferred tax assets (liabilities): Derivative assets $ $ — Depreciable, depletable property, plant and equipment — Deferred tax assets: — Valuation allowance — Total Deferred tax assets $ — $ — During November 2015, the FASB issued ASU 2015-17, “Balance Sheet Classification of Deferred Taxes”, which simplifies the presentation of deferred income taxes. This ASU requires that deferred tax assets and liabilities be classified as non-current in a statement of financial position by jurisdiction rather than separately presented as current and non-current portions. ASU 2015-17 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for financial statements as of the beginning of an interim or annual reporting period. The Partnership chose to adopt ASU 2015-17 as of the quarter ended December 31, 2015. As of December 31, 2015 and 2014, the Partnership had no material uncertain tax positions.

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation [Abstract]
Asset Retirement Obligation	9. ASSET RETIREMENT OBLIGATION We recognize the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred if a reasonable estimate of fair value can be made. Each period, we accrete the ARO to its then present value. The associated asset retirement cost (ARC) is capitalized as part of the carrying amount of our oil and natural gas properties, equipment and facilities. Subsequently, the ARC is depreciated using a systematic and rational method over the asset’s useful life. The AROs recorded by us relate to the plugging and abandonment of oil and natural gas wells, and decommissioning of oil and natural gas gathering and other facilities. Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions result in adjustments to the recorded fair value of the existing ARO, a corresponding adjustment is made to the ARC capitalized as part of the oil and natural gas property balance. The following table is a reconciliation of the ARO (in thousands): December 31, December 31, 2015 2014 Asset retirement obligation, beginning balance $ $ Liabilities added from acquisitions Liabilities added from drilling — Sold — Revisions to cost estimates Settlements Accretion expense Asset retirement obligation, ending balance $ $ Additional retirement obligations increase the liability associated with new oil and natural gas wells and other facilities as these obligations are incurred. Actual expenditures for abandonments of oil and natural gas wells and other facilities reduce the liability for asset retirement obligation. In 2015 and 2014, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing asset retirement obligations. During the year ended December 31, 2015, revisions were made to the ARO liability based on recent costs incurred on abandoned wells, which were lower on average than originally projected.

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies [Abstract]
Commitments And Contingencies	10. COMMITMENTS AND CONTINGENCIES We did not have any material commitments and contingencies as of December 31, 2015.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	11. RELATED PARTY TRANSACTIONS Sanchez-Related Agreements We are controlled by our general partner. The sole member of our general partner is Manager, which has no officers. In May 2014, we entered into the Services Agreement with Manager pursuant to which Manager provides services that we require to operate our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, professionals and acquisition, disposition and financing services. In connection with providing the services under the Services Agreement, Manager receives compensation as discussed above in “Item 13. Certain Relationships.” The Services Agreement has a ten -year term and will be automatically renewed for an additional ten years unless both Manager and the Company provide notice to terminate the agreement. During the year ended December 31, 2015, we paid approximately $9.9 million to Manager pursuant to the Services Agreement. During the year ended December 31, 2014, we paid $6.0 million to Manager under the Services Agreement and issued 5,956 common units to Manager pursuant to the Services Agreement in connection with Manager’s election to receive payment of its fee for the quarter ended September 30, 2014 in common units rather than cash, with such issuance being in lieu of paying a fee of $165,582 in cash, or $12.78 per common unit. Manager utilizes SOG to provide the services under the Services Agreement. In May 2014, we entered into a Contract Operating Agreement with SOG pursuant to which SOG either provides services to operate, develop and produce our oil and natural gas properties or engages a third-party operator to do so, other than with respect to our properties in the Mid-Continent Region. We also have entered into the Geophysical Seismic Data Use License Agreement with SOG pursuant to which SOG provides us a non-exclusive, royalty-free license to use seismic, geophysical and geological information relating to our oil and natural gas properties that is proprietary to SOG and not restricted by agreements that SOG has with landowners or seismic data vendors. In May 2014, we entered into the Transition Agreement with SOG and Manager pursuant to which we agreed to make available to Manager and SOG certain of our employees for SOG or Manager to provide services under the Services Agreement and Operating Agreement. No compensation was paid by any party for the provision or use of employees under the Transition Agreement. On May 8, 2014, the Company and SOG entered into a Contract Operating Agreement, the Company, Manager and SOG entered into a Transition Agreement, and the Company, SOG and certain subsidiaries of the Company entered into the License Agreement. For further discussion of these agreements, refer to our Annual Report on Form 10-K for the year ended December 31, 2014. In connection with the closing of the Western Catarina Midstream Divestiture, the Partnership entered into a Firm Gathering and Processing 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, LLC (“Catarina Midstream”). In addition, for the first five years of the Gathering Agreement, SN Catarina, LLC 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. As of December 31, 2015 and December 31, 2014, the Partnership had a net receivable from related parties of $1.5 million and $1.0 million, respectively, which are included in “Accounts receivable – related entities” in the condensed consolidated balance sheets. As of December 31, 2015, the Partnership also had a net payable from related parties of $1.0 million. The net receivables /payable as of December 31, 2015 and December 31, 2014 consist primarily of revenues receivable from oil and natural gas production, offset by costs associated with that production and obligations for general and administrative costs. Sanchez-Related Transactions We have entered into several transactions with Sanchez Energy since January 1, 2014. Antonio R. Sanchez, Jr. is a director and Executive Chairman of the Board of Sanchez Energy, and Antonio R. Sanchez, III, is a director and Chief Executive Office r of Sanchez Energy. In addition, Eduardo Sanchez is the President of Sanchez Energy. The employees of SOG, including Kirsten A. Hink, our Chief Accounting Officer, provide common services to both us and Sanchez Energy. On March 31, 2015, the Partnership and Sanchez Energy entered into a Purchase and Sale Agreement for the Eagle Ford acquisition for total consideration of $85.0 million. After $1.4 million in normal and customary closing adjustments, consideration paid at closing consisted of $81.6 million cash paid by us to Sanchez Energy and 105,263 of our common units issued to Sanchez Energy with an aggregate consideration value of $2,000,000 . In connection with the purchase agreement, we entered into a registration rights agreement with Sanchez Energy pursuant to which we granted certain registration rights related to the common unit consideration received. As of December 31, 2015, there were no common units held by Sanchez Energy or related subsidiaries thereof. All 105,263 common units issued as consideration for the Eagle Ford acquisition were repurchased in connection with the Western Catarina Midstream acquisition in October 2015. See further discussion of the transaction in Note 3, “Acquisitions.” In Octobe r 2015, the Partnership and Sanchez Energy consummated the Western Catarina Midstream acquisition for total consideration of approximately $345.8 million in cash, subject to closing and post-closing adjustments. Concurrently with the signing of the Western Catarina Midstream acquisition purchase and sale agreement, we entered into a 15 -year gas gathering and processing agreement with Sanchez Energy. For the year ended December 31, 2015, Sanchez Energy paid us approximately $7.5 million pursuant to the terms of the gathering and processing agreement. See further discussion of the transaction in Note 3, “Acquisitions.”

Unit-Based Compensation

Unit-Based Compensation	12 Months Ended
	Dec. 31, 2015
Unit-Based Compensation [Abstract]
Unit-Based Compensation	12. UNIT-BASED COMPENSATION Prior to our conversion to a Delaware limited partnership on March 6, 2015, we granted restricted common unit awards to certain employees in Texas under the 2009 Omnibus Incentive Compensation Plan (the “Omnibus Plan”). The Omnibus Plan provided for a variety of unit-based and performance-based awards, including unit options, restricted units, unit grants, notional units, unit appreciation rights, performance awards and other unit-based awards. Additionally, prior to March 6, 2015, we granted restricted common unit awards to certain field employees in Kansas and Oklahoma and to certain employees in Texas under our previous Long-Term Incentive Plan (the “Previous LTIP”). After the conversion to a limited partnership, both the Omnibus Plan and the Previous LTIP had no outstanding units remaining. Effective March 6, 2015, the Omnibus Plan was amended and restated and renamed the Sanchez Production Partners LP Long-Term Incentive Plan (the “LTIP”) and the Previous LTIP was merged into the LTIP. Restricted unit activity under the Omnibus Plan, the Previous LTIP, and the LTIP during the period, after adjusting for the reverse split, is presented in the following table: Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2013 $ Granted (1) Vested (1) Returned/Cancelled (1) Outstanding at December 31, 2014 Granted (1) Vested (1) Returned/Cancelled (1) Outstanding at December 31, 2015 $ (1) Values herein presented as if Omnibus Plan and Previous LTIP had merged as of the earliest date presented. During the year ended December 31, 2015, the Partnership issued 346,925 restricted common units ( 34,693 restricted common units after adjusting for reverse unit split) pursuant to the LTIP to the directors of the Partnership’s general partner that vested immediately on the date of the grant. The unit based compensation expense for the awards were based on their grant date fair values. In March 2015, officers were granted a total of 1,025,641 restricted common units ( 102,564 restricted common units after adjusting for the reverse unit split) that were due upon request, of which 769,231 restricted common units ( 76,923 restricted common units after adjusting for reverse unit split) were vested and delivered at the request of the officers, net of 322,692 restricted common units ( 32,269 restricted common units after adjusting for reverse unit split) that were returned to the plan for settlement of taxes associated with the vesting. Furthermore, on December 1, 2015 the board of directors approved the grant of 335,715 restricted units pursuant to the LTIP to employees, service providers, and executive officers which are set to vest pro-rata over a three -year period.

Distributions To Unitholders

Distributions To Unitholders	12 Months Ended
	Dec. 31, 2015
Distributions To Unitholders [Abstract]
Distributions To Unitholders	13. DISTRIBUTIONS TO UNITHOLDERS From the second quarter of 2009 through the second quarter of 2015, we did not pay distributions on our common units. Starting in the third quarter of 2015, the board of directors of our general partner declared distributions of Class A Preferred Units on August 10, 2015 and November 10, 2015 to holders as of August 14, 2015 and November 16, 2015, respectively. A total of 549,756 paid-in-kind units were distributed for the year ended December 31, 2015. On November 30, 2015, we paid a cash distribution with respect to the quarter ended September 30, 2015 in the amount of $0.400 per common unit. On February 9, 2016, we announced that the board of directors of our general partner approved a cash distribution of $0.406 per common unit for the fourth quarter of 2015. The Partnership also declared a fourth quarter 2015 paid-in-kind distribution of 2.5% on its Class A preferred units and a fourth quarter prorated cash distribution of $0.3815 on its Class B preferred units. The distributions were paid on February 29, 2016 to unitholders of record on February 19, 2016.

Members Equity Partners Capital

Members Equity Partners Capital	12 Months Ended
	Dec. 31, 2015
Members' Equity/Partners' Capital [Abstract]
Members' Equity/Partners' Capital	14. MEMBERS’ EQUITY/PARTNERS’ CAPITAL Outstanding Units As of December 31, 2015, we had 11,409,131 Class A Preferred Units outstanding, 19,444,445 Class B Preferred Units outstanding, and 3,240,812 common units outstanding, which included 25,641 unvested restricted common units issued under the LTIP. Conversion The board of managers of Sanchez Production Partners LLC (“SPP LLC”) approved a Plan of Conversion (the “Conversion”) providing for the conversion of the company from a limited liability company formed under the law s of the State of Delaware into a limited partnership formed under the laws of the State of Delaware. This plan was approved by the vote of the unitholders of SPP LLC on March 6, 2015. After the Conversion, all of the rights, privileges and obligations of the Company prior to the Conversion were transferred and are now held by the Partnership. The Conversion converted each outstanding common unit of the Company into one common unit of the Partnership. The outstanding Class A units of the Company were converted into common units of the Partnership in a number equal to 2% of the Partnership’s common units outstanding immediately after the Conversion (after taking into account the conversion of such Class A units), and the outstanding Class Z unit of the Company was cancelled. In addition, a non-economic general partner interest in the Partnership was issued to our general partner, and the incentive distribution rights of the Partnership were issued to Manager. Common Unit Issuances In April 2015, we entered into an at-the-market sales agreement with MLV & Co. LLC to sell from time to time up to $100 million of common units , with any proceeds from such sales to be used for general limited partnership purposes. As of December 31, 2015, we had sold 68,000 common units ( 6,800 common units after adjusting for reverse unit split) for total net proceeds of less than $0.2 million. During 2015 , we paid de minimis commissions to the sales agent in connection with the at-the-market facility. On August 3, 2015, the Partnership effected a 1 -for-10 reverse split on its common units, pursuant to which common unitholders received one common unit for every ten common units held at the close of trading on August 3, 2015. All fractional units created by the reverse split were rounded to the nearest whole unit. Each unitholder received at least one unit. Post-split units of the Partnership began trading on August 4, 2015. Immediately prior to the reverse unit split, there were 31,495,506 common units of the Partnership issued and outstanding, with a per unit closing trading price on the NYSE MKT on August 3, 2015 of $1.55 . Immediately after the reverse unit split, the number of issued and outstanding common units of the Partnership decreased to 3,149,551 , not inclusive of shares required by DTCC due to the rounding up of fractional shares at the beneficial level, and the per unit opening trading price on the NYSE MKT was $15.50 . Preferred Unit Issuance Class A Preferred Unit Offerings: On March 31, 2015, the Partnership entered into a Class A Preferred Unit Purchase Agreement (the “Preferred Unit Purchase Agreement”) with the purchasers named on Schedule A thereto (collectively, the “Purchasers”), pursuant to which the Partnership sold, and the Purchasers purchased, 10,625,000 of the Partnership’s newly created Class A Preferred Units (the “Class A Preferred Units”) in a privately negotiated transaction (the “Private Placement”) for an aggregate cash purchase price of $1.60 per Class A Preferred Unit resulting in gross proceeds to the Partnership of $17 million. The Partnership used the net proceeds of $ 17.0 from this transaction, together with common units issued to Sanchez Energy, borrowings under the Credit Agreement, and available cash on hand, to pay the consideration in the Eagle Ford acquisition. Additionally, on April 15, 2015, the Partnership entered into a Class A Preferred Unit Purchase Agreement (the “April Preferred Unit Purchase Agreement”) with the purchasers named on Schedule A thereto (collectively, the “April Purchasers”), pursuant to which the Partnership sold, and the April Purchasers purchased, 234,375 of the Partnership’s Class A Preferred Units in a privately negotiated transaction for an aggregate cash purchase price of $1.60 per Class A Preferred Unit resulting in gross and net proceeds to the Partnership of $375,000 . The Partnership used the proceeds for general working capital purposes. Commencing with the three months ended June 30, 2015 and through the date on which the Class A Preferred Units are converted into common units, the holders of the Class A Preferred Units shall be entitled to receive distributions. For the three months ended June 30, 2015, through and including the three months ending June 30, 2016, the distributions will be paid in kind with additional Class A Preferred Units; thereafter, distributions will be paid in-kind or in cash at the discretion of the board of directors of our general partner. For the first year after the issuance date, the distribution rate will be 10% per annum, or 2.5% per quarter; for the second year after the issuance date, the distribution rate will be 11.5% per annum, or 2.875% per quarter; and thereafter, the distribution rate will be 12.5% per annum, or 3.125% per quarter. Distributions will be made on or about the last day of each of February, May, August and November following the end of each quarter commencing with the three months ended June 30, 2015. On August 10, 2015, the board of directors of our general partner declared a distribution to holders of Class A Preferred Units as of August 14, 2015 to be paid in kind for the three months ended June 30, 2015. This distribution to the holders was made on August 31, 2015. Further, on November 10, 2015, the board of directors of our general partner declared a distribution to holders of Class A Preferred Units as of November 16, 2015 to be paid in kind and distributed to the holders on November 30, 2015. Class B Preferred Unit Offering: On October 14, 2015, pursuant to that certain Class B Preferred Unit Purchase Agreement dated September 25, 2015 (the “ Pr eferred Unit Purchase Agreement ”) between the Partnership and Stonepe ak Catarina Holdings LLC (the “Purchaser ”), the Partnership sold and the Purchaser purchased 19,444,445 of the Partnership’s newly created Class B Preferred Units (the “Class B Preferred Units ”) in a privatel y negotiated transaction (the “Private Placement ”) for an aggregate cash purchase price of $18.00 per Class B Preferred Unit , which resulted in gross proceeds to the Partnership of $350,000,010 . The Partnership used the net proceeds to pay a portion of the consideration under the Purchase Agreement, along with the payment to the Purchaser of a fee equal to 2.25% of the consideration paid for the Class B Preferred Units. Under the terms of the Amended Partnership Agreement, commencing with the quarter ended on December 31 , 2015, the Class B Preferred Units will receive a quarterly distribution of, at the election of the Board, of 10.0% per annum if paid in full in cash or 12.0% per annum if paid in part cash ( 8.0% per annum) and in part paid-in-kind units ( 4.0% per annum). In the event the Partnership does not raise at least $75,000,000 through the issuance of additional c ommon u nits prior to September 30, 2016 (with the conversion of the Class A Preferred Units of the Partnership counting toward such amount) or if any Class A Preferred Units remain outstanding after March 31, 2016, the cash portion of the distribution rate will increase by 4.0% per annum until consummation of such issuance or conversion, as applicable. Distributions are to be paid on or about the last day of each of February, May, August and November after the end of each quarter. The holders of Class B Preferred Units have the right at any time to request conversion in whole or in part of their Class B Preferred Units at the Conversion Rate, subject to the requirement to convert a minimum of $17,500,000 of Class B Preferred Units. The “Conversion Rate” is equal to the quotient of (i) the aggregate purchase price for the Class B Preferred Units plus accrued and unpaid distributions thereon, divided by (ii) the lesser of (a) the purchase price for the Class B Preferred Units and (b) the volume weighted average price for which c ommon u nits are issued by the Partnership during the period beginning on the p rivate p lacement closing date and ending on the date on wh ich the Partnership has issued c ommon u nits (other than issuances pursuant to the LTIP ) in exchange for cash in an aggregate amount equal to at least $75 million. The Class B Preferred Units are accounted for as mezzanine equity in the consolidated balance sheet consisting of the following (in thousands): For the Year Ended December 31, 2015 2014 Private placement of Class B Preferred Units $ $ — Less: discount — Less: amortization of discount — Less: distributions — Total mezzanine equity $ $ — Earnings per Unit For the period prior to our conversion, the basic net income (loss) per unit was computed from the two-class method by dividing net income (loss) attributable to unitholders by the weighted average number of units outstanding during each period. To determine net income (loss) allocated to each class of ownership (Class A and Class B), we first allocated net income (loss) in accordance with the amount of distributions made for the period by each class, if any. The remaining net income (loss) was allocated to each class in proportion to the class weighted average number of units outstanding for the period, as compared to the weighted average number of units for all classes for the period. Post conversion, net income (loss) per common unit for the period is based on any distributions that are made to the unitholders (common units) plus an allocation of undistributed net income (loss), divided by the weighted average number of common units outstanding. The two-class method dictates that net income (loss) for a period be reduced by the amount of distributions and that any residual amount representing undistributed net income (loss) be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income (loss). Unit-based awards granted but unvested are eligible to receive distributions. The underlying unvested restricted unit awards are considered participating securities for purposes of determining net income (loss) per unit. Undistributed income (loss) is allocated to participating securities based on the proportional relationship of the weighted average number of common units and unit-based awards outstanding. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units. Undistributed losses are not allocated to unvested restricted unit awards as they do not participate in net losses. Distributions declared and paid in the period are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings. Our general partner does not have an economic interest in the Partnership and, therefore, does not participate in the Partnership’s net income. The following table presents the weighted average basic and diluted units outstanding for the periods indicated: Year Ended January 1 - March 6 March 6 - December 31 December 31, 2015 2015 2014 Class A units - Basic — Class B Common units - Basic — Common units - Basic — — Weighted Common Units prior to reverse split - Basic Adjustment for reverse split Weighted Common Units after reverse split - Basic Class A units - Diluted — Class B Common units - Diluted — Common units - Diluted — — Weighted Common Units prior to reverse split - Diluted Adjustment for reverse split Weighted Common Units after reverse split - Diluted At December 31, 2015, we had 361,356 common units that were restricted unvested common units granted and outstanding. No losses were allocated to participating restricted unvested units because such securities do not have a contractual obligation to share in the Partnership’s losses. At December 31, 2014, we had 100,825 Class B common units that were restricted unvested common units granted and outstanding. These units were included in the diluted weighted average common units outstanding number since we recognized net income for the period. The following table presents our basic and diluted loss per unit for the period from January 1, 2015 to March 6, 2015 (the date of conversion to a limited partnership) (in thousands, except for per unit amounts): Total Class A Units Class B Units Assumed net loss to be allocated January 1 - March 6 $ $ $ Basic and diluted loss per unit prior to reverse split $ $ Basic and diluted loss per unit after reverse split $ $ The following table presents our basic and diluted loss per unit for the period from March 6, 2015 through December 31, 2015 (the period after conversion to a limited partnership) (in thousands, except for per unit amounts): Total Common Units Assumed net loss attributable to common unitholders to be allocated March 6 - December 31 $ $ Basic and diluted loss per unit prior to reverse split $ Basic and diluted loss per unit after reverse split $ Net loss per unit increased significantly for the period from March 6, 2015 through December 31, 2015 as compared to the period from January 1, 2015 through March 5, 2015 as it included non-cash impairment charges of $123.8 million. There was no impairment charge recorded for the period from January 1, 2015 through March 5, 2015. The following table presents our basic and diluted income per unit for the year end December 31, 2014 (in thousands, except for per unit amounts): Total Class A Units Class B Units Assumed net income to be allocated $ $ $ Basic and diluted income per unit prior to reverse split $ $ Basic and diluted income per unit after reverse split $ $

Reporting Segments

Reporting Segments	12 Months Ended
	Dec. 31, 2015
Reporting Segments [Abstract]
Reporting Segments	15. REPORTING SEGMENTS Exploration and Production and Midstream best define the operating segments of the businesses that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment. The Exploration and Production segment operates to explore for and produce crude oil and natural gas. The Midstream segment operates the gathering, processing and transportation of crude oil, NGLs and natural gas. These segments are broadly understood across the petroleum and petrochemical industries. These functions have been defined as the operating segments of the Partnership because they are the segments (1) that engage in business activities from which revenues are earned and expenses are incurred; (2) whose operating results are regularly reviewed by the Partnership’s chief operating decision maker to make decisions about resources to be allocated to the segment and to assess its performance; and (3) for which discrete financial information is available. Operating segments are evaluated for their contribution to the Partnership’s consolidated results based on operating income, which is defined as segment operating revenues less expenses. The following tables set forth our segment information for the periods indicated (in thousands): Year Ended December 31, 2015 Exploration & Production Midstream Total Operating revenues Natural gas sales $ $ — $ Oil sales — Natural gas liquids sales — Gathering and transportation sales — Total operating revenues Operating expenses: Lease operating expenses Transportation operating expenses — Cost of sales — Production taxes — General and administrative — Exploration costs — Gain on sale of assets — Depreciation, depletion and amortization Asset impairments — Accretion expense Total operating expenses Operating income (loss) $ $ $ Year Ended December 31, 2014 Exploration & Production Midstream Total Operating revenues Natural gas sales $ $ — $ Oil sales — Natural gas liquids sales — Gathering and transportation sales — — — Total operating revenues — Operating expenses: Lease operating expenses — Cost of sales — Production taxes — General and administrative — Loss on sale of assets — Depreciation, depletion and amortization — Asset impairments — Accretion expense — Total operating expenses — Operating income $ $ — $ The following table summarizes the total assets by operating segment for the years ended December 31, 2015 and 2014 (in thousands): December 31, Segment Assets 2015 2014 Exploration & Production $ $ Midstream — Total assets $ $ The following table summarizes the percentage of revenue earned from those customers in each segment that exceed 10% of the Partnership's consolidated segment's revenue for the each of the periods presented below: Year Ended December 31, 2015 2014 Exploration & Production Customer A % % Customer B Customer C Customer D All Others Total % % Midstream Customer E % — % Total % — %

Supplemental Information On Oil

Supplemental Information On Oil And Natural Gas Producing Activities	12 Months Ended
	Dec. 31, 2015
Supplemental Information On Oil And Natural Gas Producing Activities [Abstract]
Supplemental Information On Oil And Natural Gas Producing Activities	16. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED) The Supplementary Information on Oil and Natural Gas Producing Activities is presented as required by the appropriate authoritative guidance . The supplemental information includes capitalized costs related to oil and natural gas producing activities; costs incurred for the acquisition of oil and natural gas producing activities, exploration and development activities and the results of operations from oil and natural gas producing activities. Supplemental information is also provided for per unit production costs; oil and natural gas production and average sales prices; the estimated quantities of proved oil and natural gas reserves; the standardized measure of discounted future net cash flows associated with proved reserves and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved reserves. Costs The following table sets forth capitalized costs for the years ended December 31, 2015 and 2014 (in thousands): December 31, 2015 2014 Capitalized costs at the end of the period: ⁽ᵃ⁾ Oil and natural gas properties and related equipment (successful efforts method) Property costs Proved property $ $ Unproved property Land Total property costs Materials and supplies Total Less: Accumulated depreciation, depletion, amortization and impairments Oil and natural gas properties and equipment, net $ $ (a) Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. Unproved property costs include capitalized costs for oil and natural gas leaseholds where proved reserves do not exist. The following table sets forth costs incurred for oil and natural gas producing activities for the years ended December 31, 2015 and 2014 (in thousands): For the Year Ended December 31, 2015 2014 Costs incurred for the period: Acquisition of properties Proved $ $ Unproved — Development costs Oil and natural gas properties and equipment, net $ $ The development costs for the years ended December 31, 2015 and 2014 primarily represent costs to develop our proved undeveloped reserves. The properties acquired in 2015 and 2014 were in Texas and Louisiana. We had no exploration and dry hole costs in 2015 and 2014, with the exception of impairments related to unproved properties which were recorded as exploration costs. Results of Operations The revenues and expenses associated directly with oil and natural gas producing activities are reflected in the Consolidated Statements of Operations. All of our operations are oil and natural gas producing activities located in the United States. Net Proved Oil, Natural Gas and Natural Gas Liquids Reserves The following table sets forth information with respect to changes in proved developed and undeveloped reserves. This information excludes reserves related to royalty and net profit interests. All of our reserves are located in the United States. Natural Gas Total Oil Natural Gas Liquids (MMBoe) (in MMBoe) (in MMBoe) (in MMBoe) Net proved reserves December 31, 2013 Extensions and discoveries — Puchase of reserves in place — — Revisions of previous estimates Production December 31, 2014 Extensions and discoveries — — Puchase of reserves in place Revisions of previous estimates Production December 31, 2015 Proved developed reserves: December 31, 2014 December 31, 2015 Proved undeveloped reserves: December 31, 2014 — December 31, 2015 — Reserves and Related Estimates Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our December 31, 2015 and 2014, proved reserve estimates were 11.6 MMBoe and 16.6 MMBoe, respectively. For 2015, NSAI and Ryder Scott, independent petroleum engineering firms, prepared the estimates of our proved reserves which were used to prepare our financial statements. For 2014, NSAI prepared the estimates of our proved reserves which were used to prepare our financial statements. Our 2015 estimates of total proved reserves decreased 5.0 MMBoe from 2014 due to a 4.0 MMBoe decrease in undeveloped gas reserves. The lower volumes were due to a higher gas price. Our reserves are 66% natural gas and are sensitive to lower prices for natural gas and basis differentials in the Mid-Continent region. For the proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report: $50.28 per barrel for oil, $19.90 per barrel for NGLs and $2.58 per Mcf for natural gas. Proved developed producing reserves were lower due to natural production decline. Our 2014 estimates of total proved reserves increased 1.4 MMBoe from 2013 due to a 2.2 MMBoe increase in undeveloped gas reserves in the Cherokee Basin. The higher volumes were due to a higher gas price. Our reserves are 90% natural gas and are sensitive to lower prices for natural gas and basis differentials in the Mid-Continent region. For the proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report: $93.95 per barrel for oil, $35.11 per barrel for NGLs and $4.09 per Mcf for natural gas. Proved developed producing reserves were lower due to natural production decline. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas Reserves, Including a Reconciliation of Changes Therein The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved oil and natural gas reserves. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. Future cash inflows are calculated by applying the SEC-required prices of oil and natural gas relating to our proved reserves to the year-end quantities of those reserves. Future cash inflows exclude the impact of our hedging program. Future development and production costs represent the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. In addition, asset retirement obligations are included within future production and development costs. There are no future income tax expenses because the Partnership is a non-taxable entity. The assumptions used to compute estimated future cash inflows do not necessarily reflect expectations of actual revenues or costs or their present values. In addition, variations from expected production rates could result directly or indirectly from factors outside of our control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production; however, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized. The following table summarizes the standardized measure of estimated discounted future cash flows from the oil and natural gas properties (in thousands): For the Year Ended December 31, 2015 2014 Future cash inflows $ $ Future production costs Future estimated development costs Future net cash flows 10% annual discount for estimated timing of cash flows Standardized measure of discounted estimated future net cash flows related to proved gas reserves $ $ The following table summarizes the principal sources of change in the standardized measure of estimated discounted future net cash flows (in thousands): For the Year Ended December 31, 2015 2014 Beginning of the period $ $ Sales and transfers of oil and natural gas, net of production costs Net changes in prices and production costs related to future production Development costs incurred during the period Changes in extensions and discoveries Revisions of previous quantity estimates Purchases and sales of reserves in place Accretion discount Other Standardized measure of discounted future net cash flows related to proved gas reserves $ $

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	17. SUBSEQUENT EVENTS On February 9, 2016, the board of directors of the general partner of the Partnership declared a fourth quarter 2015 cash distribution on its common units of $0.4060 per unit ( $1.6240 per unit annualized) payable on February 29, 2016 to holders of record on February 19, 2016. The Partnership also declared a fourth quarter 2015 paid-in-kind distribution of 2.5% on its Class A preferred units and a fourth quarter prorated cash distribution of $0.3815 on its Class B preferred units, each payable on February 29, 2016 to holders of record on February 19, 2016.

Basis Of Presentation And Sum25

Basis Of Presentation And Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Basis Of Presentation And Summary Of Significant Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Accounting policies used by us conform to accounting principles generally accepted in the United States of America. The accompanying financial statements include the accounts of us and our wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. We conduct our business activities as two operating segments: the exploration and production of oil and natural gas and the midstream business, which include the Catarina gathering system. Our management evaluates performance based on these two business segments.
Recent Accounting Pronouncements	Recent Accounting Pronouncements From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our condensed consolidated financial statements upon adoption. In February 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018, with a modified retrospective approach to be used for implementation. ASU 2016-02 updates the previous lease guidance by requiring the recognition of a right-to-use asset and lease liability on the statement of financial position for those leases previously classified as operating leases under the old guidance. In addition, ASU 2016-02 updates the criteria for a lessee’s classification of a finance lease. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In November 2015, the FASB issued ASU 2015-17, “Balance Sheet Classification of Deferred Taxes”, which simplifies the presentation of deferred income taxes. This ASU requires that deferred tax assets and liabilities be classified as non-current in a statement of financial position by jurisdiction rather than separately presented as current and non-current portions. ASU 2015-17 is effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods. Early adoption is permitted for financial statements as of the beginning of an interim or annual reporting period. The Company chose to adopt ASU 2015-17 as of the quarter ended December 31, 2015 on a retrospective basis. Adoption of this guidance did not affect the balance sheet as of December 31, 2014. In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory,” effective for annual and interim periods beginning after December 15, 2016. ASU 2015-11 changes the inventory measurement principle for entities using the first-in, first out (FIFO) or average cost methods. For entities utilizing one of these methods, the inventory measurement principle will change from lower of cost or market to the lower of cost and net realizable value. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements, but do not expect the impact to be material. In April 2015, the FASB issued ASU No. 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 International Financial Reporting Standards. Under this new standard, debt issuance costs related to a recognized the 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 No. 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis” to improve consolidation guidance for certain types of legal entities. The guidance modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities (“VIEs”) or voting interest entities, eliminates the presumption that a general partner should consolidate a limited partnership, affects the consolidation analysis of reporting entities that are involved with VIEs, particularly those that have fee arrangements and related party relationships, and provides a scope exception from consolidation guidance for certain money market funds. These provisions are effective for annual reporting periods beginning after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. These provisions may also be adopted using either a full retrospective or a modified retrospective approach. We are currently assessing the impact that adopting this new accounting guidance will have on our consolidated financial statements and footnote disclosures, but we 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. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows .
Reclassifications	Reclassifications Certain reclassifications have been made to the prior period to conform to the current period presentation. These reclassifications had no effect on total unitholders’ equity, net income or net cash provided by or used in operating, investing or financing activities and an immaterial effect on total assets and total liabilities.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying footnotes. These estimates and the underlying assumptions affect the amounts of assets and liabilities reported, disclosures about contingent assets and liabilities and reported amounts of revenues and expenses. The estimates that are particularly significant to our financial statements include estimates of our reserves of oil, natural gas and natural gas liquids (“NGLs”); future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of commodity derivatives and fair values of assets and liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best estimates and judgment. Management evaluates its estimates and assumptions on an on-going basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from the estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
Cash and Cash Equivalents	Cash and Cash Equivalents All highly liquid investments with original maturities of three months or less are considered cash equivalents. Checks-in-transit are included in accounts payable or as a reduction of cash, depending on the type of bank account the checks were drawn on. There were no checks-in-transit as of December 31, 2015 and 2014.
Restricted Cash	Restricted Cash Restricted cash, as of December 31, 2015 and December 31, 2014, of $0.6 million and $1.7 million, respectively, was being held in escrow. The balance as of December 31, 2015 is relat ed to a vendor dispute, and remain ed in the escrow account until the dispute was resolved in March 2016 .
Accounts Receivable, Net	Accounts Receivable, Net Our accounts receivable are primarily from purchasers of oil and natural gas and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted. At December 31, 2015 and December 31, 2014, we had an allowance for doubtful accounts receivable of $0.4 million and $0.2 million, respectively.
Concentration of Credit Risk and Accounts Receivable	Concentration of Credit Risk and Accounts Receivable Financial instruments that potentially subject us to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and derivative financial instruments. We place our cash with high credit quality financial institutions. We place our derivative financial instruments with financial institutions that participate in our credit facility and maintain an investment grade credit rating. Substantially all of our accounts receivables are due from purchasers of oil and natural gas. These sales are generally unsecured and, in some cases, may carry a parent guarantee. As we generally have fewer than 10 large customers for our oil and natural gas sales, we routinely assess the financial strength of our customers. Bad debt expense is recognized on an account-by-account review and when recovery is not probable. Our allowance for doubtful accounts was $0.4 million during 2015 and less than $0.2 million in 2014. We have no off-balance-sheet credit exposure related to our operations or customers. For the year ended December 31, 2015, three customers accounted for approximately 41% , 33% , and 18% of our sales revenues related to upstream activities, while one customer accounted for 100% of our midstream sales revenues. For the year ended December 31, 2014, five customers accounted for approximately 33% , 30% , 16% , 14% and 7% of our sales revenues.
Derivatives and Hedging Activities	Derivatives and Hedging Activities We use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production by reducing our exposure to price fluctuations. Additionally, we use derivative financial instruments in the form of interest rate swaps to mitigate interest rate exposure on our borrowings under our credit facility. We account for all our open derivatives as mark-to-market activities. All derivative instruments are recorded in the consolidated balance sheets as either an asset or a liability measured at fair value with changes in fair value recognized in earnings. All of our open derivatives are effective as economic hedges of our commodity price or interest rate exposure. These contracts are accounted for using the mark-to-market accounting method. Using this method, the contracts are carried at their fair value on our consolidated balance sheets under the captions “Risk management assets” and “Risk management liabilities.” We recognize all unrealized and realized gains and losses related to these contracts on our consolidated statements of operations under the caption “Oil sales” or “Natural gas sales” and settled interest rate swaps as “Interest expense.”
Revenue Recognition	Revenue Recognition Sales are recognized when oil, natural gas and natural gas liquids have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Oil, natural gas and NGLs are generally sold on a monthly basis. Most of the contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a specific tank battery, gathering or transmission line, quality of oil, natural gas and NGLs, and prevailing supply and demand conditions, so that the price of the oil, natural gas and NGLs fluctuates to remain competitive with other available oil, natural gas and NGLs supplies. As a result, revenues from the sale of oil, natural gas and NGLs will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our oil, natural gas and NGLs contracts are customary in the industry. Gas imbalances occur when sales are more or less than the entitled ownership percentage of total gas production. We use the entitlements method when accounting for gas imbalances. Any amount received in excess is treated as a liability. If less than the entitled share of the production is received, the excess is recorded as a receivable. There was only a minimal gas imbalance position on one of our wells in the Mid-continent region at December 31, 2015 and 2014. Revenues relating to the gathering and transportation sales of oil and natural gas are recognized in the period service is provided. Under these arrangements, the Partnership receives a fee or fees for services provided. The revenue the Partnership recognizes from gathering and transportation services is generally directly related to the volume of oil and natural gas that flows through its systems.
Income Taxes	Income Taxes SPP and each of its wholly-owned subsidiary LLCs are treated as a partnership for federal and state income tax purposes. All of our taxable income or loss, which may differ considerably from net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our members. As such, no federal income tax for these entities has been provided for in the accompanying financial statements. SPP is subject to franchise tax obligations in Kansas and Texas and state tax obligations in Alabama and Oklahoma. SPP also has informational filing requirements in Georgia, Indiana, Louisiana, Maine, Missouri, New Jersey, New York, Oregon, Pennsylvania, and West Virginia because we have resident unitholders in these states. Our wholly-owned subsidiary, CEP Services Company, Inc. is a taxable entity. For the years ended December 31, 2015, and 2014, the current and deferred income taxes for the entity were immaterial. The entity has no material deferred tax assets or liabilities .
Earnings per Unit	Earnings per Unit For the period prior to our conversion, the basic net income (loss) per unit was computed from the two-class method by dividing net income (loss) attributable to unitholders by the weighted average number of units outstanding during each period. To determine net income (loss) allocated to each class of ownership (Class A and Class B), we first allocated net income (loss) in accordance with the amount of distributions made for the period by each class, if any. The remaining net income (loss) was allocated to each class in proportion to the class weighted average number of units outstanding for the period, as compared to the weighted average number of units for all classes for the period. Post conversion, net income (loss) per common unit for the period is based on any distributions that are made to the unitholders (common units) plus an allocation of undistributed net income (loss), divided by the weighted average number of common units outstanding. The two-class method dictates that net income (loss) for a period be reduced by the amount of distributions and that any residual amount representing undistributed net income (loss) be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income (loss). Unit-based awards granted but unvested are eligible to receive distributions. The underlying unvested restricted unit awards are considered participating securities for purposes of determining net income (loss) per unit. Undistributed income (loss) is allocated to participating securities based on the proportional relationship of the weighted average number of common units and unit-based awards outstanding. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units. Undistributed losses are not allocated to unvested restricted unit awards as they do not participate in net losses. Distributions declared and paid in the period are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings.
Environmental Cost	Environmental Cost We record environmental liabilities at their undiscounted amounts on our balance sheets in other current and long-term liabilities when our environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the federal Environmental Protection Agency (EPA) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods. At December 31, 2015, we had no environmental liabilities recorded, as no liabilities were deemed necessary.
Unit-Based Compensation	Unit-Based Compensation We record compensation expense for all equity grants issued under our Long-Term Incentive Plan based on the fair value at the grant date, recognized over the vesting period.
Other Contingencies	Other Contingencies We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. Funds spent to remedy these contingencies are charged against the associated reserve, if one exists, or expensed. When a range of probable loss can be estimated, we accrue the most likely amount or at least the minimum of the range of probable loss.

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2015
Business Acquisition [Line Items]
Supplemental Pro Forma Information	· Issuance of common units to finance a portion of the Eagle Ford acquisition and the related effect on net income (loss) per common unit (in thousands, except per unit amounts). Year Ended December 31, 2015 2014 Revenues $ $ Net income (loss) attributable to common unitholders $ $ Net income (loss) per unit prior to conversion Class A units - Basic and diluted $ $ Class B units - Basic and diluted $ $ Net income (loss) per unit after conversion Common units - Basic and diluted $ $ —
Post-Acquisition Operating Results	The amounts of revenue and excess of revenues over direct operating expenses included in the Partnership’s condensed consolidated statements of operations for the year ended December 31, 2015, for the Eagle Ford acquisition are shown in the table that follows. Direct operating expenses include lease operating expenses and production and ad valorem taxes (in thousands): Year Ended December 31, 2015 Revenues $ Excess of revenues over direct operating expenses $
Eagle Ford [Member]
Business Acquisition [Line Items]
Estimated Values Of Assets Acquired And Liabilities Assumed	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 developed reserves $ Facilities Fair value of hedges assumed Fair value of assets acquired Asset retirement obligations Ad valorem tax liability Fair value of net assets acquired $
Western Catarina Midstream [Member]
Business Acquisition [Line Items]
Estimated Values Of Assets Acquired And Liabilities Assumed	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): Fixed assets $ Contractual customer relationships Purchase of SPP common units from Sanchez Energy Fair value of assets acquired $

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Measurements [Abstract]
Fair Value Of Assets And Liabilities On A Recurring Basis	The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2015 (in thousands): Fair Value Measurements at December 31, 2015 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Netting Cash and Fair Value at (Level 1) (Level 2) (Level 3) Collateral December 31, 2015 Derivative assets $ — $ $ — $ — $ Derivative liabilities — — — — — Embedded derivative — — Total net assets $ — $ $ $ — $ The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 (in thousands): Fair Value Measurements at December 31, 2014 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Netting Cash and Fair Value at (Level 1) (Level 2) (Level 3) Collateral December 31, 2014 Derivative assets $ — $ $ — $ $ Derivative liabilities — — — Total net assets $ — $ $ — $ — $
Reconciliation Of Changes In Fair Value Of Embedded Derivative Classified As Level 3	The following table sets forth a reconciliation of changes in the fair value of the Partnership's embedded derivative classified as Level 3 in the fair value hierarchy (in thousands): Significant Unobservable Inputs (Level 3) Year Ended December 31, 2015 2014 Beginning balance $ — $ — Initial fair value of embedded derivative - bifurcated from mezzanine equity — Total (losses) included in earnings — Ending balance $ $ — (Losses) included in earnings related to derivatives still held as of December 31, 2015, and 2014 $ $ —

Derivative And Financial Inst28

Derivative And Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative And Financial Instruments [Abstract]
Summary Of Derivative Contracts In Place	MTM Fixed Price Swaps – NYMEX (Henry Hub) For the Year Ended December 31, 2015 (in Bbls) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2016 $ $ $ $ $ 2017 $ $ $ $ $ 2018 $ $ $ $ $ 2019 $ $ $ $ $ MTM Fixed Price Basis Swaps – West Texas Intermediate (WTI) For the Year Ended December 31, 2015 (in Bbls) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2016 $ $ $ $ $ 2017 $ $ $ $ $ 2018 $ $ $ $ $ 2019 $ $ $ $ $
Fair Value for Risk Management Assets and Liabilities	The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the year ended December 31, 2015 and the year ended December 31, 2014 (in thousands): December 31, 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 Ending fair value of commodity derivatives $ $
Schedule Of Effect Of Derivative Instruments On Consolidated Statements Of Operations	The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands): Amount of Gain in Income Location of Gain For the Year Ended December 31, Derivative Type in Income 2015 2014 Commodity – Mark-to-Market Oil sales $ $ Commodity – Mark-to-Market Natural gas sales - $ $
Reconciliation Of Changes In Fair Value Of Embedded Derivative	The following table sets forth a reconciliation of the changes in fair value of the Partnership’s embedded derivative for the year ended December 31, 2015, and the year ended December 31, 2014 (in thousands): For the Year Ended December 31, 2015 2014 Beginning fair value of embedded derivative $ — $ — Initial fair value of embedded derivative - bifurcated from mezzanine equity — (Losses) on embedded derivative — Ending fair value of embedded derivative $ $ —

Oil And Natural Gas Properties

Oil And Natural Gas Properties (Tables)	12 Months Ended
	Dec. 31, 2015
Oil And Natural Gas Properties [Abstract]
Oil and Natural Gas Properties	Oil and natural gas properties consist of the following (in thousands): December 31, 2015 2014 Oil and natural gas properties and related equipment (successful efforts method) Property costs Proved property $ $ Unproved property Land Total property costs Materials and supplies Total Less: Accumulated depreciation, depletion, amortization and impairments Oil and natural gas properties and equipment, net $ $
Gathering and Transportation Assets	Gathering and transportation assets consist of the following (in thousands): December 31, 2015 2014 Gathering and transportation assets Catarina midstream assets $ $ — Less: Accumulated depreciation, depletion, amortization — Total gathering and transportation assets $ $ —
Depreciation, Depletion, Amortization and Impairments	Depreciation, depletion, amortization and impairments consisted of the following (in thousands): Year Ended December 31, 2015 2014 DD&A of oil and natural gas-related assets $ $ DD&A of gathering and transportation related assets — Total DD&A Asset impairments Total $ $

Provision For Income Taxes (Tab

Provision For Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Provision For Income Taxes [Abstract]
Summary of Federal, State and Foreign Income Tax Provision (Benefit)	Our federal, state and foreign income tax provision (benefit) is summarized below (in thousands) : For the Year Ended December 31, 2015 2014 Current: Federal $ $ — State — Total current — Deferred: Federal — — State — — Total deferred — — Total provision for income taxes $ $ —
Reconciliation of Provision for (Benefit from) Income Taxes	A reconciliation of the provision for (benefit from) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows (in thousands): For the Year Ended December 31, 2015 2014 Pre-Tax Net Book Loss "NBI" $ $ — Texas Margin Tax (a) — Return to Accrual — Valuation Allowance — Provision for income taxes $ $ — Effective income tax rate % - % (a) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.
Significant Components of Deferred Tax Assets and Deferred Tax Liabilities	The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated (in thousands): For the Year Ended December 31, 2015 2014 Deferred tax assets (liabilities): Derivative assets $ $ — Depreciable, depletable property, plant and equipment — Deferred tax assets: — Valuation allowance — Total Deferred tax assets $ — $ —

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation [Abstract]
Reconciliation of Asset Retirement Obligation	The following table is a reconciliation of the ARO (in thousands): December 31, December 31, 2015 2014 Asset retirement obligation, beginning balance $ $ Liabilities added from acquisitions Liabilities added from drilling — Sold — Revisions to cost estimates Settlements Accretion expense Asset retirement obligation, ending balance $ $

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Unit-Based Compensation [Abstract]
Schedule Of Units Activity	Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2013 $ Granted (1) Vested (1) Returned/Cancelled (1) Outstanding at December 31, 2014 Granted (1) Vested (1) Returned/Cancelled (1) Outstanding at December 31, 2015 $ (1) Values herein presented as if Omnibus Plan and Previous LTIP had merged as of the earliest date presented.

Members Equity Partners Capit33

Members Equity Partners Capital (Tables)	12 Months Ended
	Dec. 31, 2015
Members' Equity/Partners' Capital [Abstract]
Class B Preferred Units Accounted for as Mezzanine Equity in the Consolidated Balance Sheet	The Class B Preferred Units are accounted for as mezzanine equity in the consolidated balance sheet consisting of the following (in thousands): For the Year Ended December 31, 2015 2014 Private placement of Class B Preferred Units $ $ — Less: discount — Less: amortization of discount — Less: distributions — Total mezzanine equity $ $ —
Schedule of Weighted Average Basic and Diluted Units Outstanding	Year Ended January 1 - March 6 March 6 - December 31 December 31, 2015 2015 2014 Class A units - Basic — Class B Common units - Basic — Common units - Basic — — Weighted Common Units prior to reverse split - Basic Adjustment for reverse split Weighted Common Units after reverse split - Basic Class A units - Diluted — Class B Common units - Diluted — Common units - Diluted — — Weighted Common Units prior to reverse split - Diluted Adjustment for reverse split Weighted Common Units after reverse split - Diluted
Schedule of Basic and Diluted Loss per Unit	The following table presents our basic and diluted loss per unit for the period from January 1, 2015 to March 6, 2015 (the date of conversion to a limited partnership) (in thousands, except for per unit amounts): Total Class A Units Class B Units Assumed net loss to be allocated January 1 - March 6 $ $ $ Basic and diluted loss per unit prior to reverse split $ $ Basic and diluted loss per unit after reverse split $ $ The following table presents our basic and diluted loss per unit for the period from March 6, 2015 through December 31, 2015 (the period after conversion to a limited partnership) (in thousands, except for per unit amounts): Total Common Units Assumed net loss attributable to common unitholders to be allocated March 6 - December 31 $ $ Basic and diluted loss per unit prior to reverse split $ Basic and diluted loss per unit after reverse split $ Net loss per unit increased significantly for the period from March 6, 2015 through December 31, 2015 as compared to the period from January 1, 2015 through March 5, 2015 as it included non-cash impairment charges of $123.8 million. There was no impairment charge recorded for the period from January 1, 2015 through March 5, 2015. The following table presents our basic and diluted income per unit for the year end December 31, 2014 (in thousands, except for per unit amounts): Total Class A Units Class B Units Assumed net income to be allocated $ $ $ Basic and diluted income per unit prior to reverse split $ $ Basic and diluted income per unit after reverse split $ $

Reporting Segments (Tables)

Reporting Segments (Tables)	12 Months Ended
	Dec. 31, 2015
Reporting Segments [Abstract]
Schedule of Segment Information	The following tables set forth our segment information for the periods indicated (in thousands): Year Ended December 31, 2015 Exploration & Production Midstream Total Operating revenues Natural gas sales $ $ — $ Oil sales — Natural gas liquids sales — Gathering and transportation sales — Total operating revenues Operating expenses: Lease operating expenses Transportation operating expenses — Cost of sales — Production taxes — General and administrative — Exploration costs — Gain on sale of assets — Depreciation, depletion and amortization Asset impairments — Accretion expense Total operating expenses Operating income (loss) $ $ $ Year Ended December 31, 2014 Exploration & Production Midstream Total Operating revenues Natural gas sales $ $ — $ Oil sales — Natural gas liquids sales — Gathering and transportation sales — — — Total operating revenues — Operating expenses: Lease operating expenses — Cost of sales — Production taxes — General and administrative — Loss on sale of assets — Depreciation, depletion and amortization — Asset impairments — Accretion expense — Total operating expenses — Operating income $ $ — $
Summary of Total Assets by Segment	The following table summarizes the total assets by operating segment for the years ended December 31, 2015 and 2014 (in thousands): December 31, Segment Assets 2015 2014 Exploration & Production $ $ Midstream — Total assets $ $
Summary of Percentage of Revenue Earned from Customers by Segment	Year Ended December 31, 2015 2014 Exploration & Production Customer A % % Customer B Customer C Customer D All Others Total % % Midstream Customer E % — % Total % — %

Supplemental Information On O35

Supplemental Information On Oil And Natural Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Information On Oil And Natural Gas Producing Activities [Abstract]
Schedule Of Capitalized Costs	The following table sets forth capitalized costs for the years ended December 31, 2015 and 2014 (in thousands): December 31, 2015 2014 Capitalized costs at the end of the period: ⁽ᵃ⁾ Oil and natural gas properties and related equipment (successful efforts method) Property costs Proved property $ $ Unproved property Land Total property costs Materials and supplies Total Less: Accumulated depreciation, depletion, amortization and impairments Oil and natural gas properties and equipment, net $ $ (a) Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. Unproved property costs include capitalized costs for oil and natural gas leaseholds where proved reserves do not exist.
Schedule Of Costs Incurred For Oil And Natural Gas Producing Activities	The following table sets forth costs incurred for oil and natural gas producing activities for the years ended December 31, 2015 and 2014 (in thousands): For the Year Ended December 31, 2015 2014 Costs incurred for the period: Acquisition of properties Proved $ $ Unproved — Development costs Oil and natural gas properties and equipment, net $ $
Schedule Of Changes In Proved Developed And Undeveloped Reserves	Natural Gas Total Oil Natural Gas Liquids (MMBoe) (in MMBoe) (in MMBoe) (in MMBoe) Net proved reserves December 31, 2013 Extensions and discoveries — Puchase of reserves in place — — Revisions of previous estimates Production December 31, 2014 Extensions and discoveries — — Puchase of reserves in place Revisions of previous estimates Production December 31, 2015 Proved developed reserves: December 31, 2014 December 31, 2015 Proved undeveloped reserves: December 31, 2014 — December 31, 2015 —
Summary Of Standardized Measure Of Estimated Discounted Future Cash Flows From Properties	The following table summarizes the standardized measure of estimated discounted future cash flows from the oil and natural gas properties (in thousands): For the Year Ended December 31, 2015 2014 Future cash inflows $ $ Future production costs Future estimated development costs Future net cash flows 10% annual discount for estimated timing of cash flows Standardized measure of discounted estimated future net cash flows related to proved gas reserves $ $
Summary Of Change In Standardized Measure Of Estimated Discounted Future Net Cash Flows	The following table summarizes the principal sources of change in the standardized measure of estimated discounted future net cash flows (in thousands): For the Year Ended December 31, 2015 2014 Beginning of the period $ $ Sales and transfers of oil and natural gas, net of production costs Net changes in prices and production costs related to future production Development costs incurred during the period Changes in extensions and discoveries Revisions of previous quantity estimates Purchases and sales of reserves in place Accretion discount Other Standardized measure of discounted future net cash flows related to proved gas reserves $ $

Organization And Business (Deta

Organization And Business (Details)	12 Months Ended
	Dec. 31, 2015
Sanchez Energy Corporation [Member]
Gathering and processing agreement term	15 years

Basis Of Presentation And Sum37

Basis Of Presentation And Summary Of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2015USD ($)segmentcustomershares	Dec. 31, 2014USD ($)customershares
Number of operating segments | segment	2
Restricted unvested common units granted and outstanding | shares	361,356
Restricted cash held in escrow	$ 600,000	$ 1,700,000
Restricted cash	600,000	1,748,000
Allowance for doubtful accounts	$ 400,000	$ 200,000
Number of large customers | customer	3	5
Environmental liabilities	$ 0
Oil [Member]
Trade accounts receivable, general collection period after month end	30 days
Natural Gas [Member]
Trade accounts receivable, general collection period after month end	60 days
Minimum [Member] | Furniture and Equipment [Member]
Useful life	3 years
Maximum [Member]
Allowance for doubtful accounts		$ 200,000
Number of large customers | customer	10
Maximum [Member] | Furniture and Equipment [Member]
Useful life	15 years
Maximum [Member] | Gathering Facilities [Member]
Useful life	36 years
Sales [Member] | Customer One [Member]
Percentage of sales revenue	41.00%	33.00%
Sales [Member] | Customer Two [Member]
Percentage of sales revenue	33.00%	30.00%
Sales [Member] | Customer Three [Member]
Percentage of sales revenue	18.00%	16.00%
Sales [Member] | Customer Four [Member]
Percentage of sales revenue		14.00%
Sales [Member] | Customer Five [Member]
Percentage of sales revenue		7.00%
Class B Unit [Member]
Restricted unvested common units granted and outstanding | shares		100,825
Midstream [Member] | Sales [Member]
Number of large customers | customer	1
Percentage of sales revenue	100.00%

Acquisitions (Details)

Acquisitions (Details) - USD ($)	Oct. 14, 2015	Apr. 15, 2015	Mar. 31, 2015	Dec. 31, 2015
Business Acquisition [Line Items]
Proceeds from preferred units sold				$ 359,500,000
Eagle Ford [Member]
Business Acquisition [Line Items]
Initial purchase price			$ 85,000,000
Cash payment for acquisition			83,400,000
Purchase price			$ 84,299,000
Western Catarina Midstream [Member]
Business Acquisition [Line Items]
Cash payment for acquisition	$ 345,800,000
Repurchase of units (in units)	105,263
Purchase price	$ 345,840,000
Class A Preferred [Member]
Business Acquisition [Line Items]
Price per unit sold		$ 1.60	$ 1.60
Proceeds from preferred units sold		$ 375,000	$ 17,000,000
Class A Preferred [Member] | Eagle Ford [Member]
Business Acquisition [Line Items]
Shares issued			10,625,000
Price per unit sold			$ 1.60
Proceeds from preferred units sold			$ 17,000,000
Common Units [Member] | Eagle Ford [Member]
Business Acquisition [Line Items]
Shares issued			105,263
Prior To Stock Split [Member] | Common Units [Member] | Eagle Ford [Member]
Business Acquisition [Line Items]
Shares issued			1,052,632

Acquisitions (Value Net Assets

Acquisitions (Value Net Assets Acquired) (Details) - USD ($) $ in Thousands	Oct. 14, 2015	Mar. 31, 2015
Eagle Ford [Member]
Business Acquisition [Line Items]
Proved developed reserves		$ 72,889
Facilities		8,002
Fair value of hedges assumed		3,408
Fair value of assets acquired		84,299
Asset retirement obligations		(877)
Ad valorem tax liability		(44)
Fair value of assets acquired		$ 83,378
Western Catarina Midstream [Member]
Business Acquisition [Line Items]
Fixed assets	$ 142,887
Contractual customer relationships	201,888
Purchase of SPP common shares from SN	1,065
Fair value of assets acquired	$ 345,840

Acquisitions (Pro Forma) (Detai

Acquisitions (Pro Forma) (Details) $ / shares in Units, $ in Thousands	Aug. 03, 2015	Dec. 31, 2015USD ($)$ / shares	Dec. 31, 2014USD ($)$ / shares
Eagle Ford [Member]
Business Acquisition [Line Items]
Revenues		$ 105,204	$ 165,022
Net income (loss) attributable to common unitholders		(157,161)	$ 8,256
Revenues, actual		19,357
Excess of revenues over direct operating expenses, actual		$ 14,270
Class A Unit [Member] | Eagle Ford [Member]
Business Acquisition [Line Items]
Net income (loss) - pro forma basic and diluted (in dollars per unit) | $ / shares		$ (17.72)	$ 2.16
Class B Unit [Member] | Eagle Ford [Member]
Business Acquisition [Line Items]
Net income (loss) - pro forma basic and diluted (in dollars per unit) | $ / shares		(14.10)	$ 2.85
Common Units [Member]
Business Acquisition [Line Items]
Reverse stock split ratio	0.1
Common Units [Member] | Eagle Ford [Member]
Business Acquisition [Line Items]
Net income (loss) - pro forma basic and diluted (in dollars per unit) | $ / shares		$ (40.32)

Fair Value Measurements (Detail

Fair Value Measurements (Details) $ in Thousands	Dec. 31, 2015USD ($)item	Dec. 31, 2014USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Embedded derivative	$ (193,077)
Number of interest rate derivatives | item	0
Netting Cash and Collateral [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets		$ (90)
Derivative liabilities		90
Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	$ 31,018	22,829
Embedded derivative	(193,077)
Total net assets	(162,059)	22,829
Fair Value, Inputs, Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	31,018	22,919
Derivative liabilities		(90)
Total net assets	31,018	$ 22,829
Fair Value, Inputs, Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Embedded derivative	(193,077)
Total net assets	$ (193,077)

Fair Value Measurements (Embedd

Fair Value Measurements (Embedded Derivative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Fair Value Measurements [Abstract]
Beginning Balance
Initial fair value of embedded derivative - bifurcated from mezzanine equity	$ (183,095)
(Losses) on embedded derivative	(9,982)
Ending Balance	(193,077)
(Losses) included in earnings related to derivatives still held as of December 31, 2015, and 2014	$ (9,982)

Derivative And Financial Inst43

Derivative And Financial Instruments (Hedges In Place) (Details)	12 Months Ended
	Dec. 31, 2015MMBTU$ / MMBTU$ / bblbbl
West Texas Intermediate 2016 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	121,005
Average Price | $ / bbl	73.53
West Texas Intermediate 2016 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	113,226
Average Price | $ / bbl	73.77
West Texas Intermediate 2016 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	106,483
Average Price | $ / bbl	73.95
West Texas Intermediate 2016 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	100,525
Average Price | $ / bbl	74.10
West Texas Intermediate 2016 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	441,239
Average Price | $ / bbl	73.82
West Texas Intermediate 2017 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	57,953
Average Price | $ / bbl	64.80
West Texas Intermediate 2017 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	54,554
Average Price | $ / bbl	64.80
West Texas Intermediate 2017 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	51,570
Average Price | $ / bbl	64.80
West Texas Intermediate 2017 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	48,926
Average Price | $ / bbl	64.80
West Texas Intermediate 2017 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	213,003
Average Price | $ / bbl	64.80
West Texas Intermediate 2018 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	56,798
Average Price | $ / bbl	65.40
West Texas Intermediate 2018 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	54,197
Average Price | $ / bbl	65.40
West Texas Intermediate 2018 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	51,851
Average Price | $ / bbl	65.40
West Texas Intermediate 2018 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	49,709
Average Price | $ / bbl	65.40
West Texas Intermediate 2018 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	212,555
Average Price | $ / bbl	65.40
West Texas Intermediate 2019 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	52,760
Average Price | $ / bbl	65.65
West Texas Intermediate 2019 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	50,784
Average Price | $ / bbl	65.65
West Texas Intermediate 2019 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	48,960
Average Price | $ / bbl	65.65
West Texas Intermediate 2019 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	47,264
Average Price | $ / bbl	65.65
West Texas Intermediate 2019 [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	199,768
Average Price | $ / bbl	65.65
West Texas Intermediate [Member]
Derivative [Line Items]
Volume (in Bbls) | bbl	1,066,565
NYMEX 2016 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	1,098,689
Average Price | $ / MMBTU	4.13
NYMEX 2016 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	1,048,146
Average Price | $ / MMBTU	4.14
NYMEX 2016 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	998,394
Average Price | $ / MMBTU	4.14
NYMEX 2016 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	963,327
Average Price | $ / MMBTU	4.14
NYMEX 2016 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	4,108,556
Average Price | $ / MMBTU	4.14
NYMEX 2017 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	80,563
Average Price | $ / MMBTU	3.52
NYMEX 2017 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	75,829
Average Price | $ / MMBTU	3.52
NYMEX 2017 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	71,672
Average Price | $ / MMBTU	3.52
NYMEX 2017 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	67,984
Average Price | $ / MMBTU	3.52
NYMEX 2017 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	296,048
Average Price | $ / MMBTU	3.52
NYMEX 2018 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	79,042
Average Price | $ / MMBTU	3.58
NYMEX 2018 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	75,404
Average Price | $ / MMBTU	3.58
NYMEX 2018 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	72,115
Average Price | $ / MMBTU	3.58
NYMEX 2018 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	69,122
Average Price | $ / MMBTU	3.58
NYMEX 2018 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	295,683
Average Price | $ / MMBTU	3.58
NYMEX 2019 Swap Quarter 1 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	73,432
Average Price | $ / MMBTU	3.62
NYMEX 2019 Swap Quarter 2 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	70,648
Average Price | $ / MMBTU	3.62
NYMEX 2019 Swap Quarter 3 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	68,088
Average Price | $ / MMBTU	3.62
NYMEX 2019 Swap Quarter 4 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	65,720
Average Price | $ / MMBTU	3.62
NYMEX 2019 [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	277,888
Average Price | $ / MMBTU	3.62
NYMEX [Member]
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	4,978,175

Derivative And Financial Inst44

Derivative And Financial Instruments (Change In Fair Value) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	$ 25,150	$ 19,854
Commodity Contract [Member]
Derivative Instruments Gain Loss [Line Items]
Beginning fair value of commodity derivatives	22,829	10,601
Ending fair value of commodity derivatives	31,018	22,829
Oil [Member] | Commodity Contract [Member]
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	22,410	13,983
Net settlements on derivative contracts	(13,191)	69
Oil [Member] | Oil And Liquids Sales [Member]
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	19,147	19,854
Natural Gas [Member] | Commodity Contract [Member]
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	6,148	5,871
Net settlements on derivative contracts	(7,178)	$ (7,695)
Natural Gas [Member] | Natural Gas Sales [Member]
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	$ 6,003

Derivative And Financial Inst45

Derivative And Financial Instruments (Eagle Ford) (Details) - Eagle Ford [Member] $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Derivative [Line Items]
Oil and natural gas production, 2015	95.00%
Oil and natural gas production, 2016	90.00%
Oil and natural gas production, 2017	85.00%
Oil and natural gas production, 2018	85.00%
Oil and natural gas production, 2019	80.00%
Fair value of derivative instruments	$ 15

Derivative And Financial Inst46

Derivative And Financial Instruments (Embedded Derivative) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Derivative And Financial Instruments [Abstract]
Beginning Balance
Initial fair value of embedded derivative - bifurcated from mezzanine equity	$ (183,095)
(Losses) on embedded derivative	(9,982)
Ending Balance	$ (193,077)

Long-Term Debt (Details)

Long-Term Debt (Details)	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Line of Credit Facility [Line Items]
Outstanding debt under reserve-based credit facility	$ 107,000,000	$ 42,500,000
Unamortized debt issue costs	2,000,000	$ 700,000
Credit Agreement [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity	500,000,000
Initial borrowing capacity	$ 200,000,000
Borrowing base multiplier	5
Sub-limit which may be used for issuance of letters of credit	$ 15,000,000
Credit Agreement [Member] | Second full quarter after Catarina acquisition
Line of Credit Facility [Line Items]
Borrowing base multiplier	4.75
Credit Agreement [Member] | Thereafter
Line of Credit Facility [Line Items]
Borrowing base multiplier	4.5
Credit Agreement [Member] | Scenario Two [Member]
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4
Minimum [Member] | Credit Agreement [Member]
Line of Credit Facility [Line Items]
Commitment fee on unutilized borrowing base	0.375%
Consolidated current asset ratio	1
Required interest coverage ratio	2.5
Ownership percentage by subsidiary	50
Exceeding of reserve-based credit facility over borrowing base (as a percent)	90.00%
Minimum [Member] | Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Variable interest rate	1.75%
Minimum [Member] | Credit Agreement [Member] | ABR [Member]
Line of Credit Facility [Line Items]
Variable interest rate	0.75%
Maximum [Member] | Credit Agreement [Member]
Line of Credit Facility [Line Items]
Commitment fee on unutilized borrowing base	0.50%
Maximum [Member] | Credit Agreement [Member] | Scenario One [Member]
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4.5
Maximum [Member] | Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line of Credit Facility [Line Items]
Variable interest rate	2.75%
Maximum [Member] | Credit Agreement [Member] | ABR [Member]
Line of Credit Facility [Line Items]
Variable interest rate	1.75%

Oil And Natural Gas Propertie48

Oil And Natural Gas Properties (Properties) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Oil And Natural Gas Properties [Abstract]
Proved property	$ 731,548	$ 649,432
Unproved property	39	1,560
Land	501	501
Total property costs	732,088	651,493
Materials and supplies	1,056	1,056
Total	733,144	652,549
Less: Accumulated depreciation, depletion, amortization and impairments	(652,167)	(517,239)
Oil and natural gas properties and equipment, net	$ 80,977	$ 135,310

Oil and Natural Gas Propertie49

Oil and Natural Gas Properties (Gathering and Transportation Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Gathering and transportation assets	$ 147,479
Less: Accumulated depreciation, depletion, amortization and impairments	(652,167)	$ (517,239)
Western Catarina Midstream [Member]
Property, Plant and Equipment [Line Items]
Gathering and transportation assets	147,479
Less: Accumulated depreciation, depletion, amortization and impairments	(1,402)
Total gathering and transportation assets	$ 146,077

Oil and Natural Gas Propertie50

Oil and Natural Gas Properties (DDA and Impairments) (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Mar. 05, 2015	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
DD&A			$ 14,536	$ 17,533
Asset impairments	$ 0	$ 123,800	123,860	5,424
Total			138,396	22,957
Non-cash impairment charges			123,900	5,400
Proved property		$ 731,548	731,548	649,432
Exploration and dry hole costs			0	0
Impairments of unproved properties			$ 1,866
Furniture and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Useful lives			3 years
Furniture and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Useful lives			15 years
Gathering Facilities [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Useful lives			36 years
Oil and Natural Gas-Related Assets [Member]
Property, Plant and Equipment [Line Items]
DD&A			$ 10,330	17,533
Gathering and Transportation Related Assets [Member]
Property, Plant and Equipment [Line Items]
DD&A			$ 4,206
Texas And Louisiana Oil And Natural Gas Fields [Member]
Property, Plant and Equipment [Line Items]
Proved property				$ 81,000

Provision For Income Taxes (Inc

Provision For Income Taxes (Income Tax Provision (Benefit)) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
Current:
Federal	$ 2
State	53
Total current	55
Total provision for (benefit from) income taxes	$ 55

Provision For Income Taxes (Rec

Provision For Income Taxes (Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Provision For Income Taxes [Abstract]
Pre-Tax Net Book Income (Loss) "NBI"	$ (137,001)	$ 9,503
Texas Margin Tax	780
Return to Accrual	55
Valuation Allowance	(780)
Total provision for (benefit from) income taxes	$ 55
Effective income tax rate	(0.04%)

Provision For Income Taxes (DTA

Provision For Income Taxes (DTA and DTL) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Deferred tax assets (liabilities):
Derivative assets, liability	$ (63)
Depreciable, depletable property, plant and equipment	843
Deferred tax assets:	780
Valuation allowance	$ (780)
Total Deferred tax assets

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation [Abstract]
Asset retirement obligation, beginning balance	$ 17,031,000	$ 9,513,000
Liabilities added from acquisitions	3,634,000	80,000
Liabilities added from drilling		59,000
Sold	(58,000)
Revisions to cost estimates	(1,156,000)	6,780,000
Settlements	(186,000)	(5,000)
Accretion expense	1,099,000	604,000
Asset retirement obligation, ending balance	20,364,000	17,031,000
Legally restricted assets	$ 0	$ 0

Related Party Transactions (Det

Related Party Transactions (Details)	Oct. 14, 2015USD ($)aMcfbbl	Mar. 31, 2015USD ($)shares	Oct. 31, 2015shares	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)$ / sharesshares	Dec. 31, 2015USD ($)shares	Dec. 31, 2014USD ($)shares	Aug. 02, 2015shares
Related Party Transaction [Line Items]
Related parties, net receivable						$ 1,500,000	$ 1,000,000
Related parties, net payable						1,000,000
Cash payment for acquisition, net						$ 427,218,000	1,351,000
Sanchez Energy Corporation [Member]
Related Party Transaction [Line Items]
Agreement term						15 years
SP Holdings [Member]
Related Party Transaction [Line Items]
Agreement term						10 years
Services Agreement renewal term						10 years
Administrative fee paid						$ 9,900,000	$ 6,000,000
Eagle Ford [Member]
Related Party Transaction [Line Items]
Initial purchase price		$ 85,000,000
Cash payment for acquisition		83,400,000
Eagle Ford [Member] | Sanchez Energy Corporation [Member]
Related Party Transaction [Line Items]
Initial purchase price		85,000,000
Closing adjustments		1,400,000
Cash payment for acquisition, net		$ 81,600,000
Western Catarina Midstream [Member]
Related Party Transaction [Line Items]
Agreement term	15 years
Acres dedicated for gathering | a	35,000
Gathering Agreement delivery commitment period	5 years
Cash payment for acquisition	$ 345,800,000
Western Catarina Midstream [Member] | Oil [Member]
Related Party Transaction [Line Items]
Gathering Agreement minimum quarterly volume delivery commitment | bbl	10,200
Western Catarina Midstream [Member] | Natural Gas [Member]
Related Party Transaction [Line Items]
Gathering Agreement minimum quarterly volume delivery commitment | Mcf	142,000
Western Catarina Midstream [Member] | Sanchez Energy Corporation [Member]
Related Party Transaction [Line Items]
Agreement term				15 years
Cash payment for acquisition				$ 345,800,000
Proceeds from gathering and processing agreement						$ 7,500,000
Class A Unit [Member]
Related Party Transaction [Line Items]
Common units, outstanding | shares						0	48,451
Class B Unit [Member]
Related Party Transaction [Line Items]
Common units, outstanding | shares						0	2,877,701
Class A Preferred [Member] | Eagle Ford [Member]
Related Party Transaction [Line Items]
Business acquisition, units issued | shares		10,625,000
Common Units [Member]
Related Party Transaction [Line Items]
Common units, outstanding | shares						3,240,812	0	31,495,506
Common Units [Member] | Sanchez Energy Corporation [Member]
Related Party Transaction [Line Items]
Common units, outstanding | shares						0
Common Units [Member] | SP Holdings [Member]
Related Party Transaction [Line Items]
Shares issued in lieu of paying fee | shares					5,956
Shares issued in lieu of paying fee, value					$ 165,582
Cost per share issued in lieu of paying fee | $ / shares					$ 12.78
Common Units [Member] | Eagle Ford [Member]
Related Party Transaction [Line Items]
Business acquisition, units issued | shares		105,263
Common Units [Member] | Eagle Ford [Member] | Sanchez Energy Corporation [Member]
Related Party Transaction [Line Items]
Business acquisition, units issued | shares		105,263
Business acquisition, value of units		$ 2,000,000
Shares repurchased | shares			105,263

Unit-Based Compensation (Detail

Unit-Based Compensation (Details) - shares	Dec. 01, 2015	Mar. 31, 2015	Dec. 31, 2015
Director [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted			34,693
Officer [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted		102,564
Number of Restricted Units, Vested		(76,923)
Number of Restricted Units, Withheld for taxes		32,269
Restricted Stock Units (RSUs) [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares approved for grant	335,715
Vesting period	3 years
Prior To Stock Split [Member] | Director [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted			346,925
Prior To Stock Split [Member] | Officer [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted		1,025,641
Number of Restricted Units, Vested		(769,231)
Number of Restricted Units, Withheld for taxes		322,692

Unit-Based Compensation (Restri

Unit-Based Compensation (Restricted Units Activity) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding	361,356
LTIP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding	25,641
Restricted Stock Units (RSUs) [Member] | 2009 Omnibus Incentive Compensation Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding	10,083	38,033
Number of Restricted Units, Granted	472,972	44,968
Number of Restricted Units, Vested	(87,872)	(55,034)
Number of Restricted Units, Returned/Cancelled	(33,826)	(17,884)
Number of Restricted Units, Outstanding	361,357	10,083
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	$ 31.10	$ 32.42
Weighted Averaged Grant Date Fair Value Per Unit, Granted	14.89	27.48
Weighted Averaged Grant Date Fair Value Per Unit, Vested	18.68	24.40
Weighted Averaged Grant Date Fair Value Per Unit, Returned/Cancelled	17.33	28.16
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	$ 14.18	$ 31.10

Distributions To Unitholders (D

Distributions To Unitholders (Details) - $ / shares	Feb. 29, 2016	Feb. 09, 2016	Nov. 30, 2015	Jun. 30, 2015	Dec. 31, 2009	Dec. 31, 2015	Dec. 31, 2014
Paid-in-kind units distributed						549,756
Distribution paid per unit			$ 0.400
Common Units [Member]
Distribution paid per unit				$ 0	$ 0		$ 0
Common Units [Member] | Subsequent Event [Member]
Distribution declared per unit		$ 0.406
Distribution paid per unit	$ 0.406
Class A Preferred [Member] | Subsequent Event [Member]
Distributions declared as a percentage		2.50%
Distributions paid as a percentage	2.50%
Class B Preferred [Member] | Subsequent Event [Member]
Distribution declared per unit		$ 0.3815
Distribution paid per unit	$ 0.3815

Members Equity Partners Capit59

Members Equity Partners Capital (Details)	Oct. 14, 2015USD ($)$ / sharesshares	Aug. 03, 2015$ / sharesshares	Apr. 15, 2015USD ($)$ / sharesshares	Mar. 31, 2015USD ($)$ / sharesshares	Mar. 06, 2015	May. 31, 2015USD ($)shares	Dec. 31, 2015USD ($)shares	Dec. 31, 2015USD ($)shares	Dec. 31, 2015USD ($)shares	Aug. 04, 2015$ / shares	Aug. 02, 2015shares	Apr. 30, 2015USD ($)	Dec. 31, 2014shares
Limited Partners' Capital Account [Line Items]
Restricted unvested common units granted and outstanding							361,356	361,356	361,356
Issuance of common units, value | $								$ 193,000
Proceeds from common units sold | $									$ 193,000
Proceeds from preferred units sold | $									$ 359,500,000
LTIP [Member]
Limited Partners' Capital Account [Line Items]
Restricted unvested common units granted and outstanding							25,641	25,641	25,641
Class A Preferred [Member]
Limited Partners' Capital Account [Line Items]
Class A preferred units, outstanding							11,409,131	11,409,131	11,409,131				0
Units sold (in units)			234,375	10,625,000
Price per unit sold | $ / shares			$ 1.60	$ 1.60
Proceeds from preferred units sold | $			$ 375,000	$ 17,000,000
Distribution rate, first year									10.00%
Distribution rate, first year, quarterly									2.50%
Distribution rate, second year									11.50%
Distribution rate, second year, quarterly									2.875%
Distribution rate, third year									12.50%
Distribution rate, third year, quarterly									3.125%
Increase in distribution rate							4.00%
Class B Preferred [Member]
Limited Partners' Capital Account [Line Items]
Class B preferred units, outstanding							19,444,445	19,444,445	19,444,445				0
Units sold (in units)	19,444,445
Price per unit sold | $ / shares	$ 18
Proceeds from preferred units sold | $	$ 350,000,010
Percent of consideration paid	2.25%
Paid in full in cash, per annum							10.00%
Paid in part cash, per annum							12.00%
Dividend per annum							8.00%
Paid-in kind per annum							4.00%
Class A Unit [Member]
Limited Partners' Capital Account [Line Items]
Common units, outstanding							0	0	0				48,451
Common units, issued							0	0	0				48,451
Class B Unit [Member]
Limited Partners' Capital Account [Line Items]
Common units, outstanding							0	0	0				2,877,701
Restricted unvested common units granted and outstanding													100,825
Common units, issued							0	0	0				2,877,701
Common Units [Member]
Limited Partners' Capital Account [Line Items]
Common units, outstanding							3,240,812	3,240,812	3,240,812		31,495,506		0
Percent of common units outstanding					2.00%
Common units sales agreement, value of common units allocated | $												$ 100,000,000
Issuance of common units, value | $								$ 193,000
Reverse stock split ratio		0.1
Common units, issued		3,149,551					3,240,812	3,240,812	3,240,812				0
Market price | $ / shares		$ 1.55								$ 15.50
Units sold (in units)						6,800
Proceeds from common units sold | $						$ 200,000
Minimum [Member] | Class A Preferred [Member]
Limited Partners' Capital Account [Line Items]
Proceeds from common units sold | $							$ 75,000,000
Minimum [Member] | Class B Preferred [Member]
Limited Partners' Capital Account [Line Items]
Preferred unit conversion, amount | $									$ 17,500,000
Cash from conversion | $									$ 75,000,000
Prior To Stock Split [Member] | Common Units [Member]
Limited Partners' Capital Account [Line Items]
Units sold (in units)						68,000

Members Equity Partners Capit60

Members Equity Partners Capital (Class B Preferred Units) (Details) - Class B Preferred [Member] $ in Thousands	10 Months Ended
	Dec. 31, 2015USD ($)
Private placement of Class B Preferred Units	$ 350,000
Less: discount	(191,901)
Less: amortization of discount	6,594
Less: distributions	7,418
Total mezzanine equity	$ 172,111

Members Equity Partners Capit61

Members Equity Partners Capital (EPU) (Details) - USD ($) $ / shares in Units, $ in Thousands	2 Months Ended	7 Months Ended	10 Months Ended	12 Months Ended
	Mar. 05, 2015	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014
Assumed net (loss) income	$ (923)		$ (153,895)	$ (154,818)	$ 9,503
Asset impairments	0		123,800	$ 123,860	$ 5,424
Class A Unit [Member]
Weighted average units outstanding, basic				48,451	76,326
Weighted average units outstanding, diluted				48,451	76,326
Assumed net (loss) income	$ (18)				$ 190
Net (loss) income per unit - Basic and diluted	$ (0.38)				$ 2.50
Class B Unit [Member]
Weighted average units outstanding, basic				2,879,163	2,843,159
Weighted average units outstanding, diluted				2,879,163	2,853,241
Assumed net (loss) income	$ (905)				$ 9,313
Net (loss) income per unit - Basic and diluted	$ (0.31)				$ 3.30
Common Units [Member]
Weighted Average Units Outstanding - Basic and diluted				3,071,587
Weighted average units outstanding, basic	2,927,613	3,071,587			2,919,485
Adjustment for reverse split - Basic	(26,348,518)	(27,644,287)			(26,275,362)
Weighted average units outstanding, diluted	2,927,613	3,071,587			2,929,567
Adjustment for reverse split - Diluted	(26,348,518)	(27,644,287)			(26,366,105)
Assumed net (loss) income			$ (153,895)
Net (loss) income per unit - Basic and diluted			$ (50.10)	$ (50.10)
Prior To Stock Split [Member] | Class A Unit [Member]
Weighted average units outstanding, basic	484,505				763,261
Weighted average units outstanding, diluted	484,505				763,261
Net (loss) income per unit - Basic and diluted	$ (0.04)				$ 0.25
Prior To Stock Split [Member] | Class B Unit [Member]
Weighted average units outstanding, basic	28,791,626				28,431,586
Weighted average units outstanding, diluted	28,791,626				28,532,411
Net (loss) income per unit - Basic and diluted	$ (0.03)				$ 0.33
Prior To Stock Split [Member] | Common Units [Member]
Weighted average units outstanding, basic	29,276,131	30,715,874			29,194,847
Weighted average units outstanding, diluted	29,276,131	30,715,874			29,295,672
Net (loss) income per unit - Basic and diluted			$ (5.01)

Reporting Segments (Segment Inf

Reporting Segments (Segment Information) (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Mar. 05, 2015	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014
Operating Revenues
Natural gas sales			$ 19,809	$ 34,458
Oil sales			35,297	40,337
Natural gas liquid sales			1,597	2,477
Gathering and transportation sales			11,725
Total revenues			68,428	77,272
Operating expenses:
Lease operating expenses			19,988	21,012
Transportation operating expenses			2,176
Cost of sales			595	1,487
Production taxes			1,792	3,200
General and administrative			26,109	16,499
Exploration costs			1,866
(Gain) loss on sale of assets			(111)	223
Depreciation, depletion and amortization			14,536	17,533
Asset impairments	$ 0	$ 123,800	123,860	5,424
Accretion expense			1,099	604
Total operating expenses			191,910	65,982
Operating income (loss)			(123,482)	11,290
Upstream [Member]
Operating Revenues
Natural gas sales			19,809	34,458
Oil sales			35,297	40,337
Natural gas liquid sales			1,597	2,477
Total revenues			56,703	77,272
Operating expenses:
Lease operating expenses			19,890	21,012
Cost of sales			595	1,487
Production taxes			1,792	3,200
General and administrative			26,109	16,499
Exploration costs			1,866
(Gain) loss on sale of assets			(111)	223
Depreciation, depletion and amortization			10,330	17,533
Asset impairments			123,860	5,424
Accretion expense			1,048	604
Total operating expenses			185,379	65,982
Operating income (loss)			(128,676)	$ 11,290
Midstream [Member]
Operating Revenues
Gathering and transportation sales			11,725
Total revenues			11,725
Operating expenses:
Lease operating expenses			98
Transportation operating expenses			2,176
Depreciation, depletion and amortization			4,206
Accretion expense			51
Total operating expenses			6,531
Operating income (loss)			$ 5,194

Reporting Segments (Assets by S

Reporting Segments (Assets by Segment) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 473,391	$ 173,247
Upstream [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	120,174	$ 173,247
Midstream [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 353,217

Reporting Segments (Percentage

Reporting Segments (Percentage of Revenue) (Details) - Revenue [Member] - Customer Concentration Risk [Member]	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Upstream [Member]
Revenue, Major Customer [Line Items]
Percentage of revenue	100.00%	100.00%
Upstream [Member] | Customer A [Member]
Revenue, Major Customer [Line Items]
Percentage of revenue	33.00%	33.00%
Upstream [Member] | Customer B [Member]
Revenue, Major Customer [Line Items]
Percentage of revenue	41.00%	30.00%
Upstream [Member] | Customer C [Member]
Revenue, Major Customer [Line Items]
Percentage of revenue	1.00%	16.00%
Upstream [Member] | Customer D [Member]
Revenue, Major Customer [Line Items]
Percentage of revenue	18.00%	14.00%
Upstream [Member] | All Others [Member]
Revenue, Major Customer [Line Items]
Percentage of revenue	7.00%	7.00%
Midstream [Member]
Revenue, Major Customer [Line Items]
Percentage of revenue	100.00%
Midstream [Member] | Customer E [Member]
Revenue, Major Customer [Line Items]
Percentage of revenue	100.00%

Supplemental Information On O65

Supplemental Information On Oil And Natural Gas Producing Activities (Capitalized Costs) (Details) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014
Supplemental Information On Oil And Natural Gas Producing Activities [Abstract]
Proved property	[1]	$ 731,548	$ 649,432
Unproved property	[1]	39	1,560
Land		501	501
Total property costs	[1]	732,088	651,493
Materials and supplies	[1]	1,056	1,056
Total	[1]	733,144	652,549
Less: accumulated depreciation, depletion, amortization and impairments	[1]	(652,167)	(517,239)
Oil and natural gas properties and equipment, net	[1]	$ 80,977	$ 135,310
[1]	Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. Unproved property costs include capitalized costs for oil and natural gas leaseholds where proved reserves do not exist.

Supplemental Information On O66

Supplemental Information On Oil And Natural Gas Producing Activities (Costs Incurred Production) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Supplemental Information On Oil And Natural Gas Producing Activities [Abstract]
Proved	$ 81,378	$ 1,239
Unproved		112
Development costs	468	5,865
Oil and natural gas properties and equipment, net	$ 81,846	$ 7,216

Supplemental Information On O67

Supplemental Information On Oil And Natural Gas Producing Activities (Proved Reserves) (Details) - MMBoe MMBoe in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Changes in proved developed and undeveloped reserves
Balance	16,627	15,209
Extensions and discoveries	3	509
Purchase of reserves in place	5,124	72
Revisions of previous estimates	(9,038)	2,361
Production	(1,074)	(1,524)
Balance	11,642	16,627
Proved developed reserves	11,523	12,439
Proved undeveloped reserves	119	4,188
Oil [Member]
Changes in proved developed and undeveloped reserves
Balance	1,662	2,072
Extensions and discoveries	3	416
Purchase of reserves in place	3,516	72
Revisions of previous estimates	(1,754)	(590)
Production	(268)	(308)
Balance	3,159	1,662
Proved developed reserves	3,071	1,523
Proved undeveloped reserves	88	139
Natural Gas [Member]
Changes in proved developed and undeveloped reserves
Balance	14,907	12,994
Extensions and discoveries		93
Purchase of reserves in place	799
Revisions of previous estimates	(7,175)	3,008
Production	(795)	(1,188)
Balance	7,736	14,907
Proved developed reserves	7,705	10,858
Proved undeveloped reserves	31	4,049
Natural Gas Liquids [Member]
Changes in proved developed and undeveloped reserves
Balance	58	143
Purchase of reserves in place	809
Revisions of previous estimates	(109)	(57)
Production	(11)	(28)
Balance	747	58
Proved developed reserves	747	58

Supplemental Information On O68

Supplemental Information On Oil And Natural Gas Producing Activities (Proved Reserves Narrative) (Details) MMBoe in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)MMBoe$ / Mcf$ / bbl	Dec. 31, 2014USD ($)MMBoe$ / Mcf$ / bbl	Dec. 31, 2013MMBoe
Reserve Quantities [Line Items]
Exploration and dry hole costs | $	$ 0	$ 0
Proved reserve estimates	11,642	16,627	15,209
Reserve revision	11,523	12,439
Increase (decrease) in proved reserve estimates	5,000	1,400
Oil [Member]
Reserve Quantities [Line Items]
Proved reserve estimates	3,159	1,662	2,072
Reserve revision	3,071	1,523
Weighted-average product price | $ / bbl	50.28	93.95
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved reserve estimates	747	58	143
Reserve revision	747	58
Weighted-average product price | $ / bbl	19.90	35.11
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved reserve estimates	7,736	14,907	12,994
Reserve revision	7,705	10,858
Percentage of reserves	66.00%	90.00%
Weighted-average product price | $ / Mcf	2.58	4.09
Cherokee Basin [Member]
Reserve Quantities [Line Items]
Increase (decrease) in proved reserve estimates	4,000	2,200

Supplemental Information On O69

Supplemental Information On Oil And Natural Gas Producing Activities (Standardized Measure) (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Information On Oil And Natural Gas Producing Activities [Abstract]
Future cash inflows	$ 289,767	$ 532,152
Future production costs	(165,861)	(260,909)
Future estimated development costs	(19,026)	(57,741)
Future net cash flows	104,880	213,502
10% annual discount for estimated timing of cash flows	(37,028)	(93,969)
Standardized measure of discounted future net cash flows related to proved gas reserves	$ 67,852	$ 119,533	$ 143,714

Supplemental Information On O70

Supplemental Information On Oil And Natural Gas Producing Activities (Change Standardized Measure) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Supplemental Information On Oil And Natural Gas Producing Activities [Abstract]
Beginning of the period	$ 119,533	$ 143,714
Sales and transfers of oil and natural gas, net of production costs	(30,748)	(38,817)
Net changes in prices and production costs related to future production	(125,979)	(18,410)
Development costs incurred during the period	5,016	18,075
Changes in extensions and discoveries	178	24,611
Revisions of previous quantity estimates	(11,299)	(22,034)
Purchases and sales of reserves in place	109,181	1,918
Accretion discount	11,953	14,371
Other	(9,983)	(3,895)
Standardized measure of discount future net cash flows related to proved gas reserves	$ 67,852	$ 119,533

Subsequent Events (Details)

Subsequent Events (Details) - Subsequent Event [Member]	Feb. 09, 2016$ / shares
Class B Preferred [Member]
Subsequent Event [Line Items]
Distribution declared per unit	$ 0.3815
Annual distribution declared per unit	$ 0.3815
Class A Preferred [Member]
Subsequent Event [Line Items]
Paid-in-kind distribution percentage	2.50%
Common Units [Member]
Subsequent Event [Line Items]
Distribution declared per unit	$ 0.406
Annual distribution declared per unit	$ 1.6240