Evolve Transition Infrastructure (SNMP) 10-K 28 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Mar. 23, 2017	Jun. 30, 2016
Document And Entity Information
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
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		14,153,061
Entity Public Float			$ 40,730,955
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, 2016	Dec. 31, 2015
Revenues
Natural gas sales	$ 10,408	$ 19,809
Oil sales	5,138	35,297
Natural gas liquids sales	1,167	1,597
Gathering and transportation sales	53,972	11,725
Total revenues	70,685	68,428
Operating expenses:
Lease operating expenses	14,981	19,988
Transportation operating expenses	12,478	2,176
Cost of sales	328	595
Production taxes	1,167	1,792
General and administrative	22,901	23,655
Unit-based compensation expense	1,941	2,454
Exploration costs		1,866
Loss (gain) on sale of assets	219	(111)
Depreciation, depletion and amortization	33,799	14,536
Asset impairments	7,646	123,860
Accretion expense	1,127	1,099
Total operating expenses	96,587	191,910
Other (income) expense
Interest expense, net	5,093	4,207
(Gain) loss on embedded derivatives	(47,794)	9,982
Earnings from equity investments	(2,382)	(81)
Other income	(50)	(589)
Total other (income) expenses	(45,133)	13,519
Total expenses	51,454	205,429
Income (loss) before income taxes	19,231	(137,001)
Income tax expense		55
Net income (loss)	19,231	(137,056)
Less:
Preferred unit paid-in-kind distributions		(1,425)
Preferred unit distributions	(39,375)	(7,418)
Preferred unit amortization	(24,340)	(8,919)
Net loss attributable to common unitholders	$ (44,484)	$ (154,818)
Net loss per unit
Weighted Average Units Outstanding - Basic and diluted	4,658,970
Class A Units
Net loss per unit
Net loss per unit - Basic and diluted		$ (0.38)
Weighted Average Units Outstanding - Basic and diluted		48,451
Class B Units
Net loss per unit
Net loss per unit - Basic and diluted		$ (0.31)
Weighted Average Units Outstanding - Basic and diluted		2,879,163
Common Units
Other (income) expense
Net income (loss)	$ 19,231
Less:
Net loss attributable to common unitholders	$ (44,484)
Net loss per unit
Net loss per unit - Basic and diluted	$ (9.55)	$ (50.1)
Weighted Average Units Outstanding - Basic and diluted	4,658,970	3,071,587

Consolidated Statements Of Ope3

Consolidated Statements Of Operations (Parenthetical)	Aug. 03, 2015
Consolidated Statements of Operations
Reverse stock split ratio	0.1

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets
Cash and cash equivalents	$ 957	$ 6,571
Restricted cash	0	600
Accounts receivable	1,212	2,461
Accounts receivable - related entities	5,987	1,515
Prepaid expenses	2,041	744
Fair value of derivative instruments	4,568	21,010
Total current assets	14,765	32,901
Oil and natural gas properties and related equipment
Oil and natural gas properties, equipment and facilities (successful efforts method)	758,913	732,088
Gathering and transportation assets	152,209	147,479
Material and supplies	1,056	1,056
Less: accumulated depreciation, depletion, amortization and impairment	(689,358)	(653,569)
Oil and natural gas properties and equipment, net	222,820	227,054
Other assets
Intangible assets, net	185,766	199,741
Fair value of derivative instruments	3,964	10,008
Equity investments	111,614	642
Other non-current assets	776	954
Total assets	539,705	471,300
Current liabilities
Accounts payable and accrued liabilities	951	7,288
Accounts payable and accrued liabilities - related entities	7,046	1,035
Royalties payable	706	689
Fair value of derivative instruments	740
Total current liabilities	9,443	9,012
Other liabilities
Asset retirement obligation	13,579	20,364
Embedded derivatives		193,077
Long-term debt, net of debt issuance costs	151,322	104,909
Fair value of derivative instruments	1,356
Other liabilities	4,270
Total other liabilities	170,527	318,350
Total liabilities	179,970	327,362
Commitments and contingencies (See Note 12)
Mezzanine equity
Class B preferred units, 29,296,441 and 19,444,445 units issued and outstanding as of December 31, 2016 and 2015, respectively	342,991	172,111
Partners' capital (deficit)
Class A preferred units, zero and 11,694,364 units issued and outstanding as of December 31, 2016 and 2015, respectively		17,112
Common units, 13,447,749 and 3,240,813 units issued and outstanding as of December 31, 2016 and 2015, respectively	16,744	(45,285)
Total partners' capital (deficit)	16,744	(28,173)
Total liabilities and partners' capital	$ 539,705	$ 471,300

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - shares	Dec. 31, 2016	Dec. 31, 2015
Consolidated Balance Sheets
Class B preferred units, issued	29,296,441	19,444,445
Class B preferred units, outstanding	29,296,441	19,444,445
Class A preferred units, issued	0	11,694,364
Class A preferred units, outstanding	0	11,694,364
Units, issued	13,447,749	3,240,813
Units, outstanding	13,447,749	3,240,813

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Net income (loss)	$ 19,231	$ (137,056)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	21,900	13,250
Amortization of debt issuance costs	507	1,338
Revisions to asset retirement obligation included in DD&A	(1,859)	(1,518)
Asset impairments	7,646	123,860
Accretion of plugging and abandonment liability	1,127	1,099
Distributions (return on investment) from equity investments	2,950	47
Equity earnings in affiliate	(2,381)	(80)
Bad debt expense	35	122
Dryhole/exploration expense		1,866
(Gain)/Loss from disposition of property and equipment	210	(111)
Total mark-to-market on commodity derivative contracts	7,239	(25,149)
Cash settlements on commodity derivative contracts	18,780	18,996
Unit-based compensation	2,044	2,454
(Gain) loss on embedded derivatives	(47,794)	9,982
Amortization of intangible assets	13,756	2,805
Costs for plug and abandon activities	(182)	(186)
Changes in Operating Assets and Liabilities:
Accounts receivable	(159)	4,166
Accounts receivable - related entities	(4,472)	(1,515)
Prepaid expenses	(1,297)	1,039
Other assets	730	300
Accounts payable and accrued liabilities	(3,876)	(862)
Accounts payable - related entities	6,011	1,035
Royalties payable	17	(445)
Net cash provided by operating activities	40,163	15,437
Cash flows from investing activities:
Cash paid for acquisitions	(25,622)	(427,218)
Development of oil and natural gas properties	(939)	(2,005)
Proceeds from sale of assets	38	470
Construction of gathering and transportation assets	(4,730)
Purchases of equity affiliate	(107,271)	13
Net cash used in investing activities	(138,524)	(428,740)
Cash flows from financing activities:
Proceeds from issuance of preferred units		359,500
Payments for offering costs	(5,403)	(1,756)
Proceeds from issuance of debt	72,000	107,000
Repayment of debt	(26,000)	(42,500)
Issuance of common units	99,196	193
Repurchase of common units under repurchase program	(2,948)	(2,223)
Units tendered by employees for tax withholdings	(140)	(618)
Distributions to common unitholders	(6,696)	(1,219)
Class B preferred unit cash distributions	(37,168)
Debt issuance costs	(94)	(2,741)
Net cash provided by financing activities	92,747	415,636
Net increase (decrease) in cash and cash equivalents	(5,614)	2,333
Cash and cash equivalents, beginning of period	6,571	4,238
Cash and cash equivalents, end of period	957	6,571
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	1,119	1,684
Acquisition of oil and natural gas properties in exchange for common units		935
Cash paid during the period for interest	4,449	2,380
Cash paid during the period for income taxes		$ 53
Transfer of embedded derivative to Class B preferred units	$ 145,283

Consolidated Statements of Chan

Consolidated Statements of Changes in Members’ Equity/Partners’ Capital - USD ($) $ in Thousands	Class A Units	Class B Units	Class A Preferred	Common Units	Total
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			11,694,364	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	$ (1,912)			$ 1,912
Class A Units converted to common units (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 distributions			$ 1,425	(1,425)
Preferred unit paid-in-kind distributions (in shares)			834,989
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 to common unit holders				$ (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			11,694,364	3,240,813
Class A Units converted to common units			$ (17,112)	$ 17,112
Class A Units converted to common units (in shares)			(11,694,364)	1,169,441
Units tendered by employees for tax withholding				$ (140)	(140)
Units tendered by employees for tax withholding (in shares)				(12,227)
Unit-based compensation programs				$ 2,044	2,044
Unit-based compensation programs (in shares)				67,627
Units forfeited by employees (in shares)				(2,000)
Issuance of common units				$ 96,278	96,278
Issuance of common units (in shares)				9,226,595
Common units retired via unit repurchase program				$ (2,948)	(2,948)
Common units retired via unit repurchase program (in shares)				(242,500)
Cash distributions to common unit holders				$ (6,696)	(6,696)
Distributions - Class B preferred units				(62,852)	(62,852)
Net income (loss)				19,231	19,231
Balance at Dec. 31, 2016				$ 16,744	$ 16,744
Balance (in shares) at Dec. 31, 2016				13,447,749

Consolidated Statements of Cha8

Consolidated Statements of Changes in Members’ Equity/Partners’ Capital (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Offering costs	$ 5.3
Class A Units
Offering costs		$ 0.8

Organization And Business

Organization And Business	12 Months Ended
	Dec. 31, 2016
Organization And Business
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 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, 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 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 also commenced a process to sell our oil and natural gas properties in the Mid-Continent region. In July 2016, we sold a portion of our oil and natural gas properties in the Mid-Continent region and acquired a 50% equity interest in Carnero Gathering. In November 2016, we completed a public offering of approximately 6,745,107 common units (which includes exercise of the underwriters’ option to purchase 194,305 common units) for net proceeds of approximately $69.7 million, after deducting customary offering expenses. Concurrent with the public offering, we completed a private placement of 2,272,727 common units representing limited partner interests for net proceeds of approximately $25.0 million. The combined proceeds were used to close the acquisition of a 50% equity interest in Carnero Processing, as well as acquire working interest in 23 producing Eagle Ford Shale wellbores located in Dimmit and Zavala counties in South Texas and escalating working interests in an additional 11 producing wellbores in the Palmetto Field in Gonzales, Texas. As a result of the acquisition of midstream assets from Sanchez Energy, our historical financial statements prior to the quarter ended December 31, 2015, will differ substantially from our financial statements, from and after such period principally because a significant portion of our revenues now 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, 2016
Basis Of Presentation And Summary Of Significant Accounting Policies
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 production of oil and natural gas and the midstream business, which include the Western 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 consolidated financial statements upon adoption. In January 2017, the FASB issued Accounting Standards Update (“ASU”) 2017-01 “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which provides a new framework for determining whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In December 2016, the FASB issued ASU 2016-19 “Technical Corrections and Improvements,” which amends a number of Topics in the FASB ASC. The ASU is part of an ongoing FASB project to facilitate Codification updates for non-substantive technical corrections, clarifications, and improvements that are not expected to have a significant effect on accounting practice or create a significant administrative cost to most entities. The ASU will apply to all reporting entities within the scope of the affected accounting guidance. Most amendments are effective upon issuance (December 2016). In November 2016, the FASB issued ASU 2016-18 “Statement of Cash Flows (Topic 230): Restricted Cash,” which requires companies to include cash and cash equivalents that have restrictions on withdrawal or use in total cash and cash equivalents on the statement of cash flows. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In October 2016, the FASB issued ASU 2016-16 “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” which eliminates a current exception in U.S. GAAP to the recognition of the income tax effects of temporary differences that result from intra-entity transfers of non-inventory assets. The intra-entity exception is being eliminated under the ASU. The standard is required to be applied on a modified retrospective basis and will be effective beginning with the first quarter of 2018. Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments” effective for annual and interim periods beginning after December 15, 2017. This ASU is intended to clarify the presentation of cash receipts and payments in specific situations. Early adoption is permitted including adoption in an interim period. We chose to adopt ASU 2016-15 for the year ended December 31, 2016 on a retrospective basis. In March 2016, the FASB issued ASU No. 2016-09 “Improvements to Employee Share-Based Payment Accounting,” effective for annual and interim periods for public companies beginning after December 15, 2016, with a cumulative-effect and prospective approach to be used for implementation. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions including accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, minimum statutory tax withholding requirements and classification of employee taxes paid on the statement of cash flows when an employer withholds shares for tax-withholding purposes. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018, with a modified retrospective approach to be used for implementation. ASU 2016-02 updates the previous lease guidance by requiring the recognition of a right-to-use asset and lease liability on the statement of financial position for those leases previously classified as operating leases under the old guidance. In addition, ASU 2016-02 updates the criteria for a lessee’s classification of a finance lease. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In 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 on a retrospective basis. 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 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. In August 2015, the FASB issued ASU 2015-15, “Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.” The guidance in ASU 2015-03 does not address debt issuance costs related to line-of-credit arrangements. ASU 2015-15 states given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements, the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. During the first quarter of 2016, the Partnership adopted ASU 2015-03 and ASU 2015-15 retrospectively to the comparable periods in this Form 10-K. Adoption of this guidance affected the balance sheets as of December 31, 2015 as follows (in thousands): Decrease in Long term debt, net of debt issuance costs of approximately $2,091 Decrease in Debt issuance costs (Other Assets) of approximately $2,091 In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” In March, April, and May of 2016, the FASB issued rules clarifying several aspects of the new revenue recognition standard. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The Partnership will not early adopt the standard although early adoption is permitted. The Partnership is currently evaluating whether to apply the retrospective approach or modified retrospective approach with the cumulative effect recognized as of the date of initial application. The Partnership is currently evaluating the impact the standard is expected to have on its consolidated financial statements by evaluating current revenue streams and evaluating contracts under the revised standards. 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. In accordance with ASU No. 2015-03 and ASU No. 2015-15, debt issuance costs are to 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. As such, debt issuance costs, net of amortization, at December 31, 2015 of $2.1 million have been reclassified from other assets to other liabilities, effectively eliminating the debt issuance cost line and reducing long-term debt in the balance sheet. 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 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. Restricted Cash We had no restricted cash as of December 31, 2016. At December 31, 2015, we had restricted cash of $0.6 million held in escrow related to a vendor dispute, which 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. Our allowance for doubtful accounts was $0.4 million as of December 31, 2016 and 2015. 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 Agreement 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 as of December 31, 2016 and 2015. We have no off-balance-sheet credit exposure related to our operations or customers. For the years ended December 31, 2016 and 2015, two customers accounted for 10% or more of our total revenue. Sanchez Energy, whose earned revenues contribute exclusively to our midstream segment, accounted for 76% and 17% of total revenue for the years ended December 31, 2016 and 2015, respectively. During that same time period, Macquarie Cook Energy, LLC, whose earned revenues contribute exclusively to our production segment, accounted for approximately 6% and 17% of our total revenue, respectively. 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. 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 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 as either short-term or long-term assets or liabilities based on their anticipated settlement date. 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.” Revenue Recognition Sales are recognized when oil, natural gas and NGLs 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 were no gas imbalance positions as of December 31, 2016, and an immaterial gas imbalance on one of our wells in the Mid-continent region at December 31, 2015. 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. Our wholly-owned subsidiary, CEP Services Company, Inc. is a taxable entity. For the years ended December 31, 2016, and 2015, 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. For the years ended December 31, 2016 and 2015, we had no environmental liabilities recorded, as no liabilities were deemed necessary. Unit-Based Compensation The Partnership records stock-based compensation expense for awards granted to its directors (for their services as directors) in accordance with the provisions of Accounting Standards Codification (“ASC”) Topic 718, “Compensation—Stock Compensation.” Stock-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method. Unit-based compensation granted to employees of SOG (including those employees who also serve as the officers of our general partner) and consultants in exchange for services are considered awards to non-employees and the Partnership records unit-based compensation expense for these awards at fair value in accordance with the provisions of ASC 505-50, “Equity-Based Payments to Non-Employees.” For awards granted to non-employees, the Partnership records compensation expenses equal to the fair value of the unit-based award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. Compensation expense for unvested awards to non-employees is revalued at each period end and is amortized over the vesting period of the unit-based award. Unit-based payments are measured based on the fair value of the equity instruments granted, as it is more determinable than the value of the services rendered. In accordance with the guidance, the inclusion of market performance acceleration conditions does not change the accounting classification as compared to those awards without market performance acceleration conditions. Compensation expense for the unvested awards is revalued at each period end and is amortized over the vesting period of the stock-based award. 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 and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2016
Acquisitions and Divestitures
Acquisitions and Divestitures	3. ACQUISITIONS AND DIVESTITURES Carnero Processing Acquisition On November 22, 2016, we completed the acquisition of 50% of the outstanding membership interests in Carnero Processing, LLC (“Carnero Processing”) from Sanchez Energy and SN Midstream, LLC, (“SN Midstream”) a wholly-owned subsidiary of Sanchez Energy, for aggregate cash consideration of approximately $55.5 million and the assumption of approximately $24.5 million of remaining capital contribution commitments (the “Carnero Processing Transaction”). The membership interests acquired constitute 50% of the outstanding membership interests in Carnero Processing, with the other 50% of the membership interests being owned by TPL SouthTex Processing Company LP. Carnero Processing is constructing a cryogenic gas processing facility located in La Salle County, Texas. See Note 11. “Investments” for additional information relating to the Carnero Processing Transaction. Production Acquisition On November 22, 2016, we completed the acquisition from SN Cotulla Assets, LLC and SN Palmetto, LLC, each a wholly-owned subsidiary of Sanchez Energy, of working interests in 23 producing Eagle Ford Shale wellbores located in Dimmit and Zavala counties in South Texas together with escalating working interests in an additional 11 producing wellbores located in the Palmetto Field in Gonzales County, Texas (together, the “Production Acquisition”) for aggregate cash consideration of $25.6 million after $1.4 million in normal and customary closing adjustments. The effective date of the transaction was July 1, 2016. The Production Acquisition included initial conveyed working interests and net revenue interests for each property which escalate on January 1 for 2017 and 2018, at which point, SPP’s interests in the Production Acquisition properties will stay constant for the remainder of the respective lives of the assets. 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 $ Fair value of assets acquired Asset retirement obligations Fair value of net assets acquired $ Carnero Gathering Transaction On July 5, 2016, the Partnership purchased from Sanchez Energy and SN Midstream 50% of the issued and outstanding membership interests in Carnero Gathering for total consideration of approximately $37.0 million, plus the assumption of approximately $7.4 million of remaining capital contribution commitments (the “Carnero Gathering Transaction”). In addition, the Partnership is required to pay an earnout based on gas received at the delivery points from SN Catarina, LLC, a wholly-owned subsidiary of Sanchez Energy (“SN Catarina”), and other producers. The membership interests acquired constitute 50% of the outstanding membership interests in Carnero Gathering, with the other 50% of the membership interests being owned by TPL SouthTex Processing Company LP. Carnero Gathering operates a gas gathering pipeline from an interconnection in Webb County, Texas to interconnection(s) with a gas processing facility being developed and constructed by Carnero Processing. See Note 11. “Investments” for additional information relating to the Carnero Gathering Transaction. The Partnership made capital contributions to Carnero Gathering totaling $3.3 million between July 5, 2016 and December 31, 2016. 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 $ 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 Shale 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 Eagle Ford 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 Shale 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 $ Mid-Continent Divestiture On June 15, 2016, certain wholly-owned subsidiaries of the Partnership entered into an agreement with Gateway Resources U.S.A., Inc. (“Gateway”) to sell substantially all of the Partnership’s operated oil and natural gas wells, leases and other associated assets and interests in Oklahoma and Kansas (other than those arising under or related to a concession agreement with the Osage Nation) (the “Mid-Continent Divestiture”) for cash consideration of $7,120, subject to adjustment for title and environmental defects, effective as of August 1, 2016 (the “Effective Time”). In addition, Gateway agreed to assume all obligations relating to the assets arising after the Effective Time and all plugging and abandonment costs relating to the assets arising prior to the Effective Time. The Partnership closed the sale of this transaction on July 15, 2016. The Partnership recorded a $0.2 million loss related to an intangible asset balance comprised of marketing contracts from the 2007 Newfield acquisition which were included in the Mid-Continent Divestiture. Results of Operations and Pro Forma Information (Unaudited) The following unaudited pro forma combined financial information for the year ended December 31, 2015 reflect the consolidated results of operations of the Partnership as if the Western Catarina Midstream Acquisition and Eagle Ford Acquisition and related financings had occurred on January 1, 2015. 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 Revenues $ Net loss attributable to common unitholders $ Net loss per unit prior to conversion Class A units - Basic and diluted $ Class B units - Basic and diluted $ Net 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 Acquisition and Eagle Ford Acquisition 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 consolidated statements of operations for the year ended December 31, 2016, for the Western Catarina Midstream Acquisition and Eagle Ford Acquisition are shown in the table that follows. As the income from the Carnero Gathering Transaction and Carnero Processing Transaction are classified under earnings from equity investments on the income statement, it is not included in operating results below. However, earnings resulting from the Carnero Gathering Transaction and Carnero Processing Transaction were $2. 3 million for the year ended December 31, 2016. Direct operating expenses include lease operating expenses and production and ad valorem taxes (in thousands): Year Ended December 31, 2016 Revenues $ Excess of revenues over direct operating expenses $

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Fair Value Measurements
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). 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, 2016 (in thousands): Fair Value Measurements at December 31, 2016 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Netting Cash and Fair Value at (Level 1) (Level 2) (Level 3) Collateral December 31, 2016 Derivative assets $ — $ $ — $ — $ 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, 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 $ — $ $ — $ — $ Embedded derivative — — — Total net assets $ — $ $ $ — $ As of December 31, 2016 and 2015, 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 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. We periodically review oil and natural gas properties for impairment when facts and circumstances indicate that their carrying values may not be recoverable. A reconciliation of the beginning and ending balances of the Partnership’s asset retirement obligations is presented in Note 9, ‘‘Asset Retirement Obligation.’’ The following table summarizes the non-recurring fair value measurements of our assets and liabilities as of December 31, 2016 (in thousands): Fair Value Measurements at December 31, 2016 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Impairment (a) $ — $ — $ Acquisitions (b) — — Total net assets $ — $ — $ (a) During the year ended December 31, 2016, we recorded a non-cash impairment charge of $7.6 million to impair our producing oil and natural gas properties in Texas and Louisiana (acquired prior to the Eagle Ford Acquisition) and in Oklahoma . The carrying values of the impaired proved properties were reduced to a fair value of $10.7 million, estimated using inputs characteristic of a Level 3 fair value measurement. (b) During the year ended December 31, 2016, we acquired oil and natural gas properties with a fair value of $25.6 million. See Note 3. “Acquisitions and Divestitures” for fair value allocation. The following table summarizes the non-recurring fair value measurements of our assets and liabilities as of December 31, 2015 (in thousands): Fair Value Measurements at December 31, 2015 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Impairment (a) $ — $ — $ Acquisitions (b) — — Total net assets $ — $ — $ (a) For the year ended December 31, 2015, we recorded a non-cash impairment charge 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) . The carrying values of the impaired proved properties were reduced to a fair value of $81.0 million, estimated using inputs characteristic of a Level 3 fair value measurement. (b) During the year ended December 31, 2015, we acquired oil and natural gas properties and midstream assets with a combined fair value of $429.2 million. See Note 3. “Acquisitions and Divestitures” for fair value allocation. The fair values of oil and natural gas properties 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. 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, 2016. 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 were required to be bifurcated from the contract and valued as a derivative. The embedded derivative was valued through the use of a Monte Carlo model which utilized observable inputs, the Partnership’s unit prices at 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 marked this derivative to market as of December 31, 2015, and incurred an approximate $10.0 million loss as a result. The fair value of the Partnership’s embedded derivative classified as Level 3 as of December 31, 2016 was zero. 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) December 31, 2016 2015 Beginning balance $ $ — Initial fair value of embedded derivative - bifurcated from mezzanine equity — Gain (loss) on embedded derivative Transfer to mezzanine equity — Ending balance $ — $ Loss included in earnings related to derivatives still held as of December 31, 2016 and 2015 $ — $

Derivative And Financial Instru

Derivative And Financial Instruments	12 Months Ended
	Dec. 31, 2016
Derivative And Financial Instruments
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, 2016, 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, (volume in MMBtu) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2017 $ $ $ $ $ 2018 $ $ $ $ $ 2019 $ $ $ $ $ 2020 $ $ $ $ $ MTM Fixed Price Basis Swaps – West Texas Intermediate (WTI) For the Year Ended December 31, (volume 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 2017 $ $ $ $ $ 2018 $ $ $ $ $ 2019 $ $ $ $ $ 2020 $ $ $ $ $ The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the years ended December 31, 2016 and 2015 (in thousands): December 31, 2016 2015 Beginning fair value of commodity derivatives $ $ Net gains (losses) on crude oil derivatives Net gains on natural gas derivatives Net settlements on derivative contracts: Crude oil Natural gas Net premiums on derivative contracts — Ending fair value of commodity derivatives $ $ The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands): Location of Gain(Loss) Year Ended December 31, Derivative Type in Income 2016 2015 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, 2016 and 2015, 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, 2016 and 2015, the fair value of the hedges assumed resulted in a $6.4 million and $15.0 million asset, respectively, 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 were required to be bifurcated from the contract and valued as a derivative. The embedded derivative was valued through the use of a Monte Carlo model which utilized 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 marked this derivative to market as of December 31, 2015, and incurred approximately $10.0 million loss as a result. In November 2016, we completed a public offering and private placement of common units. As a result of these equity issuances, the Class B conversion rate was determined and the provisions that were required to bifurcate were removed. At that time, the fair value of the derivative was transferred to mezzanine equity. The following table sets forth a reconciliation of the changes in fair value of the Partnership’s embedded derivative for the years ended December 31, 2016 and 2015 (in thousands): December 31, 2016 2015 Beginning fair value of embedded derivative $ $ — Initial fair value of embedded derivative - bifurcated from mezzanine equity — Gain (loss) on embedded derivative Transfer to mezzanine equity — Ending fair value of embedded derivative $ — $

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2016
Long-Term Debt
Long-Term Debt	6. LONG-TERM DEBT Credit Agreement We have entered into a Credit Agreement with Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto. The Credit Agreement provides a maximum commitment of $500,000,000 and has a maturity date of March 31, 2020. Borrowings under the Credit Agreement 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 Agreement is limited to the borrowing base for our midstream assets and our oil and natural gas. Borrowings under the Credit Agreement are available for direct investment in oil and natural gas properties, acquisitions, and working capital and general business purposes. The Credit Agreement 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 Agreement 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 and the amount of distributions received from joint ventures multiplied by 5.0 initially, 4.75 for the second full quarter after the acquisition of the Western 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 Agreement are determined by reference to (i) the London interbank rate (“LIBOR”) plus an applicable margin between 2.25% and 3.25% per annum based on utilization or (ii) a domestic bank rate (“ABR”) plus an applicable margin between 1.25% and 2.25% per annum based on utilization plus (iii) a commitment fee of 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 Agreement 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 Agreement 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 Agreement and exercise other rights and remedies. The Credit Agreement 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 Agreement, 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 Agreement 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, 2016, we were in compliance with the financial covenants contained in the Credit Agreement. We monitor compliance on an ongoing basis. If we are unable to remain in compliance with the financial covenants contained in our Credit Agreement 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 Agreement, 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, 2016 and 2015, our unamortized debt issuance costs were $1.7 million and $2.1 million, respectively. These costs are amortized to interest expense in our consolidated statements of operations over the life of our Credit Agreement. Amortization of debt issuance costs recorded during the year ended December 31, 2016 and 2015 were $0.5 million and $1.3 million, respectively.

Oil And Natural Gas Properties

Oil And Natural Gas Properties And Related Equipment	12 Months Ended
	Dec. 31, 2016
Oil And Natural Gas Properties And Related Equipment.
Oil And Natural Gas Properties And Related Equipment	7. OIL AND NATURAL GAS PROPERTIES AND RELATED EQUIPMENT Gathering and transportation assets consist of the following (in thousands): December 31, 2016 2015 Gathering and transportation assets Midstream assets $ $ Less: Accumulated depreciation and amortization Total gathering and transportation assets $ $ Oil and natural gas properties consist of the following (in thousands): December 31, 2016 2015 Oil and natural gas properties and related equipment 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 $ $ Oil and Natural Gas Properties We follow the successful efforts method of accounting for our oil and natural gas production activities. Under this method of accounting, costs relating to leasehold acquisition, property acquisition and the development of proved areas are capitalized when incurred. 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. Proved Reserves 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, 2016 and 2015 is described in detail in Note 19, “Supplemental Information on Oil and Natural Gas Producing Activities.” 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. 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. 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, 2016 2015 Depreciation, depletion and amortization of oil and natural gas-related assets $ $ Depreciation, depletion and amortization of gathering and transportation related assets Total Depreciation, depletion and amortization 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: (i) future operating and development costs; (ii) future commodity prices; and (iii) 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 impairment testing exclude derivative instruments. Asset Retirement Obligation As described in Note 9, “Asset Retirement Obligations,” 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, 2016 and 2015; 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, 2016
Provision For Income Taxes
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 the years ended December 31, 2016 and 2015 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 Years Ended December 31, 2016 2015 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 Years Ended December 31, 2016 2015 Pre-tax net book income (loss) $ $ 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): December 31, 2016 2015 Deferred tax assets (liabilities): Derivative assets $ $ Depreciable, depletable property, plant and equipment Other — Deferred tax assets: Valuation allowance Total Deferred tax assets $ — $ — 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 Partnership chose to adopt ASU 2015-17 as of the quarter ended December 31, 2015 on a retrospective basis. As of December 31, 2016, and 2015, the Partnership had no material uncertain tax positions.

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation
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 the units-of-production method or straight line for midstream assets. 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, 2016 2015 Asset retirement obligation, beginning balance $ $ Liabilities added from acquisitions 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 2016 and 2015, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing asset retirement obligations. During the years ended December 31, 2016 and 2015, revisions were made to the ARO liability based on recent costs incurred on abandoned wells, which were lower on average than originally projected.

Intangible Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2016
Intangible Assets
Intangible Assets	10. INTANGIBLE ASSETS Intangible assets are comprised of customer and marketing contracts. The intangible assets balance includes $185.6 million related to the customer contract with Sanchez Energy that was entered into as part of the Western Catarina Midstream Acquisition. Pursuant to the 15-year agreement, Sanchez Energy tenders all of its crude petroleum, natural gas and other hydrocarbon-based product volumes on 35,000 dedicated acres in the Western Catarina of the Eagle Ford Shale in Texas for processing and transportation through the gathering system, with a right to tender additional volumes outside of the dedicated acreage. These intangible assets are being amortized using the straight-line method over the 15 year life of the agreement. As of December 31, 2016, the intangible asset balance was reduced by $0.2 million due to marketing contracts from the 2007 Newfield acquisition which were included in the Mid-Continent Divestiture. Amortization expense for the years ended December 31, 2016 and 2015 was $13.8 million and $3.2 million, respectively. Intangible assets as of December 31, 2016 and 2015 are detailed below (in thousands): December 31, 2016 2015 Beginning balance $ $ Additions — Disposals — Amortization Ending balance $ $

Investments

Investments	12 Months Ended
	Dec. 31, 2016
Investments
Investments	11. INVESTMENTS On July 5, 2016, the Partnership purchased a 50% membership interest in Carnero Gathering from SN Midstream for an initial payment of approximately $37.0 million and the assumption of remaining capital commitments to Carnero Gathering, estimated at approximately $7.4 million as of the date of the acquisition. The membership interests acquired constitute 50% of the outstanding membership interests in Carnero Gathering. The remaining 50% membership interests of Carnero Gathering are owned by an affiliate of Targa Resources Corp. (“Targa”). During the year ended December 31, 2016, the Partnership made approximately $3.3 million of capital contributions to the joint venture. Prior to the sale, SN Midstream had invested approximately $26.0 million in the Carnero Gathering joint venture. The fair value of the intangible asset for the contractual customer relationship related to Carnero Gathering was valued at approximately $13.0 million. This amount is being amortized over the contract term of fifteen years and decreases earnings from Carnero Gathering. As part of the Carnero Gathering transaction, the Partnership is required to pay SN Midstream a monthly earnout based upon gas received at Carnero Gathering’s receipt points from SN Catarina and gas delivered by other producers and processing by Carnero Processing, which will begin in 2017. This earnout is considered as contingent consideration and its estimated fair value of $4.3 million was recorded on the balance sheet as a deferred liability as of December 31, 2016. As of December 31, 2016, the Partnership has paid approximately $40.3 million for the Carnero Gathering transaction related to the initial payment and contributed capital. The Partnership has accounted for this investment as an equity method investment. Targa is the operator of the joint venture and has significant influence with respect to the normal day-to-day construction and operating decisions. We have included the investment balance in the “Equity investments” caption in our consolidated balance sheet. The Partnership recorded earnings of approximately $2.8 million in equity investments from Carnero Gathering, which was offset by $0.4 million related to the amortization of the contractual customer intangible asset for year ended December 31, 2016. We have included these equity method earnings in the “Earnings from equity investments” line within the consolidated statements of operations. Cash distributions of approximately $3.0 million were received during the year ended December 31, 2016. On November 22, 2016, the Partnership purchased a 50% membership interest in Carnero Processing from SN Midstream for an initial payment of approximately $55.5 million and the assumption of remaining capital commitments to Carnero Processing, estimated at approximately $24.5 million as of the date of the acquisition. The remaining 50% membership interests of Carnero Processing are owned by an affiliate of Targa. During the year ended December 31, 2016, the Partnership made approximately $10.5 million of capital contributions to the joint venture. Prior to the sale, SN Midstream had invested approximately $48.0 million in the Carnero Processing joint venture. As of December 31, 2016, the Partnership has paid approximately $66.0 million for the Carnero Processing transaction related to the initial payment and contributed capital. The Partnership has accounted for this investment as an equity method investment. Targa is the operator of the joint venture and has significant influence with respect to the normal day-to-day construction and operating decisions. We have included the investment balance in the “Equity investments” caption in our consolidated balance sheet. The Partnership recorded expenses of approximately $0.1 million in the “Earnings from equity investments” line within our consolidated statements of operations.

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies
Commitments And Contingencies	12. COMMITMENTS AND CONTINGENCIES We did not have any material commitments and contingencies as of December 31, 2016 or 2015.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions
Related Party Transactions	13. 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, 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 years ended December 31, 2016 and 2015, we incurred costs of approximately $7.5 million and $2.4 million, respectively, to Manager under the Services Agreement. 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 connection with the closing of the Western Catarina Midstream Acquisition, 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. In July 2016, as part of the Carnero Gathering Transaction, the Partnership is required to pay SN Midstream a monthly earnout based upon gas received at Carnero Gathering’s receipt points from SN Catarina and gas delivered by other producers and processing by Carnero Processing, which will begin in 2017. This earnout is considered as contingent consideration and its estimated fair value of $4.3 million was recorded on the balance sheet as a deferred liability as of December 31, 2016. As of December 31, 2016 and 2015, the Partnership had a net receivable from related parties of $6.0 million and $1.5 million, respectively, which are included in “Accounts receivable – related entities” in the consolidated balance sheets. As of December 31, 2016 and 2015, the Partnership also had a net payable to related parties of $7.0 and $1.0 million, respectively. The net receivables/payable as of December 31, 2016 and 2015 consist primarily of revenues receivable from oil and natural gas production and transportation, offset by costs associated with that production and transportation and obligations for general and administrative costs. Sanchez-Related Transactions We have entered into several transactions with Sanchez Energy since January 1, 2015. 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 Officer of Sanchez Energy. In addition, Eduardo Sanchez is the President of Sanchez Energy and Patricio Sanchez is an Executive Vice 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 $2.0 million. 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. See further discussion of the transaction in Note 3, “Acquisitions and Divestitures.” In October 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 closing 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 years ended December 31, 2016 and 2015, Sanchez Energy paid us approximately $50.1 million and $7.5 million, respectively, pursuant to the terms of the gathering and processing agreement. See further discussion of the transaction in Note 3, “Acquisitions and Divestitures.” In July 2016, the Partnership purchased from Sanchez Energy and SN Midstream, a wholly-owned subsidiary of Sanchez Energy, 50% of the issued and outstanding membership interests in Carnero Gathering for total consideration of approximately $37.0 million, plus the assumption of approximately $7.4 million of remaining capital contribution commitments. In November 2016, in conjunction with our public offering of common units, the Partnership entered into a Common Unit Purchase Agreement with SN UR Holdings, LLC (the “Purchaser”), a wholly-owned subsidiary of Sanchez Energy, whereby we issued to the Purchaser 2,272,727 common units for proceeds of approximately $25.0 million. In November 2016, the Partnership consummated a Purchase and Sale Agreement with Sanchez Energy and SN Midstream to purchase all of SN Midstream’s issued and outstanding membership interests in Carnero Processing for approximately $55.5 million plus the assumption of approximately $24.5 million of remaining capital commitments. Also in November 2016, the Partnership consummated a Purchase and Sale Agreement with SN Cotulla Assets, LLC and SN Palmetto, LLC, each a wholly-owned subsidiary of Sanchez Energy , to purchase working interest in 23 producing Eagle Ford Shale wellbores located in Dimmit and Zavala counties in South Texas as well as escalating working interests in an additional 11 producing wellbores in the Palmetto Field in Gonzales, Texas for approximately $25.6 million.

Unit-Based Compensation

Unit-Based Compensation	12 Months Ended
	Dec. 31, 2016
Unit-Based Compensation
Unit-Based Compensation	14. 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, 2014 $ Granted (1) Vested (1) Returned/Cancelled (1) Outstanding at December 31, 2015 Granted Vested Returned/Cancelled Outstanding at December 31, 2016 $ (1) During the year ended December 31, 2016, the Partnership issued 67,627 restricted common units pursuant to the Plan to certain directors of the Partnership’s general partner that vested immediately on the date of the grant . The unit-based compensation expense for the award was based on the fair value on the day before the date of grant.

Distributions To Unitholders

Distributions To Unitholders	12 Months Ended
	Dec. 31, 2016
Distributions To Unitholders
Distributions To Unitholders	15. 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 843,989 paid-in-kind units were distributed for the year ended December 31, 2015. The table below reflects the payment of cash distributions on common units during the years ended December 31, 2016 and 2015. Distribution Date of Date of Date of Three months ended per unit declaration record distribution September 30, 2015 $ November 10, 2016 November 20, 2015 November 30, 2015 December 31, 2015 $ February 9, 2016 February 19, 2016 February 29, 2016 March 31, 2016 $ May 10, 2016 May 20, 2016 May 31, 2016 June 30, 2016 $ August 10, 2016 August 22, 2016 August 31, 2016 September 30, 2016 $ October 31, 2016 November 10, 2016 November 30, 2016 December 31, 2016 $ February 9, 2017 February 20, 2017 February 28, 2017 The table below reflects the payment of distributions on Class B preferred units during the years ended December 31, 2016 and 2015. Cash distribution Date of Date of Date of Three months ended per unit declaration record distribution December 31, 2015 $ February 9, 2016 February 19, 2016 February 29, 2016 March 31, 2016 $ May 10, 2016 May 20, 2016 May 31, 2016 June 30, 2016 $ August 10, 2016 August 22, 2016 August 31, 2016 September 30, 2016 $ October 31, 2016 November 10, 2016 November 30, 2016 December 31, 2016 (a) $ February 9, 2017 February 20, 2017 February 28, 2017 The Partnership elected to pay the fourth quarter 2016 distribution on the Class B preferred units in part cash and, with the consent of the Class B preferred unitholder, in part common units (in lieu of additional Class B preferred units). Accordingly, the Partnership declared a cash distribution of $0.2258 per Class B preferred unit and an aggregate distribution of 208,594 common units, each paid on February 28, 2017 to holders of record on February 20, 2017.

Members' Equity_Partners' Capit

Members' Equity/Partners' Capital	12 Months Ended
	Dec. 31, 2016
Members' Equity/Partners' Capital
Members' Equity/Partners' Capital	16. MEMBERS’ EQUITY/PARTNERS’ CAPITAL Outstanding Units As of December 31, 2016, we had no Class A Preferred Units outstanding, 29,296,441 Class B Preferred Units outstanding, and 13,447,749 common units outstanding, which included 219,144 unvested restricted common units issued under the Plan. 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 laws 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 67,230 common units (6,723 common units after adjusting for reverse unit split discussed below) for total gross proceeds of less than $0.1 million. During 2015, we paid de minimis commissions and other fees to the sales agent in connection with the at-the-market facility. No common units were sold under the agreement in 2016. 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. On March 31, 2016, the Partnership converted all remaining outstanding Class A Preferred Units into common units of the Partnership on a one-for-one basis, adjusted for the 1-for-10 unit split in August 2015. In November 2016, we completed a public offering and private placement of common units. The public offering consisted of 6,745,107 common units (which includes partial exercise of the underwriters’ overallotment of 194,305 common units) for net proceeds of approximately $69.7 million, after deducting customary offering expenses. The private placement consisted of 2,272,727 common units issued to the Purchaser for net proceeds of approximately $25.0 million. Preferred Unit Issuance Class A Preferred Unit Offerings: On March 31, 2015, the Partnership entered into a Class A 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 $17.0 million. The Partnership used the net proceeds of $17.0 million 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 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. On March 31, 2016, the Partnership converted all remaining outstanding Class A Preferred Units into common units of the Partnership on a one-for-one basis, adjusted for 1-for-10 unit split in August 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 “Preferred Unit Purchase Agreement”) between the Partnership and Stonepeak Catarina Holdings LLC (“Stonepeak”), the Partnership sold and Stonepeak purchased 19,444,445 of the Partnership’s newly created Class B Preferred Units (the “Class B Preferred Units”) in a privately 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 $350.0 million. The Partnership used the net proceeds to pay a portion of the consideration for the Western Catarina Gathering Acquisition, along with the payment to Stonepeak 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 holders of the Class B Preferred Units will receive a quarterly distribution, 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 did not raise at least $75,000,000 through the issuance of additional common units prior to September 30, 2016 (with the conversion of the Class A Preferred Units of the Partnership counting toward such amount), the cash portion of the distribution rate was to have increased by 4.0% per annum until consummation of such issuance, as applicable. The Partnership did not raise at least $75,000,000 through the issuance of additional common units prior to September 30, 2016 and an aggregate 14% per annum cash distribution was paid related to the three months ended September 30, 2016. As a result of the common unit issuance in November 2016, and in accordance with the Partnership Agreement, on December 6, 2016, we issued an additional 9,851,996 Class B preferred units to Stonepeak. 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 common units are issued by the Partnership during the period beginning on the private placement closing date and ending on the date on which the Partnership has issued common units (other than issuances pursuant to the Plan) in exchange for cash in an aggregate amount equal to at least $75 million. The Conversion Rate was determined to be $11.29 per Class B Preferred Unit. See further discussion of the Conversion Rate in Note 20 “Subsequent Events.” The Class B Preferred Units are accounted for as mezzanine equity in the consolidated balance sheet consisting of the following (in thousands): December 31, 2016 2015 Mezzanine equity beginning balance $ $ — Private placement of Class B Preferred Units — Discount Amortization of discount Distributions Distributions paid — Transfer embedded derivative to Class B — 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 December 31, March 6 - December 31 January 1 - March 6 2016 2015 2015 Class A units - Basic and Diluted — — Class B Common units - Basic and Diluted — — Common units - Basic and Diluted — Weighted Common units - Basic and Diluted At December 31, 2016, we had 219,144 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, 2015, we had 361,357 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. The following table presents our basic and diluted loss per unit for the year ended December 31, 2016 (in thousands, except for per unit amounts): Total Common Units Assumed net loss to be allocated $ $ 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 $ $ 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 $ 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.

Reporting Segments

Reporting Segments	12 Months Ended
	Dec. 31, 2016
Reporting Segments
Reporting Segments	17. REPORTING SEGMENTS “Midstream” and “Production” best describe the operating segments of the businesses that we separately report. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment. The Midstream segment operates the gathering, processing and transportation of crude oil, natural gas and NGLs. The Production segment operates to produce crude oil 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): For the Year Ended December 31, 2016 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 Unit compensation expense — Loss on sale of assets — Depreciation, depletion and amortization Asset impairments — Accretion expense Total operating expenses Operating income (loss) $ $ $ For the Year Ended December 31, 2015 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 — Unit-based compensation expense — Exploration costs — Loss on sale of assets — Depreciation, depletion and amortization Asset impairments — Accretion expense Total operating expenses Operating income (loss) $ $ $ The following table summarizes the total assets by operating segment as of December 31, 2016 and 2015 (in thousands): December 31, 2016 2015 Segment Assets 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 revenue for the periods presented below: For the Years Ended December 31, 2016 2015 Production Macquarie Cook Energy, LLC. % % All other Midstream Sanchez Energy % % Total % %

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2016
Variable Interest Entities
Variable Interest Entities	18. VARIABLE INTEREST ENTITIES During the year ended December 31, 2016, the Partnership adopted ASU 2015-02, “Consolidation—Amendments to the Consolidation Analysis,” which introduces a separate analysis for determining if limited partnerships and similar entities are variable interest entities (“VIEs”) and clarifies the steps a reporting entity would have to take to determine whether the voting rights of stockholders in a corporation or similar entity are substantive. As noted above in Note 11, “Investments,” the Partnership purchased a 50% membership interest in Carnero Gathering from SN Midstream for an initial payment of approximately $37.0 million and the assumption of remaining capital commitments to Carnero Gathering, estimated at approximately $7.4 million as of the date of the acquisition. The Partnership determined that the Carnero Gathering joint venture is more similar to a limited partnership than a corporation. Under the revised guidance of ASU 2015-02, a limited partnership or similar entity with equity at risk will not be a VIE if a partner is able to exercise kick-out rights over the general partner(s) or is able to exercise substantive participating rights. We concluded that the Carnero Gathering joint venture is a VIE under the revised guidance because we cannot remove Targa as operator and we do not have substantive participating rights. In addition, Targa has the discretion to direct activities of the VIE regarding the risks associated with price, operations, and capital investment which have the most significant impact on the VIE’s economic performance. The Partnership’s investment in Carnero Gathering represents a VIE that could expose the Partnership to losses. The amount of losses the Partnership could be exposed to from the Carnero Gathering joint venture is limited to the capital investment of approximately $48.1 million. As of December 31, 2016, the Partnership had invested approximately $40.3 million in Carnero Gathering and the Partnership has an outstanding letter of credit for the remaining commitment to invest approximately $4.3 million, which compares to the remaining capital commitments of approximately $4.1 million as of December 31, 2016. As of year-end 2016, no debt has been incurred by Carnero Gathering. We have included this VIE in the “Equity investments” long-term asset line on the balance sheet. As noted above in Note 11, “Investments,” the Partnership purchased a 50% membership interest in Carnero Processing from SN Midstream for an initial payment of approximately $55.5 million and the assumption of remaining capital commitments to Carnero Processing, estimated at approximately $24.5 million as of the date of the acquisition. The Partnership determined that the Carnero Processing joint venture is more similar to a limited partnership than a corporation. Under the revised guidance of ASU 2015-02, a limited partnership or similar entity with equity at risk will not be a VIE if a limited partner is able to exercise kick-out rights over the general partner(s) or is able to exercise substantive participating rights. We concluded that the Carnero Processing joint venture is a VIE under the revised guidance because we cannot remove Targa as operator and we do not have substantive participating rights. In addition, Targa has the discretion to direct activities of the VIE regarding the risks associated with price, operations, and capital investment which have the most significant impact on the VIE’s economic performance. The Partnership’s investment in Carnero Processing represents a VIE that could expose the Partnership to losses. The amount of losses the Partnership could be exposed to from the Carnero Processing joint venture is limited to the capital investment of approximately $80 million. As of December 31, 2016, the Partnership had invested approximately $66 million in Carnero Processing and the Partnership had issued a letter of credit for the remaining commitment to invest approximately $10.6 million, which compares to the remaining capital commitments of approximately $14 million as of December 31, 2016. As of year-end 2016, no debt has been incurred by Carnero Processing. We have included this VIE in the “Equity investments” long-term asset line on the balance sheet. Below is a tabular comparison of the carrying amounts of the assets and liabilities of the VIE and the Partnership’s maximum exposure to loss as of December 31, 2016 and 2015 (in thousands): December 31, 2016 2015 Capital investments $ $ — Earnings in equity investments — Distributions received — Estimated earnout accrued — Equity in equity investments $ $ — December 31, 2016 2015 Equity in equity investments $ $ — Guarantees of capital investments — Maximum exposure to loss $ $ —

Supplemental Information On Oil

Supplemental Information On Oil And Natural Gas Producing Activities	12 Months Ended
	Dec. 31, 2016
Supplemental Information On Oil And Natural Gas Producing Activities
Supplemental Information On Oil And Natural Gas Producing Activities	19. 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 our capitalized costs as of December 31, 2016 and 2015 (in thousands): December 31, 2016 2015 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, 2016 and 2015 (in thousands): For the Years Ended December 31, 2016 2015 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 year ended December 31, 2016 primarily represents costs related to recompletions, while those for the same period in 2015 related to the development of our proved undeveloped reserves. The properties acquired in 2016 were in Texas, and the properties acquired in 2015 were in Texas and Louisiana. We had no exploration and dry hole costs in 2016 and 2015, 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 oil and natural gas producing activities are 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, 2014 Extensions and discoveries — — Puchase of reserves in place Revisions of previous estimates Production December 31, 2015 Purchase of reserves in place Sales of reserves in place — Revisions of previous estimates Production December 31, 2016 Proved developed reserves: December 31, 2015 December 31, 2016 Proved undeveloped reserves: December 31, 2015 — December 31, 2016 — — — — 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, 2016 and 2015, proved reserve estimates were 6.9 MMBoe and 11.6 MMBoe, respectively. For the year ended December 31, 2016, Ryder Scott, an independent petroleum engineering firm, prepared the estimates of our proved reserves which were used to prepare our financial statements. For the year ended December 31, 2015, NSAI, an independent petroleum engineering firm, and Ryder Scott prepared the estimates of our proved reserves which were used to prepare our financial statements. Our 2016 estimates of total proved reserves decreased 4.7 MMBoe from 2015 due to a downward revision of previous estimates of 4.4 MMBoe offset by an increase of 1.4 MMBoe related to the purchase of reserves in place. The downward revision was due to lower commodity prices as well as a decrease in proved developed not producing and PUD reserves, partially offset by an increase in PDP reserves from our Production Acquisition. Our reserves are 35% 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 were: $38.85 per barrel for oil, $13.84 per barrel for NGLs and $2.28 per Mcf for natural gas. Proved developed producing reserves were lower due to natural production decline and our sale of reserves in place. 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 were: $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. 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 Years Ended December 31, 2016 2015 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 Years Ended December 31, 2016 2015 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 Changes in development costs Changes in extensions and discoveries — Revisions of previous quantity estimates Purchases and sales of reserves in place Accretion discount Change in production rates, timing, and other Standardized measure of discounted future net cash flows related to proved gas reserves $ $

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2016
Subsequent Events
Subsequent Events	20. SUBSEQUENT EVENTS On January 25, 2017, the Partnership and Stonepeak Catarina Holdings LLC (the “Class B Preferred Holder”) entered into a Settlement Agreement and Mutual Release (the “Settlement Agreement”) to settle a dispute arising from the calculation of an adjustment to the number of Class B Preferred Units pursuant to Section 5.10(g) of the Second Amended and Restated Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”). Pursuant to the Settlement Agreement, and in accordance with Section 5.4 of the Partnership Agreement, the Partnership issued 1,704,446 Class B Preferred Units to the Class B Preferred Holder in a privately negotiated transaction as partial consideration for the Settlement Agreement, with the “Class B Preferred Unit Price” being established at $11.29 per Class B Preferred Unit. Pursuant to the terms of the Partnership Agreement, the Class B Preferred Units are convertible at any time, at the option of the Class B Preferred Holder, into common units of the Partnership. The issuance of the Class B Preferred Units pursuant to the Settlement Agreement was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933 pursuant to Section 4(a)(2) thereof. On February 9, 2017, the board of directors of the general partner of the Partnership declared a fourth quarter 2016 cash distribution on its common units of $0.4310 per unit ($1.7240 per unit annualized) payable on February 28, 2017 to holders of record on February 20, 2017. The Partnership also declared a fourth quarter distribution on the Class B preferred units and elected to pay the distribution in part cash and, with the consent of the Class B Preferred Holder, in part common units (in lieu of additional Class B preferred units). Accordingly, the Partnership declared a cash distribution of $0.2258 per Class B preferred unit and an aggregate distribution of 208,594 common units, each paid on February 28, 2017 to holders of record on February 20, 2017.

Basis Of Presentation And Sum29

Basis Of Presentation And Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Basis Of Presentation And Summary Of Significant Accounting Policies
Basis of Presentation	Basis of Presentation 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 production of oil and natural gas and the midstream business, which include the Western 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 consolidated financial statements upon adoption. In January 2017, the FASB issued Accounting Standards Update (“ASU”) 2017-01 “Business Combinations (Topic 805): Clarifying the Definition of a Business,” which provides a new framework for determining whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In December 2016, the FASB issued ASU 2016-19 “Technical Corrections and Improvements,” which amends a number of Topics in the FASB ASC. The ASU is part of an ongoing FASB project to facilitate Codification updates for non-substantive technical corrections, clarifications, and improvements that are not expected to have a significant effect on accounting practice or create a significant administrative cost to most entities. The ASU will apply to all reporting entities within the scope of the affected accounting guidance. Most amendments are effective upon issuance (December 2016). In November 2016, the FASB issued ASU 2016-18 “Statement of Cash Flows (Topic 230): Restricted Cash,” which requires companies to include cash and cash equivalents that have restrictions on withdrawal or use in total cash and cash equivalents on the statement of cash flows. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In October 2016, the FASB issued ASU 2016-16 “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” which eliminates a current exception in U.S. GAAP to the recognition of the income tax effects of temporary differences that result from intra-entity transfers of non-inventory assets. The intra-entity exception is being eliminated under the ASU. The standard is required to be applied on a modified retrospective basis and will be effective beginning with the first quarter of 2018. Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments” effective for annual and interim periods beginning after December 15, 2017. This ASU is intended to clarify the presentation of cash receipts and payments in specific situations. Early adoption is permitted including adoption in an interim period. We chose to adopt ASU 2016-15 for the year ended December 31, 2016 on a retrospective basis. In March 2016, the FASB issued ASU No. 2016-09 “Improvements to Employee Share-Based Payment Accounting,” effective for annual and interim periods for public companies beginning after December 15, 2016, with a cumulative-effect and prospective approach to be used for implementation. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions including accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, minimum statutory tax withholding requirements and classification of employee taxes paid on the statement of cash flows when an employer withholds shares for tax-withholding purposes. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018, with a modified retrospective approach to be used for implementation. ASU 2016-02 updates the previous lease guidance by requiring the recognition of a right-to-use asset and lease liability on the statement of financial position for those leases previously classified as operating leases under the old guidance. In addition, ASU 2016-02 updates the criteria for a lessee’s classification of a finance lease. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In 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 on a retrospective basis. 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 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. In August 2015, the FASB issued ASU 2015-15, “Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.” The guidance in ASU 2015-03 does not address debt issuance costs related to line-of-credit arrangements. ASU 2015-15 states given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements, the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. During the first quarter of 2016, the Partnership adopted ASU 2015-03 and ASU 2015-15 retrospectively to the comparable periods in this Form 10-K. Adoption of this guidance affected the balance sheets as of December 31, 2015 as follows (in thousands): Decrease in Long term debt, net of debt issuance costs of approximately $2,091 Decrease in Debt issuance costs (Other Assets) of approximately $2,091 In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” In March, April, and May of 2016, the FASB issued rules clarifying several aspects of the new revenue recognition standard. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The Partnership will not early adopt the standard although early adoption is permitted. The Partnership is currently evaluating whether to apply the retrospective approach or modified retrospective approach with the cumulative effect recognized as of the date of initial application. The Partnership is currently evaluating the impact the standard is expected to have on its consolidated financial statements by evaluating current revenue streams and evaluating contracts under the revised standards. 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. In accordance with ASU No. 2015-03 and ASU No. 2015-15, debt issuance costs are to 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. As such, debt issuance costs, net of amortization, at December 31, 2015 of $2.1 million have been reclassified from other assets to other liabilities, effectively eliminating the debt issuance cost line and reducing long-term debt in the balance sheet.
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 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.
Restricted Cash	Restricted Cash We had no restricted cash as of December 31, 2016. At December 31, 2015, we had restricted cash of $0.6 million held in escrow related to a vendor dispute, which 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. Our allowance for doubtful accounts was $0.4 million as of December 31, 2016 and 2015.
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 Agreement 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 as of December 31, 2016 and 2015. We have no off-balance-sheet credit exposure related to our operations or customers. For the years ended December 31, 2016 and 2015, two customers accounted for 10% or more of our total revenue. Sanchez Energy, whose earned revenues contribute exclusively to our midstream segment, accounted for 76% and 17% of total revenue for the years ended December 31, 2016 and 2015, respectively. During that same time period, Macquarie Cook Energy, LLC, whose earned revenues contribute exclusively to our production segment, accounted for approximately 6% and 17% of our total revenue, respectively.
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. 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 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 as either short-term or long-term assets or liabilities based on their anticipated settlement date. 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.”
Revenue Recognition	Revenue Recognition Sales are recognized when oil, natural gas and NGLs 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 were no gas imbalance positions as of December 31, 2016, and an immaterial gas imbalance on one of our wells in the Mid-continent region at December 31, 2015. 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. Our wholly-owned subsidiary, CEP Services Company, Inc. is a taxable entity. For the years ended December 31, 2016, and 2015, 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. For the years ended December 31, 2016 and 2015, we had no environmental liabilities recorded, as no liabilities were deemed necessary.
Unit-Based Compensation	Unit-Based Compensation The Partnership records stock-based compensation expense for awards granted to its directors (for their services as directors) in accordance with the provisions of Accounting Standards Codification (“ASC”) Topic 718, “Compensation—Stock Compensation.” Stock-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method. Unit-based compensation granted to employees of SOG (including those employees who also serve as the officers of our general partner) and consultants in exchange for services are considered awards to non-employees and the Partnership records unit-based compensation expense for these awards at fair value in accordance with the provisions of ASC 505-50, “Equity-Based Payments to Non-Employees.” For awards granted to non-employees, the Partnership records compensation expenses equal to the fair value of the unit-based award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. Compensation expense for unvested awards to non-employees is revalued at each period end and is amortized over the vesting period of the unit-based award. Unit-based payments are measured based on the fair value of the equity instruments granted, as it is more determinable than the value of the services rendered. In accordance with the guidance, the inclusion of market performance acceleration conditions does not change the accounting classification as compared to those awards without market performance acceleration conditions. Compensation expense for the unvested awards is revalued at each period end and is amortized over the vesting period of the stock-based award.
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 and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2016
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 Revenues $ Net loss attributable to common unitholders $ Net loss per unit prior to conversion Class A units - Basic and diluted $ Class B units - Basic and diluted $ Net loss per unit after conversion Common units - Basic and diluted $
Post-Acquisition Operating Results	Direct operating expenses include lease operating expenses and production and ad valorem taxes (in thousands): Year Ended December 31, 2016 Revenues $ Excess of revenues over direct operating expenses $
Acquisition of Working Interests
Business Acquisition [Line Items]
Estimated Values Of Assets Purchased 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 $ Fair value of assets acquired Asset retirement obligations Fair value of net assets acquired $
Acquisition of Wellbore Interests
Business Acquisition [Line Items]
Estimated Values Of Assets Purchased 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
Business Acquisition [Line Items]
Estimated Values Of Assets Purchased 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, 2016
Fair Value Measurements
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, 2016 (in thousands): Fair Value Measurements at December 31, 2016 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Netting Cash and Fair Value at (Level 1) (Level 2) (Level 3) Collateral December 31, 2016 Derivative assets $ — $ $ — $ — $ 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, 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 $ — $ $ — $ — $ Embedded derivative — — — 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) December 31, 2016 2015 Beginning balance $ $ — Initial fair value of embedded derivative - bifurcated from mezzanine equity — Gain (loss) on embedded derivative Transfer to mezzanine equity — Ending balance $ — $ Loss included in earnings related to derivatives still held as of December 31, 2016 and 2015 $ — $
Non-Recurring Fair Value Measurements Of Assets And Liabilities	The following table summarizes the non-recurring fair value measurements of our assets and liabilities as of December 31, 2016 (in thousands): Fair Value Measurements at December 31, 2016 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Impairment (a) $ — $ — $ Acquisitions (b) — — Total net assets $ — $ — $ (a) During the year ended December 31, 2016, we recorded a non-cash impairment charge of $7.6 million to impair our producing oil and natural gas properties in Texas and Louisiana (acquired prior to the Eagle Ford Acquisition) and in Oklahoma . The carrying values of the impaired proved properties were reduced to a fair value of $10.7 million, estimated using inputs characteristic of a Level 3 fair value measurement. (b) During the year ended December 31, 2016, we acquired oil and natural gas properties with a fair value of $25.6 million. See Note 3. “Acquisitions and Divestitures” for fair value allocation. The following table summarizes the non-recurring fair value measurements of our assets and liabilities as of December 31, 2015 (in thousands): Fair Value Measurements at December 31, 2015 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Impairment (a) $ — $ — $ Acquisitions (b) — — Total net assets $ — $ — $ (a) For the year ended December 31, 2015, we recorded a non-cash impairment charge 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) . The carrying values of the impaired proved properties were reduced to a fair value of $81.0 million, estimated using inputs characteristic of a Level 3 fair value measurement. (b) During the year ended December 31, 2015, we acquired oil and natural gas properties and midstream assets with a combined fair value of $429.2 million. See Note 3. “Acquisitions and Divestitures” for fair value allocation.

Derivative And Financial Inst32

Derivative And Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative And Financial Instruments
Summary Of Derivative Contracts In Place	MTM Fixed Price Swaps – NYMEX (Henry Hub) For the Year Ended December 31, (volume in MMBtu) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2017 $ $ $ $ $ 2018 $ $ $ $ $ 2019 $ $ $ $ $ 2020 $ $ $ $ $ MTM Fixed Price Basis Swaps – West Texas Intermediate (WTI) For the Year Ended December 31, (volume 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 2017 $ $ $ $ $ 2018 $ $ $ $ $ 2019 $ $ $ $ $ 2020 $ $ $ $ $
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 years ended December 31, 2016 and 2015 (in thousands): December 31, 2016 2015 Beginning fair value of commodity derivatives $ $ Net gains (losses) on crude oil derivatives Net gains on natural gas derivatives Net settlements on derivative contracts: Crude oil Natural gas Net premiums on derivative contracts — 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): Location of Gain(Loss) Year Ended December 31, Derivative Type in Income 2016 2015 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 years ended December 31, 2016 and 2015 (in thousands): December 31, 2016 2015 Beginning fair value of embedded derivative $ $ — Initial fair value of embedded derivative - bifurcated from mezzanine equity — Gain (loss) on embedded derivative Transfer to mezzanine equity — Ending fair value of embedded derivative $ — $

Oil And Natural Gas Propertie33

Oil And Natural Gas Properties And Related Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Oil And Natural Gas Properties And Related Equipment.
Gathering and Transportation Assets	Gathering and transportation assets consist of the following (in thousands): December 31, 2016 2015 Gathering and transportation assets Midstream assets $ $ Less: Accumulated depreciation and amortization Total gathering and transportation assets $ $
Oil and Natural Gas Properties	Oil and natural gas properties consist of the following (in thousands): December 31, 2016 2015 Oil and natural gas properties and related equipment 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 $ $
Depreciation, Depletion, Amortization and Impairments	Depreciation, depletion, amortization and impairments consisted of the following (in thousands): Year Ended December 31, 2016 2015 Depreciation, depletion and amortization of oil and natural gas-related assets $ $ Depreciation, depletion and amortization of gathering and transportation related assets Total Depreciation, depletion and amortization Asset impairments Total $ $

Provision For Income Taxes (Tab

Provision For Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Provision For Income Taxes
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 Years Ended December 31, 2016 2015 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 Years Ended December 31, 2016 2015 Pre-tax net book income (loss) $ $ 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): December 31, 2016 2015 Deferred tax assets (liabilities): Derivative assets $ $ Depreciable, depletable property, plant and equipment Other — Deferred tax assets: Valuation allowance Total Deferred tax assets $ — $ —

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation
Reconciliation of Asset Retirement Obligation	The following table is a reconciliation of the ARO (in thousands): December 31, 2016 2015 Asset retirement obligation, beginning balance $ $ Liabilities added from acquisitions Sold Revisions to cost estimates Settlements Accretion expense Asset retirement obligation, ending balance $ $

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2016
Intangible Assets
Intangible assets	Intangible assets as of December 31, 2016 and 2015 are detailed below (in thousands): December 31, 2016 2015 Beginning balance $ $ Additions — Disposals — Amortization Ending balance $ $

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
Unit-Based Compensation
Schedule Of Units Activity	Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2014 $ Granted (1) Vested (1) Returned/Cancelled (1) Outstanding at December 31, 2015 Granted Vested Returned/Cancelled Outstanding at December 31, 2016 $ (1)

Distributions To Unitholders (T

Distributions To Unitholders (Tables)	12 Months Ended
	Dec. 31, 2016
Common Units
Schedule of payment of cash distributions	The table below reflects the payment of cash distributions on common units during the years ended December 31, 2016 and 2015. Distribution Date of Date of Date of Three months ended per unit declaration record distribution September 30, 2015 $ November 10, 2016 November 20, 2015 November 30, 2015 December 31, 2015 $ February 9, 2016 February 19, 2016 February 29, 2016 March 31, 2016 $ May 10, 2016 May 20, 2016 May 31, 2016 June 30, 2016 $ August 10, 2016 August 22, 2016 August 31, 2016 September 30, 2016 $ October 31, 2016 November 10, 2016 November 30, 2016 December 31, 2016 $ February 9, 2017 February 20, 2017 February 28, 2017
Class B Preferred
Schedule of payment of cash distributions	Distribution Date of Date of Date of Three months ended per unit declaration record distribution September 30, 2015 $ November 10, 2016 November 20, 2015 November 30, 2015 December 31, 2015 $ February 9, 2016 February 19, 2016 February 29, 2016 March 31, 2016 $ May 10, 2016 May 20, 2016 May 31, 2016 June 30, 2016 $ August 10, 2016 August 22, 2016 August 31, 2016 September 30, 2016 $ October 31, 2016 November 10, 2016 November 30, 2016 December 31, 2016 $ February 9, 2017 February 20, 2017 February 28, 2017 The table below reflects the payment of distributions on Class B preferred units during the years ended December 31, 2016 and 2015. Cash distribution Date of Date of Date of Three months ended per unit declaration record distribution December 31, 2015 $ February 9, 2016 February 19, 2016 February 29, 2016 March 31, 2016 $ May 10, 2016 May 20, 2016 May 31, 2016 June 30, 2016 $ August 10, 2016 August 22, 2016 August 31, 2016 September 30, 2016 $ October 31, 2016 November 10, 2016 November 30, 2016 December 31, 2016 (a) $ February 9, 2017 February 20, 2017 February 28, 2017 The Partnership elected to pay the fourth quarter 2016 distribution on the Class B preferred units in part cash and, with the consent of the Class B preferred unitholder, in part common units (in lieu of additional Class B preferred units). Accordingly, the Partnership declared a cash distribution of $0.2258 per Class B preferred unit and an aggregate distribution of 208,594 common units, each paid on February 28, 2017 to holders of record on February 20, 2017.

Members' Equity_Partners' Cap39

Members' Equity/Partners' Capital (Tables)	12 Months Ended
	Dec. 31, 2016
Members' Equity/Partners' Capital
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): December 31, 2016 2015 Mezzanine equity beginning balance $ $ — Private placement of Class B Preferred Units — Discount Amortization of discount Distributions Distributions paid — Transfer embedded derivative to Class B — Total mezzanine equity $ $
Schedule of Weighted Average Basic and Diluted Units Outstanding	Year Ended December 31, March 6 - December 31 January 1 - March 6 2016 2015 2015 Class A units - Basic and Diluted — — Class B Common units - Basic and Diluted — — Common units - Basic and Diluted — Weighted Common units - Basic and Diluted
Loss Per Unit Amounts	The following table presents our basic and diluted loss per unit for the year ended December 31, 2016 (in thousands, except for per unit amounts): Total Common Units Assumed net loss to be allocated $ $ 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 $ $ 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 $

Reporting Segments (Tables)

Reporting Segments (Tables)	12 Months Ended
	Dec. 31, 2016
Reporting Segments
Schedule of Segment Information	The following tables set forth our segment information for the periods indicated (in thousands): For the Year Ended December 31, 2016 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 Unit compensation expense — Loss on sale of assets — Depreciation, depletion and amortization Asset impairments — Accretion expense Total operating expenses Operating income (loss) $ $ $ For the Year Ended December 31, 2015 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 — Unit-based compensation expense — Exploration costs — Loss on sale of assets — Depreciation, depletion and amortization Asset impairments — Accretion expense Total operating expenses Operating income (loss) $ $ $
Summary of Total Assets by Operating Segment	The following table summarizes the total assets by operating segment as of December 31, 2016 and 2015 (in thousands): December 31, 2016 2015 Segment Assets Production $ $ Midstream Total assets $ $
Summary of Percentage of Revenue Earned from Customers by Segment	For the Years Ended December 31, 2016 2015 Production Macquarie Cook Energy, LLC. % % All other Midstream Sanchez Energy % % Total % %

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2016
Variable Interest Entities
Schedule of Carrying Amounts of Assets and Liabilities of Variable Interest Entity	Below is a tabular comparison of the carrying amounts of the assets and liabilities of the VIE and the Partnership’s maximum exposure to loss as of December 31, 2016 and 2015 (in thousands): December 31, 2016 2015 Capital investments $ $ — Earnings in equity investments — Distributions received — Estimated earnout accrued — Equity in equity investments $ $ — December 31, 2016 2015 Equity in equity investments $ $ — Guarantees of capital investments — Maximum exposure to loss $ $ —

Supplemental Information On O42

Supplemental Information On Oil And Natural Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2016
Supplemental Information On Oil And Natural Gas Producing Activities
Schedule Of Capitalized Costs	The following table sets forth our capitalized costs as of December 31, 2016 and 2015 (in thousands): December 31, 2016 2015 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, 2016 and 2015 (in thousands): For the Years Ended December 31, 2016 2015 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, 2014 Extensions and discoveries — — Puchase of reserves in place Revisions of previous estimates Production December 31, 2015 Purchase of reserves in place Sales of reserves in place — Revisions of previous estimates Production December 31, 2016 Proved developed reserves: December 31, 2015 December 31, 2016 Proved undeveloped reserves: December 31, 2015 — December 31, 2016 — — — —
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 Years Ended December 31, 2016 2015 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 Years Ended December 31, 2016 2015 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 Changes in development costs Changes in extensions and discoveries — Revisions of previous quantity estimates Purchases and sales of reserves in place Accretion discount Change in production rates, timing, and other Standardized measure of discounted future net cash flows related to proved gas reserves $ $

Organization And Business (Deta

Organization And Business (Details) $ in Thousands	Jul. 05, 2016	Nov. 30, 2016USD ($)itemshares	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)shares	Jul. 31, 2016
Units, issued			13,447,749	3,240,813
Proceeds from common units sold | $			$ 99,196	$ 193
IPO
Units, issued		6,745,107
Proceeds from common units sold | $		$ 69,700
Private Placement
Units, issued		2,272,727
Proceeds from common units sold | $		$ 25,000
Over-Allotment Option
Units, issued		194,305
Carnero Gathering LLC, Joint Venture
Gathering and processing agreement term	15 years
Ownership interest (as a percent)	50.00%				50.00%
Sanchez Energy Corporation
Gathering and processing agreement term			15 years
Sanchez Energy Corporation | Acquisition of Wellbore Interests
Producing wellbores | item		23
Sanchez Energy Corporation | Acquisition of Working Interests
Producing wellbores | item		11

Basis Of Presentation And Sum44

Basis Of Presentation And Summary Of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2016USD ($)segmentcustomeritemshares	Dec. 31, 2015USD ($)itemshares
Number of operating segments | segment	2
Amortization of debt issuance costs	$ 507,000	$ 1,338,000
Restricted unvested common units granted and outstanding | shares	219,144	361,357
Restricted cash	$ 0	$ 600,000
Allowance for doubtful accounts	$ 400,000	$ 400,000
Number of large customers | item	2	2
Gas Balancing Asset (Liability)	$ 0
Environmental liabilities	$ 0	$ 0
Oil
Trade accounts receivable, general collection period after month end	30 days
Natural Gas
Trade accounts receivable, general collection period after month end	60 days
Minimum | Furniture and Equipment
Useful life	3 years
Maximum
Number of large customers | customer	10
Maximum | Furniture and Equipment
Useful life	15 years
Maximum | Gathering Facilities
Useful life	36 years
Sales | Customer Concentration Risk | Sanchez Energy Corporation
Percentage of sales revenue	76.00%	17.00%
Sales | Customer Concentration Risk | Macquarie Cook Energy LLC
Percentage of sales revenue	6.00%	17.00%
Accounting Standards Update 2015-03 | Scenario, Adjustment
Long term debt, net of debt issuance costs		$ (2,091,000)
Amortization of debt issuance costs		(2,091,000)
Other assets		(2,100,000)
Other liabilities		$ 2,100,000

Acquisitions and Divestitures45

Acquisitions and Divestitures (Details)	Nov. 22, 2016USD ($)item	Jul. 05, 2016USD ($)	Jun. 15, 2016USD ($)	Oct. 14, 2015USD ($)shares	Apr. 15, 2015USD ($)$ / shares	Mar. 31, 2015USD ($)$ / sharesshares	Jul. 31, 2016USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2016USD ($)
Carnero Processing Acquisition
Business Acquisition [Line Items]
Acquisition membership interest (as percent)	50.00%
Cash payment for acquisition	$ 55,500,000
Capital contribution commitments	24,500,000
Carnero Gathering
Business Acquisition [Line Items]
Acquisition membership interest (as percent)		50.00%
Cash payment for acquisition		$ 37,000,000
Capital contribution commitments		$ 7,400,000						$ 3,300,000
Eagle Ford
Business Acquisition [Line Items]
Cash payment for acquisition						$ 83,400,000
Initial purchase price						85,000,000
Purchase price	$ 26,454,000					$ 84,299,000
Western Catarina Midstream
Business Acquisition [Line Items]
Cash payment for acquisition				$ 345,800,000
Repurchase of units (in units) | shares				105,263
Purchase price				$ 345,840,000
Class A Preferred
Business Acquisition [Line Items]
Price per unit sold | $ / shares					$ 1.60	$ 1.60
Proceeds from preferred units sold					$ 375,000	$ 17,000,000
Class A Preferred | Eagle Ford
Business Acquisition [Line Items]
Shares issued | shares						10,625,000
Price per unit sold | $ / shares						$ 1.60
Proceeds from preferred units sold						$ 17,000,000
Common Units | Eagle Ford
Business Acquisition [Line Items]
Shares issued | shares						105,263
Prior To Stock Split | Common Units | Eagle Ford
Business Acquisition [Line Items]
Shares issued | shares						1,052,632
Carnero Gathering LLC, Joint Venture
Business Acquisition [Line Items]
Ownership interest (as a percent)		50.00%					50.00%
Payments to acquire interest in joint venture		$ 37,000,000					$ 37,000,000
Assumption of capital commitments in joint venture		$ 7,400,000					$ 7,400,000	$ 4,300,000	$ 4,300,000
Payments of capital commitments from joint venture									$ 3,300,000
TPL South Tex Processing Company LP
Business Acquisition [Line Items]
Ownership interest (as a percent)	50.00%	50.00%
SN Cotulla Assets, LLC and SN Palmetto, LLC
Business Acquisition [Line Items]
Producing wellbores | item	23
SN Cotulla Assets, LLC and SN Palmetto, LLC | Eagle Ford
Business Acquisition [Line Items]
Cash payment for acquisition	$ 25,600,000
Closing adjustments	$ 1,400,000
Producing wellbores | item	11
Gateway Resources U.S.A., Inc.
Business Acquisition [Line Items]
Proceeds from divestiture of business			$ 7,120
Loss on disposition of intangible assets			$ 200,000

Acquisitions and Divestitures46

Acquisitions and Divestitures (Value Net Assets Acquired) (Details) - USD ($) $ in Thousands	Nov. 22, 2016	Oct. 14, 2015	Mar. 31, 2015
Eagle Ford
Business Acquisition [Line Items]
Proved developed reserves	$ 26,454		$ 72,889
Facilities			8,002
Fair value of hedges assumed			3,408
Fair value of assets acquired	26,454		84,299
Asset retirement obligations	(832)		(877)
Ad valorem tax liability			(44)
Fair value of net assets acquired	$ 25,622		$ 83,378
Western Catarina Midstream
Business Acquisition [Line Items]
Fixed assets		$ 142,887
Contractual customer relationships		201,888
Purchase of SPP common units from SN		1,065
Fair value of assets acquired		$ 345,840

Acquisitions and Divestitures47

Acquisitions and Divestitures (Pro Forma) (Details) $ / shares in Units, $ in Thousands	Mar. 31, 2016	Aug. 03, 2015	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)$ / shares
Business Acquisition [Line Items]
Earnings in equity investments			$ 2,382	$ 81
Reverse stock split ratio		0.1
Eagle Ford
Business Acquisition [Line Items]
Revenues				105,204
Net loss attributable to common unitholders				$ (157,161)
Revenues, actual			64,243
Excess of revenues over direct operating expenses, actual			47,444
Class A Units | Eagle Ford
Business Acquisition [Line Items]
Net loss - pro forma basic and diluted (in dollars per unit) | $ / shares				$ (17.72)
Class B Units | Eagle Ford
Business Acquisition [Line Items]
Net loss - pro forma basic and diluted (in dollars per unit) | $ / shares				(14.10)
Common Units
Business Acquisition [Line Items]
Reverse stock split ratio		0.1
Common Units | Eagle Ford
Business Acquisition [Line Items]
Net loss - pro forma basic and diluted (in dollars per unit) | $ / shares				$ (40.32)
Class A Preferred
Business Acquisition [Line Items]
Reverse stock split ratio	1
Carnero Gathering LLC, Joint Venture
Business Acquisition [Line Items]
Earnings in equity investments			$ 2,800

Fair Value Measurements (Recurr

Fair Value Measurements (Recurring) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Embedded derivative		$ (193,077)
Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	6,436	31,018
Embedded derivative		(193,077)
Total net assets	6,436	(162,059)
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	6,436	31,018
Total net assets	$ 6,436	31,018
Fair Value, Inputs, Level 3
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 (Non-Re

Fair Value Measurements (Non-Recurring) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Asset impairments	$ 7,646	$ 123,860
Fair Value, Inputs, Level 3 | Nonrecurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment	10,733	80,977
Acquisitions	25,622	429,218
Total net assets	$ 36,355	$ 510,195

Fair Value Measurements (Embedd

Fair Value Measurements (Embedded Derivative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Fair Value Measurements
Beginning Balance	$ (193,077)
Initial fair value of embedded derivative - bifurcated from mezzanine equity		(183,095)
Gain on embedded derivative	47,794
(Loss) on embedded derivative		(9,982)
Transfer to mezzanine equity	145,283
Ending Balance		(193,077)
Loss on embedded derivative	$ 47,794	$ (9,982)

Derivative And Financial Inst51

Derivative And Financial Instruments (Hedges In Place) (Details)	12 Months Ended
	Dec. 31, 2016MMBTU$ / MMBTU$ / bblbbl
West Texas Intermediate 2017 Swap Quarter 1
Derivative [Line Items]
Volume (in Bbls) | bbl	102,339
Average Price | $ / bbl	61.03
West Texas Intermediate 2017 Swap Quarter 2
Derivative [Line Items]
Volume (in Bbls) | bbl	94,005
Average Price | $ / bbl	61.25
West Texas Intermediate 2017 Swap Quarter 3
Derivative [Line Items]
Volume (in Bbls) | bbl	87,304
Average Price | $ / bbl	61.42
West Texas Intermediate 2017 Swap Quarter 4
Derivative [Line Items]
Volume (in Bbls) | bbl	81,702
Average Price | $ / bbl	61.55
West Texas Intermediate 2017
Derivative [Line Items]
Volume (in Bbls) | bbl	365,350
Average Price | $ / bbl	61.30
West Texas Intermediate 2018 Swap Quarter 1
Derivative [Line Items]
Volume (in Bbls) | bbl	88,854
Average Price | $ / bbl	60.82
West Texas Intermediate 2018 Swap Quarter 2
Derivative [Line Items]
Volume (in Bbls) | bbl	83,976
Average Price | $ / bbl	60.90
West Texas Intermediate 2018 Swap Quarter 3
Derivative [Line Items]
Volume (in Bbls) | bbl	79,683
Average Price | $ / bbl	60.96
West Texas Intermediate 2018 Swap Quarter 4
Derivative [Line Items]
Volume (in Bbls) | bbl	75,864
Average Price | $ / bbl	61.02
West Texas Intermediate 2018
Derivative [Line Items]
Volume (in Bbls) | bbl	328,377
Average Price | $ / bbl	60.92
West Texas Intermediate 2019 Swap Quarter 1
Derivative [Line Items]
Volume (in Bbls) | bbl	78,667
Average Price | $ / bbl	61.48
West Texas Intermediate 2019 Swap Quarter 2
Derivative [Line Items]
Volume (in Bbls) | bbl	75,326
Average Price | $ / bbl	61.53
West Texas Intermediate 2019 Swap Quarter 3
Derivative [Line Items]
Volume (in Bbls) | bbl	72,279
Average Price | $ / bbl	61.57
West Texas Intermediate 2019 Swap Quarter 4
Derivative [Line Items]
Volume (in Bbls) | bbl	69,480
Average Price | $ / bbl	61.61
West Texas Intermediate 2019
Derivative [Line Items]
Volume (in Bbls) | bbl	295,752
Average Price | $ / bbl	61.54
West Texas Intermediate 2020 Swap Quarter 1
Derivative [Line Items]
Volume (in Bbls) | bbl	66,914
Average Price | $ / bbl	53.50
West Texas Intermediate 2020 Swap Quarter 2
Derivative [Line Items]
Volume (in Bbls) | bbl	64,477
Average Price | $ / bbl	53.50
West Texas Intermediate 2020 Swap Quarter 3
Derivative [Line Items]
Volume (in Bbls) | bbl	62,251
Average Price | $ / bbl	53.50
West Texas Intermediate 2020 Swap Quarter 4
Derivative [Line Items]
Volume (in Bbls) | bbl	60,224
Average Price | $ / bbl	53.50
West Texas Intermediate 2020
Derivative [Line Items]
Volume (in Bbls) | bbl	253,866
Average Price | $ / bbl	53.50
West Texas Intermediate
Derivative [Line Items]
Volume (in Bbls) | bbl	1,243,345
NYMEX 2017 Swap Quarter 1
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	309,181
Average Price | $ / MMBTU	5.42
NYMEX 2017 Swap Quarter 2
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	287,439
Average Price | $ / MMBTU	5.45
NYMEX 2017 Swap Quarter 3
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	271,368
Average Price | $ / MMBTU	5.45
NYMEX 2017 Swap Quarter 4
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	257,234
Average Price | $ / MMBTU	5.45
NYMEX 2,017
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	1,125,222
Average Price | $ / MMBTU	5.44
NYMEX 2018 Swap Quarter 1
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	260,841
Average Price | $ / MMBTU	3.18
NYMEX 2018 Swap Quarter 2
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	248,018
Average Price | $ / MMBTU	3.18
NYMEX 2018 Swap Quarter 3
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	235,810
Average Price | $ / MMBTU	3.18
NYMEX 2018 Swap Quarter 4
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	225,208
Average Price | $ / MMBTU	3.18
NYMEX 2,018
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	969,877
Average Price | $ / MMBTU	3.18
NYMEX 2019 Swap Quarter 1
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	224,303
Average Price | $ / MMBTU	3.10
NYMEX 2019 Swap Quarter 2
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	214,186
Average Price | $ / MMBTU	3.10
NYMEX 2019 Swap Quarter 3
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	205,533
Average Price | $ / MMBTU	3.10
NYMEX 2019 Swap Quarter 4
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	197,455
Average Price | $ / MMBTU	3.10
NYMEX 2,019
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	841,477
Average Price | $ / MMBTU	3.10
NYMEX 2020 Swap Quarter 1
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	188,696
Average Price | $ / MMBTU	2.85
NYMEX 2020 Swap Quarter 2
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	176,946
Average Price | $ / MMBTU	2.85
NYMEX 2020 Swap Quarter 3
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	170,637
Average Price | $ / MMBTU	2.85
NYMEX 2020 Swap Quarter 4
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	164,747
Average Price | $ / MMBTU	2.85
NYMEX 2,020
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	701,026
Average Price | $ / MMBTU	2.85
NYMEX
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	3,637,602

Derivative And Financial Inst52

Derivative And Financial Instruments (Changes In Fair Value) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)item	Dec. 31, 2015USD ($)
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	$ (7,239)	$ 25,149
Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Beginning fair value of commodity derivatives	31,018	22,829
Net premiums on derivative contracts	3,197
Ending fair value of commodity derivatives	$ 6,435	31,018
Number of counterparties | item	4
Oil | Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	$ (8,355)	22,410
Net settlements on derivative contracts	(13,622)	(13,191)
Oil | Oil And Liquids Sales
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	(8,355)	19,146
Natural Gas | Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	1,116	6,148
Net settlements on derivative contracts	(6,919)	(7,178)
Natural Gas | Natural Gas Sales
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	$ 1,116	$ 6,003

Derivative And Financial Inst53

Derivative And Financial Instruments (Eagle Ford) (Details) - Eagle Ford - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Oil and natural gas production, 2016	95.00%
Oil and natural gas production, 2017	90.00%
Oil and natural gas production, 2018	85.00%
Oil and natural gas production, 2019	85.00%
Oil and natural gas production, 2020	80.00%
Fair value of derivative instruments	$ 6.4	$ 15

Derivative And Financial Inst54

Derivative And Financial Instruments (Embedded Derivative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Derivative And Financial Instruments
Beginning Balance	$ (193,077)
Initial fair value of embedded derivative - bifurcated from mezzanine equity		(183,095)
Loss on embedded derivative	47,794	(9,982)
Transfer to mezzanine equity	145,283
Ending Balance		$ (193,077)

Long-Term Debt (Details)

Long-Term Debt (Details)	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Line of Credit Facility [Line Items]
Outstanding debt under reserve-based credit facility	$ 151,322,000	$ 104,909,000
Unamortized debt issue costs	1,700,000	2,100,000
Amortization of debt issuance costs	507,000	$ 1,338,000
Credit Agreement
Line of Credit Facility [Line Items]
Maximum borrowing capacity	500,000,000
Initial borrowing capacity	200,000,000
Sub-limit which may be used for issuance of letters of credit	$ 15,000,000
Commitment fee on unutilized borrowing base	0.50%
Credit Agreement | Scenario Two
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4
Minimum | Credit Agreement
Line of Credit Facility [Line Items]
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 | Credit Agreement | London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Variable interest rate	2.25%
Minimum | Credit Agreement | ABR
Line of Credit Facility [Line Items]
Variable interest rate	1.25%
Maximum | Credit Agreement | Scenario One
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4.5
Maximum | Credit Agreement | London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Variable interest rate	3.25%
Maximum | Credit Agreement | ABR
Line of Credit Facility [Line Items]
Variable interest rate	2.25%
Western Catarina Midstream | Credit Agreement | Scenario One
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	5
Western Catarina Midstream | Credit Agreement | Scenario Two
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4.75
Western Catarina Midstream | Credit Agreement | Scenario Three
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4.5

Oil And Natural Gas Propertie56

Oil And Natural Gas Properties And Related Equipment (Gathering and Transportation Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Gathering and transportation assets	$ 152,209	$ 147,479
Less: Accumulated depreciation, depletion, amortization and impairments	(674,338)	(652,167)
Midstream
Property, Plant and Equipment [Line Items]
Gathering and transportation assets	152,209	147,479
Less: Accumulated depreciation, depletion, amortization and impairments	(15,020)	(1,402)
Total gathering and transportation assets	$ 137,189	$ 146,077

Oil And Natural Gas Propertie57

Oil And Natural Gas Properties And Related Equipment (Properties) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Oil And Natural Gas Properties And Related Equipment.
Proved property	$ 758,366	$ 731,548
Unproved property	46	39
Land	501	501
Total property costs	758,913	732,088
Materials and supplies	1,056	1,056
Total	759,969	733,144
Less: Accumulated depreciation, depletion, amortization and impairments	(674,338)	(652,167)
Oil and natural gas properties and equipment, net	$ 85,631	$ 80,977

Oil And Natural Gas Propertie58

Oil And Natural Gas Properties And Related Equipment (DDA and Impairments) (Details) - USD ($) $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Mar. 05, 2015	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization			$ 21,900	$ 13,250
Asset impairments	$ 0	$ 123,800	7,646	123,860
Total			41,445	138,396
Impairments of unproved properties				1,866
Exploration and dry hole costs			$ 0	0
Exploration costs				1,866
Furniture and Equipment | Minimum
Property, Plant and Equipment [Line Items]
Useful lives			3 years
Furniture and Equipment | Maximum
Property, Plant and Equipment [Line Items]
Useful lives			15 years
Gathering Facilities | Maximum
Property, Plant and Equipment [Line Items]
Useful lives			36 years
Oil and Natural Gas-Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization			$ 6,722	10,330
Gathering and Transportation Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization			27,077	4,206
Oil and Natural Gas-Related Assets and Gathering and Transportation-Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization			$ 33,799	$ 14,536

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 income taxes	$ 55

Provision For Income Taxes (Rec

Provision For Income Taxes (Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Provision For Income Taxes
Pre-tax net book income (loss)	$ 19,231	$ (137,001)
Texas Margin Tax	255	(780)
Return to accrual		55
Valuation allowance	$ (255)	780
Total provision for income taxes		$ 55
Effective income tax rate	0.00%	(0.04%)

Provision For Income Taxes (DTA

Provision For Income Taxes (DTA and DTL) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Deferred tax assets (liabilities):
Derivative assets, liability	$ (230)	$ (63)
Depreciable, depletable property, plant and equipment	753	843
Other	2
Deferred tax assets:	525	780
Valuation allowance	$ (525)	$ (780)

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation
Asset retirement obligation, beginning balance	$ 20,364,000	$ 17,031,000
Liabilities added from acquisitions	912,000	3,634,000
Sold	(6,291,000)	(58,000)
Revisions to cost estimates	(2,399,000)	(1,156,000)
Settlements	(134,000)	(186,000)
Accretion expense	1,127,000	1,099,000
Asset retirement obligation, ending balance	13,579,000	20,364,000
Legally restricted assets	$ 0	$ 0

Intangible Assets (Details)

Intangible Assets (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)a	Dec. 31, 2015USD ($)
Finite-Lived Intangible Assets [Line Items]
Amortization expense	$ 13,756	$ 2,805
Balance	199,741	1,033
Additions		201,888
Disposals	(219)
Amortization	(13,756)	(3,180)
Balance	$ 185,766	$ 199,741
Customer Contracts
Finite-Lived Intangible Assets [Line Items]
Agreement term	15 years
Dedicated acreage | a	35,000
Useful life	15 years
Balance	$ 185,600
Marketing Contracts
Finite-Lived Intangible Assets [Line Items]
Amortization expense	$ 200

Investments (Details)

Investments (Details) - USD ($) $ in Thousands	Nov. 22, 2016	Jul. 05, 2016	Jul. 31, 2016	Dec. 31, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Capital investments				$ 107,320
Estimated earnout accrued				4,270
Earnings in equity investments				2,382	$ 81
Amortization of intangible asset				13,756	2,805
Cash distributions				6,696	$ 1,219
Carnero Gathering LLC, Joint Venture
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)		50.00%	50.00%
Payments to acquire interest in joint venture		$ 37,000	$ 37,000
Assumption of capital commitments in joint venture		$ 7,400	$ 7,400	4,300
Payments of capital commitments from joint venture				3,300
Capital investments				40,300
Agreement term		15 years
Estimated fair value of contingent consideration				4,300
Earnings in equity investments				2,800
Cash distributions				3,000
Carnero Gathering LLC, Joint Venture | Customer Relationships
Schedule of Equity Method Investments [Line Items]
Intangible asset, fair value		$ 13,000
Amortization of intangible asset				400
Carnero Processing Joint Venture
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)	50.00%
Payments to acquire interest in joint venture	$ 55,500
Assumption of capital commitments in joint venture	24,500			10,600
Payments of capital commitments from joint venture				10,500
Capital investments	$ 48,000			66,000
Earnings in equity investments				$ 100
TPL South Tex Processing Company LP
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)	50.00%	50.00%
SN Midstream | Carnero Gathering LLC, Joint Venture
Schedule of Equity Method Investments [Line Items]
Capital investments		$ 26,000

Related Party Transactions (Det

Related Party Transactions (Details) $ in Thousands	Nov. 22, 2016USD ($)	Jul. 05, 2016USD ($)	Oct. 14, 2015USD ($)aMcfbbl	Mar. 31, 2015USD ($)shares	Nov. 30, 2016USD ($)itemshares	Jul. 31, 2016USD ($)	Sep. 30, 2015USD ($)	Dec. 31, 2016USD ($)shares	Dec. 31, 2015USD ($)shares	Aug. 02, 2015shares
Related Party Transaction [Line Items]
Related parties, net receivable								$ 6,000	$ 1,500
Related parties, net payable								7,000	1,000
Cash payment for acquisition, net								$ 25,622	$ 427,218
Units, outstanding | shares								13,447,749	3,240,813
Proceeds from Issuance of Common Limited Partners Units								$ 99,196	$ 193
Sanchez Energy Corporation
Related Party Transaction [Line Items]
Agreement term								15 years
Payments to acquire interest in joint venture					$ 25,000
Assumption of capital commitments in joint venture					25,600
SP Holdings
Related Party Transaction [Line Items]
Administrative fee								$ 7,500	2,400
Agreement term								10 years
Services Agreement renewal term								10 years
Carnero Processing Joint Venture
Related Party Transaction [Line Items]
Ownership interest (as a percent)	50.00%
Payments to acquire interest in joint venture	$ 55,500
Assumption of capital commitments in joint venture	$ 24,500							$ 10,600
Carnero Processing Joint Venture | Sanchez Energy Corporation
Related Party Transaction [Line Items]
Payments to acquire interest in joint venture					55,500
Assumption of capital commitments in joint venture					$ 24,500
Carnero Gathering LLC, Joint Venture
Related Party Transaction [Line Items]
Agreement term		15 years
Ownership interest (as a percent)		50.00%				50.00%
Estimated fair value of contingent consideration								4,300
Payments to acquire interest in joint venture		$ 37,000				$ 37,000
Assumption of capital commitments in joint venture		$ 7,400				$ 7,400		4,300
TPL South Tex Processing Company LP
Related Party Transaction [Line Items]
Ownership interest (as a percent)	50.00%	50.00%
Eagle Ford
Related Party Transaction [Line Items]
Initial purchase price				$ 85,000
Cash payment for acquisition				83,400
Eagle Ford | Sanchez Energy Corporation
Related Party Transaction [Line Items]
Initial purchase price				85,000
Closing adjustments				1,400
Cash payment for acquisition, net				$ 81,600
Acquisition of Wellbore Interests | Sanchez Energy Corporation
Related Party Transaction [Line Items]
Producing wellbores | item					23
Acquisition of Working Interests | Sanchez Energy Corporation
Related Party Transaction [Line Items]
Producing wellbores | item					11
Western Catarina Midstream
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
Western Catarina Midstream | Oil
Related Party Transaction [Line Items]
Gathering Agreement minimum quarterly volume delivery commitment | bbl			10,200
Western Catarina Midstream | Natural Gas
Related Party Transaction [Line Items]
Gathering Agreement minimum quarterly volume delivery commitment | Mcf			142,000
Western Catarina Midstream | Sanchez Energy Corporation
Related Party Transaction [Line Items]
Agreement term							15 years
Proceeds from gathering and processing agreement								$ 50,100	7,500
Cash payment for acquisition							$ 345,800
Common Units
Related Party Transaction [Line Items]
Units, outstanding | shares										31,495,506
Proceeds from Issuance of Common Limited Partners Units									$ 100
Common Units | Sanchez Energy Corporation
Related Party Transaction [Line Items]
Shares repurchased | shares					2,272,727
Common Units | Eagle Ford
Related Party Transaction [Line Items]
Business acquisition, units issued | shares				105,263
Common Units | Eagle Ford | Sanchez Energy Corporation
Related Party Transaction [Line Items]
Business acquisition, units issued | shares				105,263
Business acquisition, value of units				$ 2,000

Unit-Based Compensation (Restri

Unit-Based Compensation (Restricted Units Activity) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding	361,357
Number of Restricted Units, Outstanding	219,144	361,357
LTIP
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding	219,144
Restricted Stock Units | 2009 Omnibus Incentive Compensation Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding	361,357	10,083
Common units granted	67,627	472,972
Number of Restricted Units, Vested	(195,613)	(87,872)
Number of Restricted Units, Returned/Cancelled	(14,227)	(33,826)
Number of Restricted Units, Outstanding	219,144	361,357
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	$ 14.18	$ 31.10
Weighted Averaged Grant Date Fair Value Per Unit, Granted	12.69	14.89
Weighted Averaged Grant Date Fair Value Per Unit, Vested	10.35	18.68
Weighted Averaged Grant Date Fair Value Per Unit, Returned/Cancelled	15.81	17.33
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding	$ 14.22	$ 14.18
Prior To Stock Split | Director
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Common units granted	67,627

Distributions To Unitholders (D

Distributions To Unitholders (Details)	Feb. 09, 2017shares	Dec. 31, 2016$ / sharesshares	Sep. 30, 2016$ / shares	Jun. 30, 2016$ / shares	Mar. 31, 2016$ / shares	Dec. 31, 2015$ / shares	Sep. 30, 2015$ / shares	Dec. 31, 2015shares
Paid-in-kind units distributed								843,989
Class A preferred units converted to common shares, conversion ratio		0.1
Common Units
Distribution paid per unit | $ / shares		$ 0.4310	$ 0.4246	$ 0.4183	$ 0.4121	$ 0.4060	$ 0.4000
Common Units | Subsequent Event
Aggregate distribution of units	208,594
Class B Preferred
Distribution paid per unit | $ / shares		$ 0.2258	$ 0.4500	$ 0.4500	$ 0.4500	$ 0.3815
Aggregate distribution of units		208,594

Members' Equity_Partners' Cap68

Members' Equity/Partners' Capital (Details)	Jan. 25, 2017$ / shares	Mar. 31, 2016	Oct. 14, 2015USD ($)$ / sharesshares	Aug. 03, 2015$ / sharesshares	Apr. 15, 2015USD ($)$ / sharesshares	Mar. 31, 2015USD ($)$ / sharesshares	Mar. 06, 2015	Nov. 30, 2016USD ($)shares	Sep. 30, 2016	Dec. 31, 2015USD ($)shares	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)shares	Dec. 06, 2016shares	Aug. 04, 2015$ / shares	Aug. 02, 2015shares	Apr. 30, 2015USD ($)
Limited Partners' Capital Account [Line Items]
Class A preferred units, outstanding										11,694,364	0	11,694,364
Class B preferred units, outstanding										19,444,445	29,296,441	19,444,445
Units, outstanding										3,240,813	13,447,749	3,240,813
Class A preferred units converted to common shares, conversion ratio											0.1
Restricted unvested common units granted and outstanding										361,357	219,144	361,357
Reverse stock split ratio				0.1
Proceeds from common units sold | $											$ 99,196,000	$ 193,000
Units, issued										3,240,813	13,447,749	3,240,813
LTIP
Limited Partners' Capital Account [Line Items]
Restricted unvested common units granted and outstanding											219,144
IPO
Limited Partners' Capital Account [Line Items]
Proceeds from common units sold | $								$ 69,700,000
Units, issued								6,745,107
Private Placement
Limited Partners' Capital Account [Line Items]
Proceeds from common units sold | $								$ 25,000,000
Units, issued								2,272,727
Over-Allotment Option
Limited Partners' Capital Account [Line Items]
Units, issued								194,305
Class A Preferred
Limited Partners' Capital Account [Line Items]
Class A preferred units, outstanding											0
Reverse stock split ratio		1
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
Aggregate cash distribution									14.00%
Increase in distribution rate										4.00%
Units, issued													9,851,996
Class B Preferred
Limited Partners' Capital Account [Line Items]
Class B preferred units, outstanding											29,296,441
Units sold (in units)			19,444,445
Price per unit sold | $ / shares			$ 18
Proceeds from preferred units sold | $			$ 350,000,000
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 B Preferred | Subsequent Event | Settlement Agreement with Stonepeak Catarina Holdings LLC [Member]
Limited Partners' Capital Account [Line Items]
Class B preferred units, unit price | $ / shares	$ 11.29
Class B Units
Limited Partners' Capital Account [Line Items]
Units, outstanding											13,447,749
Class B Units | Settlement Agreement with Stonepeak Catarina Holdings LLC [Member]
Limited Partners' Capital Account [Line Items]
Class B preferred units, unit price | $ / shares											$ 11.29
Common Units
Limited Partners' Capital Account [Line Items]
Units, outstanding															31,495,506
Percent of common units outstanding							2.00%
Common units sales agreement, value of common units allocated | $																$ 100,000,000
Reverse stock split ratio				0.1
Market price | $ / shares				$ 1.55										$ 15.50
Units sold (in units)											0	6,723
Proceeds from common units sold | $												$ 100,000
Units, issued				3,149,551
Minimum | Class A Preferred
Limited Partners' Capital Account [Line Items]
Proceeds from common units sold | $										$ 75,000,000
Minimum | Class B Preferred
Limited Partners' Capital Account [Line Items]
Preferred unit conversion, amount | $											$ 17,500,000
Cash from conversion | $											$ 75,000,000
Prior To Stock Split | Common Units
Limited Partners' Capital Account [Line Items]
Units sold (in units)												67,230

Members Equity Partners Capital

Members Equity Partners Capital (Class B Preferred Units) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Mezzanine equity beginning balance	$ 172,111
Distributions	37,168
Total mezzanine equity	342,991	$ 172,111
Class B Preferred
Mezzanine equity beginning balance	172,111
Private placement of Class B Preferred Units		350,000
Discount	(87)	(191,901)
Amortization of discount	23,477	6,594
Distributions	39,375	7,418
Distributions paid	(37,168)
Transfer embedded derivative to Class B	145,283
Total mezzanine equity	$ 342,991	$ 172,111

Members' Equity_Partners' Cap70

Members' Equity/Partners' Capital (EPU) (Details) - USD ($) $ / shares in Units, $ in Thousands	2 Months Ended	10 Months Ended	12 Months Ended
	Mar. 05, 2015	Dec. 31, 2015	Dec. 31, 2016	Dec. 31, 2015
Weighted Average Units Outstanding - Basic and diluted	2,927,614	3,071,587	4,658,970
Assumed net loss	$ (923)	$ (153,895)	$ (44,484)	$ (154,818)
Asset impairments	0	123,800	$ 7,646	$ 123,860
Class A Units
Weighted Average Units Outstanding - Basic and diluted				48,451
Assumed net loss	$ (18)
Net loss per unit - Basic and diluted	$ (0.38)			$ (0.38)
Class B Units
Weighted Average Units Outstanding - Basic and diluted				2,879,163
Assumed net loss	$ (905)
Net loss per unit - Basic and diluted	$ (0.31)			$ (0.31)
Common Units
Weighted Average Units Outstanding - Basic and diluted			4,658,970	3,071,587
Assumed net loss		$ (153,895)	$ (44,484)
Net loss per unit - Basic and diluted			$ (9.55)	$ (50.1)
Prior To Stock Split | Class A Units
Weighted Average Units Outstanding - Basic and diluted	48,451
Prior To Stock Split | Class B Units
Weighted Average Units Outstanding - Basic and diluted	2,879,163
Prior To Stock Split | Common Units
Weighted Average Units Outstanding - Basic and diluted		3,071,587	4,658,970
Net loss per unit - Basic and diluted		$ (50.10)

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, 2016	Dec. 31, 2015
Operating Revenues
Natural gas sales			$ 10,408	$ 19,809
Oil sales			5,138	35,297
Natural gas liquids sales			1,167	1,597
Gathering and transportation sales			53,972	11,725
Total revenues			70,685	68,428
Operating expenses:
Lease operating expenses			14,981	19,988
Transportation operating expenses			12,478	2,176
Cost of sales			328	595
Production taxes			1,167	1,792
General and administrative			22,901	23,655
Unit compensation expense			1,941	2,454
Exploration costs				1,866
Loss on sale of assets			219	(111)
Depreciation, depletion and amortization			33,799	14,536
Asset impairments	$ 0	$ 123,800	7,646	123,860
Accretion expense			1,127	1,099
Total operating expenses			96,587	191,910
Operating income (loss)			(25,902)	(123,482)
Upstream
Operating Revenues
Natural gas sales			10,408	19,809
Oil sales			5,138	35,297
Natural gas liquids sales			1,167	1,597
Total revenues			16,713	56,703
Operating expenses:
Lease operating expenses			14,327	19,890
Cost of sales			328	595
Production taxes			1,167	1,792
General and administrative			17,178	23,655
Unit compensation expense			1,941	2,454
Exploration costs				1,866
Loss on sale of assets			219	(111)
Depreciation, depletion and amortization			6,722	10,330
Asset impairments			7,646	123,860
Accretion expense			875	1,048
Total operating expenses			50,403	185,379
Operating income (loss)			(33,690)	(128,676)
Midstream
Operating Revenues
Gathering and transportation sales			53,972	11,725
Total revenues			53,972	11,725
Operating expenses:
Lease operating expenses			654	98
Transportation operating expenses			12,478	2,176
General and administrative			5,723
Depreciation, depletion and amortization			27,077	4,206
Accretion expense			252	51
Total operating expenses			46,184	6,531
Operating income (loss)			$ 7,788	$ 5,194

Reporting Segments (Assets by S

Reporting Segments (Assets by Segment) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 539,705	$ 471,300
Upstream
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	207,219	118,083
Midstream
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 332,486	$ 353,217

Reporting Segments (Percentage

Reporting Segments (Percentage of Revenue) (Details) - Revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Revenue, Major Customer [Line Items]
Percentage of revenue	100.00%	100.00%
Upstream | Macquarie Cook Energy LLC
Revenue, Major Customer [Line Items]
Percentage of revenue	6.00%	17.00%
Upstream | All Other
Revenue, Major Customer [Line Items]
Percentage of revenue	18.00%	66.00%
Midstream | Sanchez Energy Corporation
Revenue, Major Customer [Line Items]
Percentage of revenue	76.00%	17.00%

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Thousands	Nov. 22, 2016	Jul. 05, 2016	Jul. 31, 2016	Dec. 31, 2016	Dec. 31, 2015
Variable Interest Entity [Line Items]
Capital investments				$ 107,320
Earnings in Equity Investments				2,301
Distributions received				(2,950)	$ (47)
Estimated earnout accrued				4,270
Equity in equity investments				110,941
Guarantees of capital investments				17,584
Maximum exposure to loss				128,525
Carnero Processing Joint Venture
Variable Interest Entity [Line Items]
Ownership interest (as a percent)	50.00%
Payments to acquire interest in joint venture	$ 55,500
Assumption of capital commitments in joint venture	24,500			10,600
Capital investments	$ 48,000			66,000
Guarantees of capital investments				14,000
Maximum exposure to loss				80,000
Carnero Gathering LLC, Joint Venture
Variable Interest Entity [Line Items]
Ownership interest (as a percent)		50.00%	50.00%
Payments to acquire interest in joint venture		$ 37,000	$ 37,000
Assumption of capital commitments in joint venture		$ 7,400	$ 7,400	4,300
Debt incurred				0
Capital investments				40,300
Guarantees of capital investments				4,100
Maximum exposure to loss				$ 48,100

Supplemental Information On O75

Supplemental Information On Oil And Natural Gas Producing Activities (Capitalized Costs) (Details) - USD ($) $ in Thousands		Dec. 31, 2016	Dec. 31, 2015
Supplemental Information On Oil And Natural Gas Producing Activities
Proved property	[1]	$ 758,366	$ 731,548
Unproved property	[1]	46	39
Land		501	501
Total property costs	[1]	758,913	732,088
Materials and supplies	[1]	1,056	1,056
Total	[1]	759,969	733,144
Less: accumulated depreciation, depletion, amortization and impairments	[1]	(674,338)	(652,167)
Oil and natural gas properties and equipment, net	[1]	$ 85,631	$ 80,977
[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 O76

Supplemental Information On Oil And Natural Gas Producing Activities (Costs Incurred Production) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Supplemental Information On Oil And Natural Gas Producing Activities
Proved	$ 25,622	$ 81,378
Development costs	937	2,005
Oil and natural gas properties and equipment, net	$ 26,559	$ 83,383

Supplemental Information On O77

Supplemental Information On Oil And Natural Gas Producing Activities (Proved Reserves) (Details) - MMBoe	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Changes in proved developed and undeveloped reserves
Balance	11,642	16,627
Extensions and discoveries		3
Purchase of reserves in place	1,397	5,124
Sales of reserves in place	(610)
Revisions of previous estimates	(4,426)	(9,038)
Production	(1,133)	(1,074)
Balance	6,870	11,642
Proved developed reserves	6,870	11,523
Proved undeveloped reserves		119
Oil
Changes in proved developed and undeveloped reserves
Balance	3,159	1,662
Extensions and discoveries		3
Purchase of reserves in place	1,049	3,516
Sales of reserves in place	(47)
Revisions of previous estimates	(316)	(1,754)
Production	(331)	(268)
Balance	3,514	3,159
Proved developed reserves	3,514	3,071
Proved undeveloped reserves		88
Natural Gas
Changes in proved developed and undeveloped reserves
Balance	7,736	14,907
Purchase of reserves in place	176	799
Sales of reserves in place	(563)
Revisions of previous estimates	(4,202)	(7,175)
Production	(721)	(795)
Balance	2,426	7,736
Proved developed reserves	2,426	7,705
Proved undeveloped reserves		31
Natural Gas Liquids
Changes in proved developed and undeveloped reserves
Balance	747	58
Purchase of reserves in place	172	809
Revisions of previous estimates	92	(109)
Production	(81)	(11)
Balance	930	747
Proved developed reserves	930	747

Supplemental Information On O78

Supplemental Information On Oil And Natural Gas Producing Activities (Proved Reserves Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)MMBoe$ / Mcf$ / bbl	Dec. 31, 2015USD ($)MMBoe$ / bbl	Dec. 31, 2014MMBoe
Reserve Quantities [Line Items]
Exploration and dry hole costs | $	$ 0	$ 0
Proved reserve estimates	6,870	11,642	16,627
Reserve revision	6,870	11,523
Increase (decrease) in proved reserve estimates	(4,700,000)	(5,000,000)
Oil
Reserve Quantities [Line Items]
Proved reserve estimates	3,514	3,159	1,662
Reserve revision	3,514	3,071
Weighted-average product price | $ / bbl	38.85	50.28
Natural Gas Liquids
Reserve Quantities [Line Items]
Proved reserve estimates	930	747	58
Reserve revision	930	747
Weighted-average product price | $ / bbl	13.84	19.90
Natural Gas
Reserve Quantities [Line Items]
Proved reserve estimates	2,426	7,736	14,907
Reserve revision	2,426	7,705
Increase (decrease) in proved reserve estimates		(4,000,000)
Percentage of reserves	35.00%	66.00%
Weighted-average product price	2.28	2.58

Supplemental Information On O79

Supplemental Information On Oil And Natural Gas Producing Activities (Standardized Measure) (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Information On Oil And Natural Gas Producing Activities
Future cash inflows	$ 182,612	$ 289,767
Future production costs	(102,569)	(165,861)
Future estimated development costs	(8,872)	(19,026)
Future net cash flows	71,171	104,880
10% annual discount for estimated timing of cash flows	(21,535)	(37,028)
Standardized measure of discounted future net cash flows related to proved gas reserves	$ 49,636	$ 67,852	$ 119,533

Supplemental Information On O80

Supplemental Information On Oil And Natural Gas Producing Activities (Change Standardized Measure) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Supplemental Information On Oil And Natural Gas Producing Activities
Beginning of the period	$ 67,852	$ 119,533
Sales and transfers of oil and natural gas, net of production costs	(8,700)	(30,748)
Net changes in prices and production costs related to future production	(7,868)	(125,979)
Changes in development costs	5,040	5,016
Changes in extensions and discoveries		178
Revisions of previous quantity estimates	(17,924)	(11,299)
Purchases and sales of reserves in place	9,134	109,181
Accretion discount	6,175	11,953
Change in production rates, timing, and other	(4,073)	(9,983)
Standardized measure of discount future net cash flows related to proved gas reserves	$ 49,636	$ 67,852

Subsequent Events (Details)

Subsequent Events (Details) - $ / shares	Feb. 09, 2017	Jan. 25, 2017	Dec. 31, 2016	Dec. 31, 2015
Subsequent Event [Line Items]
Class B preferred units, issued			29,296,441	19,444,445
Class B Preferred
Subsequent Event [Line Items]
Aggregate distribution of units			208,594
Subsequent Event | Common Units
Subsequent Event [Line Items]
Distribution declared per unit	$ 0.4310
Annual distribution declared per unit	$ 1.7240
Aggregate distribution of units	208,594
Subsequent Event | Class B Preferred
Subsequent Event [Line Items]
Distribution declared per unit	$ 0.2258
Annual distribution declared per unit	$ 0.2258
Subsequent Event | Settlement Agreement with Stonepeak Catarina Holdings LLC [Member] | Class B Preferred
Subsequent Event [Line Items]
Class B preferred units, issued		1,704,446
Class B preferred units, unit price		$ 11.29