Evolve Transition Infrastructure (SNMP) 10-K 7 Mar 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Mar. 07, 2019	Jun. 30, 2018
Document And Entity Information
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Entity Registrant Name	Sanchez Midstream Partners LP
Entity Central Index Key	1,362,705
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Ex Transition Period	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		17,464,315
Entity Public Float			$ 128,395,151
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, 2018	Dec. 31, 2017
Revenues
Gathering and transportation lease revenues	$ 53,025
Total revenues	83,610	$ 88,149
Operating expenses:
Lease operating expenses	7,864	12,994
Transportation operating expenses	12,316	11,600
Cost of sales		77
Production taxes	1,104	1,476
General and administrative expenses	23,653	22,655
Unit-based compensation expense	1,938	3,373
Gain on sale of assets	(3,186)	(4,150)
Depreciation, depletion and amortization	25,987	34,830
Asset impairments	0	4,688
Accretion expense	497	773
Total operating expenses	70,173	88,316
Other (income) expense
Interest expense, net	10,961	8,341
Earnings from equity investments	(12,859)	(7,885)
Other (income) expense	(546)	2,417
Total other (income) expenses	(2,444)	2,873
Total expenses	67,729	91,189
Income (loss) before income taxes	15,881	(3,040)
Income tax expense	190
Net income (loss)	15,691	(3,040)
Less:
Preferred unit paid-in-kind distributions	(3,500)	(2,625)
Preferred unit distributions	(33,425)	(33,250)
Preferred unit amortization	(2,358)	(1,796)
Net loss attributable to common unitholders	(23,592)	(40,711)
Common units
Other (income) expense
Net income (loss)	$ 15,691	$ (3,040)
Net loss per unit
Common units - Basic and Diluted (in dollars per share)	$ (1.55)	$ (2.90)
Weighted Average Units Outstanding, Common Units - Basic and Diluted (in units)	15,264,284	14,039,726
Natural gas sales
Revenues
Revenues	$ 953	$ 6,626
Oil sales
Revenues
Revenues	21,272	23,701
Natural gas liquid product
Revenues
Revenues	1,709	1,997
Gathering and transportation
Revenues
Revenues	$ 6,651	$ 55,825

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 2,934	$ 321
Accounts receivable	277	495
Accounts receivable - related entities	6,700	13,099
Prepaid expenses	931	2,670
Fair value of commodity derivative instruments	3,044	942
Total current assets	13,886	17,527
Oil and natural gas properties and related equipment
Oil and natural gas properties, equipment and facilities (successful efforts method)	112,173	170,750
Gathering and transportation assets	186,406	184,969
Less: accumulated depreciation, depletion, amortization and impairment	(100,245)	(142,574)
Oil and natural gas properties and equipment, net	198,334	213,145
Other assets
Intangible assets, net	158,706	172,166
Fair value of commodity derivative instruments	876	1,318
Equity investments	114,465	123,715
Other non-current assets	418	552
Total assets	486,685	528,423
Current liabilities
Accounts payable and accrued liabilities	4,678	1,782
Accounts payable and accrued liabilities - related entities	5,641	10,353
Royalties payable	359	371
Fair value of commodity derivative instruments	6	756
Other liabilities	125	151
Total current liabilities	10,809	13,413
Other liabilities
Asset retirement obligation	6,200	6,074
Long-term debt, net of debt issuance costs	178,582	187,808
Fair value of commodity derivative instruments		273
Other liabilities	5,857	6,251
Total other liabilities	190,639	200,406
Total liabilities	201,448	213,819
Commitments and contingencies (See Note 13)
Mezzanine equity
Class B preferred units, 31,310,896 and 31,000,887 units issued and outstanding as of December 31, 2018 and 2017, respectively	349,857	343,912
Partners' deficit
Common units, 16,486,239 and 14,965,134 units issued and outstanding as of December 31, 2018 and 2017, respectively	(64,620)	(29,308)
Total partners' deficit	(64,620)	(29,308)
Total liabilities and partners' capital	$ 486,685	$ 528,423

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - shares	Dec. 31, 2018	Dec. 31, 2017
Consolidated Balance Sheets
Class B preferred units, issued	31,310,896	31,000,887
Class B preferred units, outstanding	31,310,896	31,000,887
Units, issued	16,486,239	14,965,134
Units, outstanding	16,486,239	14,965,134

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities:
Net income (loss)	$ 15,691	$ (3,040)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	12,527	21,262
Amortization of debt issuance costs	783	524
Asset impairments		4,688
Accretion expense	497	773
Distributions from equity investments	24,946	8,720
Equity earnings in affiliate	(12,859)	(7,885)
Gain on sale of assets	(3,186)	(4,150)
Net gains on commodity derivative contracts	(1,316)	(3,947)
Net cash settlements received (paid) on commodity derivative contracts	(1,326)	5,487
Cash settlements on terminated commodity derivative contracts		3,602
Unit-based compensation	1,938	3,373
(Gain) loss on earnout derivative	(546)	2,353
Amortization of intangible assets	13,460	13,568
Costs for plug and abandon activities		(60)
Changes in Operating Assets and Liabilities:
Accounts receivable	(377)	644
Accounts receivable - related entities	6,389	(6,590)
Prepaid expenses	1,739	(629)
Other assets	82	144
Accounts payable and accrued liabilities	13,719	9,997
Accounts payable and accrued liabilities- related entities	(5,333)	3,566
Royalties payable	(12)	(300)
Other long-term liabilities	126
Net cash provided by operating activities	66,942	52,100
Cash flows from investing activities:
Final settlement of oil and natural gas properties acquisition		1,468
Development of oil and natural gas properties	(11)	(441)
Proceeds from sale of assets	7,692	11,665
Construction of gathering and transportation assets	(2,533)	(31,693)
Purchases of and contributions to equity affiliates	(2,838)	(13,684)
Net cash provided by (used in) investing activities	2,310	(32,685)
Cash flows from financing activities:
Payments for offering costs	(50)	(611)
Proceeds from issuance of debt	2,000	48,000
Repayment of debt	(11,000)	(12,000)
Issuance of common units		1,290
Distributions to common unitholders	(23,243)	(25,192)
Class B preferred unit cash distributions	(33,338)	(31,500)
Debt issuance costs	(1,008)	(38)
Net cash used in financing activities	(66,639)	(20,051)
Net increase (decrease) in cash and cash equivalents	2,613	(636)
Cash and cash equivalents, beginning of period	321	957
Cash and cash equivalents, end of period	2,934	321
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	525	1,064
Cash paid during the period for interest	$ 9,763	$ 7,643

Consolidated Statements of Chan

Consolidated Statements of Changes in Partners’ Capital - USD ($) $ in Thousands	Common units	Total
Partner's Capital (Deficit) at Dec. 31, 2016	$ 16,744	$ 16,744
Partner's Capital (Deficit) (in shares) at Dec. 31, 2016	13,447,749
Unit-based compensation programs	$ 3,373	3,373
Unit-based compensation programs (in shares)	217,481
Issuance of common units, net of offering costs	$ 11,228	11,228
Issuance of common units, net of offering costs (in shares)	906,613
Cash distributions to common unit holders	$ (25,192)	(25,192)
Common units issued as Class B Preferred distributions	$ 5,250	5,250
Common units issued as Class B Preferred distributions (in shares)	393,291
Distributions - Class B preferred units	$ (37,671)	(37,671)
Net income (loss)	(3,040)	(3,040)
Partner's Deficit at Dec. 31, 2017	$ (29,308)	(29,308)
Partner's Deficit (in shares) at Dec. 31, 2017	14,965,134
Unit-based compensation programs	$ 1,938	1,938
Unit-based compensation programs (in shares)	531,561
Issuance of common units, net of offering costs	$ 9,585	9,585
Issuance of common units, net of offering costs (in shares)	989,544
Cash distributions to common unit holders	$ (23,243)	(23,243)
Distributions - Class B preferred units	(39,283)	(39,283)
Net income (loss)	15,691	15,691
Partner's Deficit at Dec. 31, 2018	$ (64,620)	$ (64,620)
Partner's Deficit (in shares) at Dec. 31, 2018	16,486,239

Consolidated Statements of Ch_2

Consolidated Statements of Changes in Partners’ Capital (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Consolidated Statements of Changes in Partners’ Capital
Offering costs	$ 0.1	$ 0.6

Organization And Business

Organization And Business	12 Months Ended
	Dec. 31, 2018
Organization And Business
Organization And Business	1. ORGANIZATION AND BUSINESS Organization We are a growth-oriented publicly-traded limited partnership focused on the acquisition, development, ownership and operation of midstream and other energy-related assets in North America. We have ownership stakes in oil and natural gas gathering systems, natural gas pipelines, and a natural gas processing facility, all located in the Western Eagle Ford in South Texas. We also own production assets in Texas and Louisiana. We have entered into the Services Agreement with Manager, the sole member of our general partner, pursuant to which Manager provides services we require to operate our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, acquisition, disposition and financing services. On June 2, 2017, we changed our name to Sanchez Midstream Partners LP from Sanchez Production Partners LP. Manager also owns our general partner and all of our incentive distribution rights. Our common units are currently listed on the NYSE American under the symbol “SNMP.”

Basis Of Presentation And Summa

Basis Of Presentation And Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
Basis Of Presentation And Summary Of Significant Accounting Policies
Basis of Presentation and 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. Our business consists of two reportable segments: Production and Midstream. Midstream includes Western Catarina Midstream, the Carnero JV and Seco Pipeline. Production consists of our oil and natural gas properties in Texas and Louisiana. 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 August 2018, the FASB issued Accounting Standards Update (“ASU”) 2018-13 “Fair Value Measurement (ASC 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements,” which modifies the disclosure requirements on fair value measurements. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2019. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In June 2018, the FASB issued ASU 2018-07 “Compensation - Stock Compensation (Topic 718) - Improvements to Nonemployee Share-Based Payment Accounting,” which expands the scope of Topic 718, Compensation – Stock Compensation, to include share-based payment transactions for acquiring goods and services from nonemployees. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2018. We will adopt this guidance beginning in fiscal year 2019. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In January 2017, the FASB issued 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. The Partnership adopted this ASU on January 1, 2018, using a prospective method and did not have an impact on the Partnership’s unaudited condensed consolidated financial statements and related disclosures. In October 2016, the FASB issued ASU 2016-16 “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” which eliminates a current exception in U.S. GAAP to the recognition of the income tax effects of temporary differences that result from intra-entity transfers of non-inventory assets. The intra-entity exception is being eliminated under the ASU. The standard is required to be applied on a modified retrospective basis and is now effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. The adoption of ASU 2016-16 did not have an impact on the Partnership’s unaudited condensed consolidated financial statements and related disclosures. In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This ASU modifies the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in the more timely recognition of losses. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2019, and earlier adoption is permitted. 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. Additionally, in July 2018, the FASB issued ASU 2018-10, “Codification Improvements to Topic 842 (Leases),” which provides narrow amendments to clarify how to apply certain aspects of ASU 2016-02. The Partnership plans on electing the practical expedients disclosed in ASU 2018-10. The effective date in ASU 2018-10 is the same as that of ASU 2016-02. The standards update 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. The Partnership will not early adopt this standard and will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019. The Partnership has substantially completed its review of the impact of the new standard as well as the implementation of a lease accounting software. Adoption of the standard is expected to result in the recognition of assets and liabilities in our consolidated balance sheets for existing operating leases such as compressors and potentially other equipment still being evaluated. Concurrent with the software implementation, the Partnership is incorporating necessary updates to its business processes and controls. The quantitative impacts of the new standard are dependent on the active leases at the time of adoption. As a result, the evaluation of the effect of the new standards will extend over future periods. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” In March, April, May and December 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 requires 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 adopted the standard effective January 1, 2018. For more information, see Note 3 “Revenue Recognition.” 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. 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 natural gas, NGLs and oil; 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. Revenue Recognition Midstream We recognize revenue from contracts with customers in accordance with Topic 606 and ASC 840 for our midstream segment. The Seco Pipeline Transportation Agreement is our only contract that we account for using Topic 606. Under the Seco Pipeline Transportation Agreement, we agreed to provide transportation services of certain quantities of natural gas from the receipt point to the delivery point. Each MMBtu of natural gas transported is distinct and the transportation services performed on each distinct molecule of product is substantially the same in nature. As such, we applied the series guidance and treat these services as a single performance obligation satisfied over time using volumes delivered as the measure of progress. Additionally, Seco Pipeline Transportation Agreement contains variable consideration in the form of volume variability. As the distinct goods or services (rather than the series) are considered for the purpose of allocating variable consideration, we have taken the optional exception under ASC 606-10-50-14A(b). Under this exception, revenue is alternatively recognized in the period that control is transferred to the customer and the respective variable component of the total transaction price is resolved. The Gathering Agreement (as defined in Note 14. “Related Party Transactions”) was classified as an operating lease at inception and is accounted for under ASC 840, as Sanchez Energy controls the physical use of the property under the lease. Revenues relating to the Gathering Agreement is recognized in the period service is provided. Under this arrangement, 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. Production Our oil, natural gas, and NGL revenue is marketed and sold on our behalf by the respective asset operators, as we do not currently operate any of our production assets. The Eagle Ford Shale properties are operated by SOG and Marathon Oil Company and the Louisiana properties are operated by SOG. We are not party to the contracts with the third-party customers. How ever, we are party to joint operating agreements, which we account for under ASC 808. Both revenues and expenses for these arrangements are recognized based on the information provided to us by the operators. Accounts Receivable, Net Our accounts receivable are primarily from our contractual agreements with Sanchez Energy and its subsidiaries, operators of our oil and natural gas properties 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, 2018 and 2017. 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 receivable are due from operators of our oil and natural gas properties. These sales are generally unsecured and, in some cases, may carry a parent guarantee. 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. We have no off-balance-sheet credit exposure related to our operations or customers. Sanchez Energy accounted for 71% and 63% of total revenue for the years ended December 31, 2018 and 2017, respectively. We are highly dependent upon Sanchez Energy as our most significant customer, and we expect to derive a substantial portion of our revenue from Sanchez Energy in the foreseeable future. Accordingly, we are indirectly subject to the business risks of Sanchez Energy. Income Taxes SNMP 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. Earnings per Unit 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. Asset Retirement Obligations Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and the credit-adjusted risk-free rate. The inputs are calculated based on historical data as well as current estimates. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset and is included in “Depreciation, depletion, amortization and accretion” in the Partnership’s Consolidated Statements of Operations. To estimate the fair value of an asset retirement obligation, the Partnership employs a present value technique, which reflects certain assumptions, including its credit‑adjusted risk‑free interest rate, inflation rate, the estimated settlement date of the liability and the estimated current cost to settle the liability. Changes in timing or to the original estimate of cash flows will result in change to the carrying amount of the liability. 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. 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. As more fully described in Note 8 “Oil and Natural Gas Properties and Related Equipment” to our consolidated financial statements, proved reserves estimates are subject to future revisions when additional information becomes available. All other properties, including the gathering and transportation assets, are stated at historical acquisition cost, net of any impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, and up to 36 years for gathering facilities. Estimated asset retirement costs are recognized when the asset is acquired or placed in service, and are amortized over proved reserves using the units-of-production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates. Oil and natural gas properties are reviewed for impairment 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. Cash flow estimates for the impairment testing are based on third party reserve reports and exclude derivative instruments. Refer to Note 8 “Oil and Natural Gas Properties and Related Equipment” to our consolidated financial statements for additional information. Reserves of Natural Gas, NGLs and Oil Our estimate of proved reserves is based on the quantities of natural gas, NGLs and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Management estimates the proved reserves attributable to our ownership based on various factors, including consideration of the reserve report prepared by Ryder Scott, an independent oil and natural gas consulting firm. On an annual basis, our proved reserve estimates and the reserve report prepared by Ryder Scott are reviewed by the Audit Committee and the Board. Our financial statements for 2018 and 2017 were prepared using Ryder Scott’s estimates of our proved reserves. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The accuracy of our 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. Our 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 actual quantities of oil and natural gas eventually recovered. Unit-Based Compensation The Partnership records unit-based compensation expense for awards granted to the directors of its general partner (for their services as directors) in accordance with the provisions of Accounting Standards Codification (“ASC”) Topic 718, “Compensation—Stock Compensation.” Unit-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 unit-based award. Investments We follow the equity method of accounting when we do not exercise control over the investee, but we can exercise significant influence over the operating and financial policies of the investee. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. We evaluate our equity investments for impairment when evidence indicates the carrying amount of our investment is no longer recoverable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. When the estimated fair value of an equity investment is less than its carrying value and the loss in value is determined to be other than temporary, we recognize the excess of the carrying value over the estimated fair value as an impairment loss within equity earnings (loss) in our consolidated statements of operations. Earnout Derivative As part of the Carnero Gathering Transaction (defined in Note 12 “Investments”), we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at Carnero Gathering’s delivery points from Sanchez Energy and other producers. The earnout derivative is accounted for under ASC 815, and we measure its fair value through the use of a Monte Carlo simulation model which utilized observable inputs such as the earnout price and volume commitment, as well as unobservable inputs related to the weighted probabilities of various throughput scenarios.

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2018
Revenue Recognition
Revenue Recognition	3. REVENUE RECOGNITION Adoption of Topic 606 Effective January 1, 2018, the Partnership adopted the new Accounting Standards Codification (“ASC”) 606, Revenue from Contracts with Customers, and all the related amendments (collectively referred to as “Topic 606”) to all open contracts using the modified retrospective approach. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. For contracts that have a contract term of one year or less, we elected to utilize the practical expedient permitted under the rules of adoption whereby a company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Adoption of this guidance resulted in financial statement presentation changes whereby revenue from the Gathering Agreement and revenue from the Seco Pipeline Transportation Agreement are shown as separate line items within our condensed consolidated statements of operations. There was no cumulative adjustment to retained earnings or any other changes to our January 1, 2018 condensed consolidated balance sheet. Revenue from Contracts with Customers Beginning in 2018, we account for revenue from contracts with customers in accordance with Topic 606. The unit of account in Topic 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. Topic 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied. Disaggregation of Revenue We disaggregate revenue based on type of revenue and product type. In selecting the disaggregation categories, we considered a number of factors, including disclosures presented outside the financial statements, such as in our earnings release and investor presentations, information reviewed internally for evaluating performance, and other factors used by the Partnership or the users of its financial statements to evaluate performance or allocate resources. We have concluded that disaggregating revenue by type of revenue and product type appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. Midstream Segment The Seco Pipeline Transportation Agreement is our only contract that we account for under Topic 606. The Gathering Agreement (as defined in Note 14. “Related Party Transactions”) was classified as an operating lease at inception and is accounted for under ASC 840, Leases, and is reported as gathering and transportation lease revenue in our condensed consolidated statements of operations. Both of these contracts are further discussed in Note 14 “Related Party Transactions.” We account for income from our unconsolidated equity method investments as earnings from equity investments in our condensed consolidated statements of operations. Earnings from these equity method investments are further discussed in Note 12 “Investments.” Production Segment Our oil, natural gas, and NGL revenue is marketed and sold on our behalf by the respective asset operators, as we do not currently operate any of our production assets. The Eagle Ford Shale properties are operated by SOG and Marathon Oil Company and the Louisiana properties are operated by SOG. We are not party to the contracts with the third-party customers. However, we are party to joint operating agreements, which we account for under ASC 808. Both revenues and expenses for these arrangements are recognized based on the information provided to us by the operators. We additionally recognize and present changes in the fair value of our commodity derivative instruments within natural gas sales and oil sales in the condensed consolidated statements of operations. As this income is accounted for under ASC 815, Derivatives and Hedging, it is not subject to Topic 606. We recognized revenue of $83.6 million for the year ended December 31, 2018. The following table displays revenue disaggregated by type of revenue and product type (in thousands): Year December 31, 2018 Production Midstream Total Revenues: Natural gas sales $ 953 $ — $ 953 Oil sales 21,272 — 21,272 Natural gas liquid sales 1,709 — 1,709 Gathering and transportation sales — 6,651 6,651 Gathering and transportation lease revenues — 53,025 53,025 Total revenues $ 23,934 $ 59,676 $ 83,610 Performance Obligations Under the Seco Pipeline Transportation Agreement, we agreed to provide transportation services of certain quantities of natural gas from the receipt point to the delivery point. Each MMBtu of natural gas transported is distinct and the transportation services performed on each distinct molecule of product is substantially the same in nature. As such, we applied the series guidance and treat these services as a single performance obligation satisfied over time using volumes delivered as the measure of progress. The Seco Pipeline Transportation Agreement requires payment within 30 days following the calendar month of delivery. The Seco Pipeline Transportation Agreement contains variable consideration in the form of volume variability. As the distinct goods or services (rather than the series) are considered for the purpose of allocating variable consideration, we have taken the optional exception under ASC 606-10-50-14A(b) which is available only for wholly unsatisfied performance obligations for which the criteria in ASC 606-10-32-40 have been met. Under this exception, neither estimation of variable consideration nor disclosure of the transaction price allocated to the remaining performance obligations is required. Revenue is alternatively recognized in the period that control is transferred to the customer and the respective variable component of the total transaction price is resolved. For forms of variable consideration that are not associated with a specific volume (such as late payment fees) and thus do not meet allocation exception, estimation is required. These fees, however, are immaterial to our condensed consolidated financial statements and have a low probability of occurrence. As significant reversals of revenue due to this variability are not probable, no estimation is required. Contract Balances Under our sales contracts, we invoice customers after our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities under Reconciliation of Statements of Operations The impact of adopting Topic 606 on our condensed consolidated statements of operations is as follows (in thousands): Year Ended December 31, 2018 As reported Balances without Adoption Topic 606 Effect of change Higher/(Lower) Statement of Operations Gathering and transportation sales $ 6,651 $ 59,676 $ (53,025) Gathering and transportation lease revenues 53,025 — 53,025 Net earnings $ 59,676 $ 59,676 $ — We expect the impact of the adoption of Topic 606 to be immaterial to our net income (loss) on an ongoing basis.

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2018
Acquisitions and Divestitures
Acquisitions and Divestitures	4. ACQUISITIONS AND DIVESTITURES Louisiana Divestiture In September 2018, we entered into a purchase and sale agreement to sell certain non-operated production assets located in Louisiana for cash consideration of approximately $1.3 million. The divestiture closed on October 22, 2018 and we recorded a gain of approximately $0.6 million on the sale. Briggs Divestiture In April 2018, we entered into a purchase and sale agreement to sell specified wellbores and related assets and interests in La Salle County Texas (the “Briggs Assets”) for a base purchase price of approximately $4.5 million which, after giving effect to purchase price adjustments, was reduced to approximately $4.2 million in cash consideration (the “Briggs Divestiture”). In addition, other than limited obligations that we retained, the buyer agreed to assume all obligations relating to the Briggs Assets, including all plugging and abandonment costs, that may arise on or after March 1, 2018. The Briggs Divestiture closed on April 30, 2018 and we recorded a gain of approximately $1.8 million on the sale. Cola Divestiture In April 2018, we entered into multiple purchase and sale agreements to sell certain non-operated production assets located in Oklahoma for total cash consideration of approximately $1.0 million. The divestitures were all closed by May 8, 2018 and we recorded a total gain of approximately $1.1 million on the sale. Texas Production Divestiture In October 2017, we entered into a purchase and sale agreement to sell specified oil and gas wells, leases and other associated assets and interests located in Texas (the “Texas Production Assets”) for cash consideration of approximately $6.3 million, (the “Texas Production Divestiture”). In addition, the buyer agreed to assume all obligations relating to the assets, including all plugging and abandonment costs relating to the assets, that arise on or after October 1, 2017. The Texas Production Divestiture closed November 13, 2017 and we recorded a gain of approximately $1.4 million on the sale. Non-Operated Production Divestiture In July 2017, we entered into an agreement to assign certain non-operated production assets located in Oklahoma, as well as our equity interests in the entities that owned such assets, in exchange for agreeing upon the apportionment of certain shared litigation costs. The assignment was effective as of July 14, 2017. Oklahoma Production Divestiture In May 2017, we entered into a purchase and sale agreement to sell all of the Partnership’s equity interests in the entities that owned our remaining Oklahoma production assets for cash consideration of $5.5 million, and assumption by the buyer of all obligations relating to the assets arising after the closing date and all plugging and abandonment costs relating to the assets arising prior to the closing date (the “Oklahoma Production Divestiture”). The Oklahoma Production Divestiture closed July 17, 2017 and we recorded a gain of $2.4 million on the sale.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2018
Fair Value Measurements
Fair Value Measurements	5. 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, 2018 (in thousands): Fair Value Measurements at December 31, 2018 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative assets $ — $ 3,914 $ — $ 3,914 Midstream derivative instrument Earnout derivative liability — — (5,856) (5,856) Total $ — $ 3,914 $ (5,856) $ (1,942) 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, 2017 (in thousands): Fair Value Measurements at December 31, 2017 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative assets $ — $ 1,231 $ — $ 1,231 Midstream derivative instrument Earnout derivative liability — — (6,402) (6,402) Total $ — $ 1,231 $ (6,402) $ (5,171) As of December 31, 2018 and 2017, 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 10 ‘‘Asset Retirement Obligation.’’ The following table summarizes the non-recurring fair value measurements of our assets and liabilities as of December 31, 2018 (in thousands): Fair Value Measurements at December 31, 2018 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Impairment $ — $ — $ — Total net assets $ — $ — $ — The following table summarizes the non-recurring fair value measurements of our assets and liabilities as of December 31, 2017 (in thousands): Fair Value Measurements at December 31, 2017 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Impairment (a) $ — $ — $ 7,277 Total net assets $ — $ — $ 7,277 (a) During the year ended December 31, 2017, we recorded a non-cash impairment charge of $4.7 million to impair certain of our producing oil and natural gas properties in Texas. The carrying values of the impaired proved properties were reduced to a fair value of $7.3 million, estimated using inputs characteristic of a Level 3 fair value measurement. 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 7 “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. 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. Earnout Derivative – As part of the Carnero Gathering Transaction (defined in Note 12 “Investments”), we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at Carnero Gathering’s delivery points from Sanchez Energy and other producers. The earnout derivative was valued through the use of a Monte Carlo simulation model which utilized observable inputs such as the earnout price and volume commitment, as well as unobservable inputs related to the weighted probabilities of various throughput scenarios. We have therefore classified the fair value measurements of our earnout derivative as Level 3 inputs. The following table sets forth a reconciliation of changes in the fair value of the Partnership's embedded and earnout derivatives classified as Level 3 in the fair value hierarchy (in thousands): December 31, 2018 2017 Beginning balance $ (6,402) $ (4,270) Initial fair value of earnout derivative — 221 Gain (loss) on earnout derivative 546 (2,353) Ending balance $ (5,856) $ (6,402) Gain (loss) included in earnings related to derivatives still held as of December 31, 2018 and 2017, respectively $ 546 $ (2,353)

Derivative And Financial Instru

Derivative And Financial Instruments	12 Months Ended
	Dec. 31, 2018
Derivative And Financial Instruments
Derivative And Financial Instruments	6. 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 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, 2018, we had the following derivative contracts in place, all of which are accounted for as mark-to-market activities: MTM Fixed Price Swaps – NYMEX (Henry Hub) Three Months Ended (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 2019 119,832 $ 2.85 115,784 $ 2.85 112,032 $ 2.85 108,552 $ 2.85 456,200 $ 2.85 2020 105,104 $ 2.85 102,008 $ 2.85 99,136 $ 2.85 96,200 $ 2.85 402,448 $ 2.85 858,648 MTM Fixed Price Basis Swaps – West Texas Intermediate (WTI) Three Months Ended (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 2019 62,528 $ 60.41 59,552 $ 60.44 57,024 $ 60.48 54,824 $ 60.52 233,928 $ 60.46 2020 52,776 $ 53.50 50,960 $ 53.50 49,224 $ 53.50 47,624 $ 53.50 200,584 $ 53.50 434,512 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, 2018 and 2017 (in thousands): December 31, 2018 2017 Beginning fair value of commodity derivatives $ 1,231 $ 6,436 Net gains on crude oil derivatives 1,400 3,284 Net gains (losses) on natural gas derivatives (84) 663 Net settlements paid (received) on derivative contracts: Oil 1,330 (6,422) Natural gas 37 (2,730) Ending fair value of commodity derivatives $ 3,914 $ 1,231 The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands): Location of Gain(Loss) Years Ended December 31, Derivative Type in Income 2018 2017 Commodity – Mark-to-Market Oil sales $ 1,400 $ 3,284 Commodity – Mark-to-Market Natural gas sales (84) 663 $ 1,316 $ 3,947 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. In August 2017, we repositioned certain of our oil and natural gas hedges in anticipation of the sale of the Texas Production Assets and, in the process, received $3.6 million in net cash from the counterparties on those hedges. As of December 31, 2018 and 2017, the impact of non-performance credit risk on the valuation of our derivative instruments was not significant. Earnout Derivative Refer to Note 5 “Fair Value Measurements”.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2018
Long-Term Debt
Long-Term Debt	7. 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”). The Credit Agreement provides a maximum commitment of $500.0 million 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 properties. 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 $15.0 million which may be used for the issuance of letters of credit. The initial borrowing base under the Credit Agreement was $200.0 million. 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 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 assets is equal to the rolling four quarter EBITDA of our midstream operations and the amount of distributions received from Carnero JV multiplied by 4.5. 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. As of December 31, 2018, the borrowing base under the Credit Agreement was $310.0 million, with an elected commitment amount of $210.0 million, and we had $180.0 million of debt outstanding under the facility, leaving us with $30.0 million in unused borrowing capacity. There were no letters of credit outstanding under our Credit Agreement as of December 31, 2018. 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 for the proper conduct of our business and the payment of fees and expenses. At December 31, 2018, 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, 2018 and 2017, our unamortized debt issuance costs were $1.4 million and $1.2 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 years ended December 31, 2018 and 2017 were $0.8 million and $0.5 million, respectively.

Oil And Natural Gas Properties

Oil And Natural Gas Properties And Related Equipment	12 Months Ended
	Dec. 31, 2018
Oil And Natural Gas Properties And Related Equipment.
Oil And Natural Gas Properties And Related Equipment	8. OIL AND NATURAL GAS PROPERTIES AND RELATED EQUIPMENT Gathering and transportation assets consist of the following (in thousands): December 31, 2018 2017 Gathering and transportation assets Midstream assets $ 186,406 $ 184,969 Less: Accumulated depreciation and amortization (34,598) (26,870) Total Gathering and transportation assets, net $ 151,808 $ 158,099 Oil and natural gas properties consist of the following (in thousands): December 31, 2018 2017 Oil and natural gas properties and related equipment Proved property $ 112,173 $ 170,750 Less: Accumulated depreciation, depletion, amortization and impairments (65,647) (115,704) Oil and natural gas properties and equipment, net $ 46,526 $ 55,046 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. 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 natural gas, NGLs, and oil 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, 2018 and 2017 is described in detail in Note 20 “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. 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. Depreciation, depletion, amortization and impairments consisted of the following (in thousands): Years Ended December 31, 2018 2017 Depreciation, depletion and amortization of oil and natural gas-related assets $ 4,798 $ 9,413 Depreciation and amortization of gathering and transportation related assets 7,729 11,849 Amortization of intangible assets 13,460 13,568 Total Depreciation, depletion and amortization 25,987 34,830 Asset impairments — 4,688 Total $ 25,987 $ 39,518 The recoverability of gathering and transportation assets is evaluated when facts or circumstances indicate that their carrying value may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, we recognize an impairment equal to the excess of net book value over fair value. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our gathering and transportation assets and the recognition of additional impairments. Upon disposition or retirement of gathering and transportation assets, any gain or loss is recorded to operations. For the year ended December 31, 2018, we recorded no impairment charges. For the year ended December 31, 2017, we recorded non-cash charges of $4.7 million, to impair certain producing oil and natural gas properties in Texas. Asset Retirement Obligation. As described in Note 10 “Asset Retirement Obligation,” 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, 2018 and 2017. 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, 2018
Provision For Income Taxes
Provision For Income Taxes	9. 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, 2018 and 2017 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 reflects franchise tax obligations in the state of Texas (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 and state income tax provision (benefit) is summarized below: Years Ended December 31, 2018 2017 Current: Federal $ — $ — State 64 — Total current 64 — Deferred: Federal — — State 126 — Total deferred 126 — Total provision for income taxes $ 190 $ — 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): Years Ended December 31, 2018 2017 Pre-tax net book income (loss) $ 15,881 $ (3,040) Texas Margin Tax (a) 267 (438) Return to accrual 9 — Valuation allowance (86) 438 Provision for income taxes $ 190 $ — Effective income tax rate 1.20 % % (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, 2018 2017 Deferred tax assets (liabilities): Derivative assets $ (15) $ 7 Depreciable, depletable property, plant and equipment (112) 78 Other 1 1 Deferred tax assets (liabilities): (126) 86 Valuation allowance — (86) Total deferred tax assets (liabilities) $ (126) $ — Deferred tax assets which required valuation allowances were related to assets sold in 2018. Therefore, the valuation allowance is no longer necessary and was removed as of December 31, 2018. As of December 31, 2018 and 2017, the Partnership had no material uncertain tax positions. The Partnership files income tax returns in the U.S. and various state jurisdictions. The Partnership is no longer subject to examination by federal income tax authorities prior to 2015. State statutes vary by jurisdiction.

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation
Asset Retirement Obligation	10. 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, 2018 2017 Asset retirement obligation, beginning balance $ 6,074 $ 13,579 Liabilities added from escalating working interests 288 198 Sales (613) (8,416) Revisions to cost estimates (46) — Settlements — (60) Accretion expense 497 773 Asset retirement obligation, ending balance $ 6,200 $ 6,074 Additional AROs increase the liability associated with new oil and natural gas wells and other facilities as these obligations are incurred. Abandonments of oil and natural gas wells reduce the liability for AROs. In 2018 and 2017, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing AROs. During the year ended December 31, 2018, obligations were sold as part of the Briggs Divestiture and Louisiana Divestiture and during the year ended December 31, 2017, obligations were sold as part of the Oklahoma Production Divestiture and Texas Production Divestiture.

Intangible Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2018
Intangible Assets
Intangible Assets	11. INTANGIBLE ASSETS Intangible assets are comprised of customer and marketing contracts. The intangible assets balance includes $1 58.7 million related to the Gathering Agreement with Sanchez Energy that was entered into as part of the Western Catarina Midstream transaction. Pursuant to the 15-year agreement, Sanchez Energy tenders all of its 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 Western Catarina Midstream, 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. Amortization expense for the years ended December 31, 2018 and 2017 was $13. 5 million and $ 13.6 million, respectively. These costs are amortized to depreciation, depletion, and amortization expense in our consolidated statement of operations. Intangible assets as of December 31, 2018 and 2017 are detailed below (in thousands): December 31, 2018 2017 Beginning balance $ 172,166 $ 185,766 Disposals — (32) Amortization (13,460) (13,568) Ending balance $ 158,706 $ 172,166

Investments

Investments	12 Months Ended
	Dec. 31, 2018
Investments
Investments	12. INVESTMENTS In July 2016, we completed a transaction pursuant to which we acquired from Sanchez Energy a 50% interest in Carnero Gathering, LLC (“Carnero Gathering”), a joint venture that was 50% owned and operated by Targa Resources Corp. (NYSE: TRGP) (“Targa”), 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 acquisition date (the “Carnero Gathering Transaction”). 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 a contract term of 15 years and decreases the earnings from equity investments line within the consolidated statements of operations. As part of the Carnero Gathering Transaction, we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Sanchez Energy and other producers. See Note 5 “Fair Value Measurements” for further discussion of the earnout derivative. In November 2016, we completed a transaction pursuant to which we acquired from Sanchez Energy a 50% interest in Carnero Processing, LLC (“Carnero Processing”), a joint venture that was 50% owned and operated by Targa, for aggregate cash consideration of approximately $55.5 million and the assumption of remaining capital contribution commitments to Carnero Processing, estimated at approximately $24.5 million as of the date of acquisition (the “Carnero Processing Transaction”). In May 2018, we executed a series of agreements with Targa and other parties pursuant to which, among other things: (1) the parties merged their respective 50% interests in Carnero Gathering and Carnero Processing (the “Carnero JV Transaction”) to form an expanded 50 / 50 joint venture in South Texas, Carnero G&P, LLC (“Carnero JV”), (2) Targa contributed 100% of the equity interest in the Silver Oak II Gas Processing Plant (“Silver Oak II”), located in Bee County Texas, to Carnero JV, which expands the processing capacity of the joint venture from 260 MMcf/d to 460 MMcf/d, (3) Targa contributed certain capacity in the 45 miles of high pressure natural gas gathering pipelines owned by Carnero Gathering that connect Western Catarina Midstream to nearby pipelines and the Raptor Gas Processing Facility (the “Carnero Gathering Line”) to Carnero JV resulting in the joint venture owning all of the capacity in the Carnero Gathering Line, which has a design limit (without compression) of 400 MMcf/d, (4) the Carnero JV received a new dedication from Sanchez Energy and its working interest partners of over 315,000 Comanche acres in the Western Eagle Ford pursuant to a new long-term firm gas gathering and processing agreement. The agreement with Sanchez Energy, which was approved by all of the unaffiliated Comanche working interest partners, establishes commercial terms for the gathering of gas on the Carnero Gathering Line and processing at the Raptor Gas Processing Facility and Silver Oak II. Prior to execution of the agreement, Comanche volumes were gathered and processed on an interruptible basis, with the processing capabilities of the joint ventures limited by the capacity of the Raptor Gas Processing Facility. As a result of the Carnero JV Transaction we now record our share of earnings and losses from Carnero JV using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting, beginning with the three months ended June 30, 2018. The HLBV is a balance-sheet approach that calculates the amount we would have received if Carnero JV were liquidated at book value at the end of each measurement period. The change in our allocated amount during the period is recognized in our consolidated statements of operations. In the event of liquidation of Carnero JV, available proceeds are first distributed to any priority return and unpaid capital associated with Silver Oak II, and then to members in accordance with their capital accounts. As of December 31, 2018, the Partnership had paid approximately $123.8 million for its investment in Carnero JV related to the initial payments and contributed capital. The Partnership has accounted for this investment using the equity method. 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 on our consolidated balance sheets. For the year ended December 31, 2018, the Partnership recorded earnings of approximately $14.0 million in equity investments from Carnero JV, which was offset by approximately $1.2 million related to the amortization of the contractual customer intangible asset. We have included these equity method earnings in the earnings from equity investments line within the consolidated statements of operations. Cash distributions of approximately $24.9 million were received during the year ended December 31, 2018. Summarized financial information of unconsolidated entities is as follows (in thousands): Years Ended December 31, 2019 2018 Sales $ 321,607 $ 136,178 Total expenses 290,073 118,077 Net income $ 31,534 $ 18,101

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments And Contingencies
Commitments And Contingencies	13. COMMITMENTS AND CONTINGENCIES As part of the Carnero Gathering Transaction, we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at Carnero Gathering’s delivery points from Sanchez Energy and other producers. This earnout has an approximate value of $5.9 million and was recorded on the balance sheet as a deferred liability as of December 31, 2018. For the years ended December 31, 2018 and 2017, natural gas received did not exceed the threshold.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2018
Related Party Transactions
Related Party Transactions	14. 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. The sole manager and member of Manager is SP Capital Holdings, LLC, which has no officers. The co-managers of SP Capital Holdings, LLC are Antonio R. Sanchez, III, a member of and Chairman of the Board; Eduardo A. Sanchez, a member of the Board; Patricio D. Sanchez, a member of the Board and the President and Chief Operating Officer of our general partner; and their father, Antonio R. Sanchez, Jr. SP Capital Holdings, LLC is owned by Antonio R. Sanchez, III, Eduardo A. Sanchez , and Patricio D. Sanchez, along with their sister, Ana Lee Sanchez Jacobs, and Antonio R. Sanchez, Jr. 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 services under the Services Agreement, Manager receives compensation consisting of: (i) a quarterly fee equal to 0.375% of the value of our properties other than our assets located in the Mid-Continent region, (ii) reimbursement for all allocated overhead costs as well as any direct third-party costs incurred and (iii) for each asset acquisition, asset disposition and financing, a fee not to exceed 2% of the value of such transaction. Each of these fees, not including the reimbursement of costs, is paid in cash unless Manager elects for such fee to be paid in our equity. The Services Agreement has a ten-year term and will be automatically renewed for an additional ten years unless both Manager and the Partnership provide notice of termination to the other with at least 180 days’ notice. During the years ended December 31, 2018 and 2017, we incurred costs of approximately $8.6 million and $8.8 million, respectively, to Manager under the Services Agreement. Manager utilizes SOG to provide the services under the Services Agreement. SOG, headquartered in Houston, Texas, is a private full-service oil and natural gas company engaged in the exploration and development of oil and natural gas primarily in the South Texas and onshore Gulf Coast areas on behalf of its affiliates. The Chairman of the Board, Antonio R. Sanchez, III, the President and Chief Operating Officer of our general partner as well as one of our directors, Patricio D. Sanchez, one of our directors, Eduardo A. Sanchez, along with their immediate family members Ana Lee Sanchez Jacobs and Antonio R. Sanchez, Jr., collectively, either directly or indirectly, own a majority of the equity interests of SOG. In addition, Antonio R. Sanchez, III and Patricio D. Sanchez are Co-Presidents of SOG; Antonio R. Sanchez, Jr. is the Chief Executive Officer and sole director of SOG; Ana Lee Sanchez Jacobs is an Executive Vice President of SOG; and Gerald F. Willinger is an Executive Vice President of SOG. Sanchez-Related Transactions We have entered into several transactions with Sanchez Energy since January 1, 2017. In conjunction with the acquisition of Western Catarina Midstream, we entered into a 15-year gas gathering agreement with Sanchez Energy, pursuant to which Sanchez Energy agreed to tender all of its crude oil, natural gas and other hydrocarbon-based product volumes on approximately 35,000 dedicated acres in the Western Catarina area of the Eagle Ford Shale in Texas for processing and transportation through Western Catarina Midstream, with the potential to tender additional volumes outside of the dedicated acreage (the “Gathering Agreement”). During the first five years of the term of the Gathering Agreement, Sanchez Energy is required to meet a minimum quarterly volume delivery commitment of 10,200 Bbls per day of oil and condensate and 142,000 Mcf per day of natural gas, subject to certain adjustments. Sanchez Energy is required to pay gathering and processing fees of $0.96 per Bbl for crude oil and condensate and $0.74 per Mcf for natural gas that are tendered through Western Catarina Midstream, in each case, subject to an annual escalation for a positive increase in the consumer price index. For the years ended December 31, 2018 and 2017, Sanchez Energy paid us approximately $57.9 million and $52.8 million, respectively, pursuant to the terms of the gathering and processing agreement. On June 30, 2017, the Gathering Agreement was amended to add an incremental infrastructure fee to be paid by SN Catarina based on water that is delivered through the gathering system through March 31, 2018. Following March 31, 2018, we have agreed with Sanchez Energy to continue the incremental infrastructure fee on a month-to-month basis. As part of the Carnero Gathering Transaction, we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at Carnero Gathering’s delivery points from Sanchez Energy and other producers. For the years ended December 31, 2018 and 2017, we did not make any earnout payments to Sanchez Energy. However, we had a payable of $0.1 million to Sanchez Energy at year end December 31, 2017 related to the earnout. In November 2016, we completed the Carnero Processing Transaction pursuant to which we acquired from Sanchez Energy a 50% interest in Carnero Processing, a joint venture that is 50% owned and operated by Targa, for aggregate cash consideration of approximately $55.5 million and the assumption of remaining capital contribution commitments to Carnero Processing, estimated at approximately $24.5 million as of the date of acquisition. 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 interests 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 $24.2 million. In September 2017, we entered into the Seco Pipeline Transportation Agreement. For the years ended December 31, 2018 and 2017, SN Catarina paid us approximately $7.2 million and $0.9 million, respectively, pursuant to the terms of that agreement. In May 2018, the Carnero JV, which is operated by Targa, received a dedication from Sanchez Energy and its working interest partners of over 315,000 Comanche acres in the Western Eagle Ford pursuant to a new long-term firm gas gathering and processing agreement. The agreement with Sanchez Energy, which was approved by all of the unaffiliated Comanche working interest partners, establishes commercial terms for the gathering of gas on the Carnero Gathering Line and processing at the Raptor Gas Processing Facility and Silver Oak II. Prior to execution of the agreement, Comanche volumes were gathered and processed on an interruptible basis, with the processing capabilities of the joint ventures limited by the capacity of the Raptor Gas Processing Facility. As of December 31, 2018 and 2017, the Partnership had a net receivable from related parties of approximately $6.7 million, and $13.1 million, respectively, which are included in “Accounts receivable – related entities” in the consolidated balance sheets. As of December 31, 2018 and 2017, the Partnership also had a net payable to related parties of approximately $5.6 million, and $10.4 million, respectively. The net receivable/payable as of December 31, 2018 consist primarily of revenues receivable from oil and natural gas production and transportation, offset by costs associated with that production and transportation and ad valorem. Sanchez Energy is an independent exploration and production company focused on the acquisition and development of U.S. onshore unconventional oil and natural gas resources, with a current focus on the horizontal development of significant resource potential from the Eagle Ford Shale in South Texas where it has assembled approximately 473,000 gross leasehold acres (271,000 net acres). The Chairman of the Board, Antonio R. Sanchez, III, is Sanchez Energy’s Chief Executive Officer and a member of its board of directors. A member of the Board, Eduardo A. Sanchez, is the former President of Sanchez Energy. The President and Chief Operating Officer of our general partner, Patricio D. Sanchez, who is also a member of the Board, is an Executive Vice President of Sanchez Energy. Antonio R. Sanchez, Jr., the father of Antonio R. Sanchez, III, Eduardo A. Sanchez, and Patricio D. Sanchez, is the Executive Chairman of the board of directors of Sanchez Energy. Antonio R. Sanchez, Jr., Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez beneficially own 6.5%, 3.2%, 1.2% and 1.3%, respectively , of Sanchez Energy’s shares outstanding as of February 26, 2019. As of March 7, 2019, Sanchez Energy indirectly, through one of its wholly owned subsidiaries, beneficially owns approximately 13.0% of the outstanding common units of SNMP. The employees of SOG, including Kirsten A, Hink, our Chief Accounting Officer, provide services to both us and Sanchez Energy.

Unit-Based Compensation

Unit-Based Compensation	12 Months Ended
	Dec. 31, 2018
Unit-Based Compensation
Unit-Based Compensation	15. UNIT-BASED COMPENSATION The Sanchez Midstream Partners LP Long-Term Incentive Plan allows for restricted common unit grants. Restricted common unit activity under the Plan during the period is presented in the following table: Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2016 219,144 $ 14.22 Granted 220,814 14.73 Vested (153,487) 14.20 Returned/Cancelled (3,333) 13.59 Outstanding at December 31, 2017 283,138 $ 14.64 Granted 622,534 11.94 Vested (301,005) 13.60 Returned/Cancelled (90,973) 12.77 Outstanding at December 31, 2018 513,694 $ 12.31 In April 2018, the Partnership issued 63,630 restricted common units pursuant to the LTIP to certain directors of the Partnership’s general partner that vested immediately on the date of grant. In April 2018, the Partnership issued 244,813 and 314,091 restricted common units pursuant to the LTIP to executives that vest on the first anniversary of the date of grant and to non-executive employees that vest over three years from the date of grant, respectively. In March 2017, the Partnership issued 171,231 restricted common units pursuant to the LTIP to executives of the Partnership’s general partner that vested on the first anniversary of the date of grant in March 2018. The unit-based compensation expense for the award was based on the fair value on the day before the date of grant. As of December 31, 2018, 1,309,385 common units remain available for future issuance to participants under the LTIP.

Distributions To Unitholders

Distributions To Unitholders	12 Months Ended
	Dec. 31, 2018
Distributions To Unitholders
Distributions To Unitholders	16. DISTRIBUTIONS TO UNITHOLDERS The table below reflects the payment of cash distributions on common units relating to the years ended December 31, 2018 and 2017. Distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2017 $ 0.4375 May 10, 2017 May 22, 2017 May 31, 2017 June 30, 2017 $ 0.4441 August 9, 2017 August 22, 2017 August 31, 2017 September 30, 2017 $ 0.4508 November 7, 2017 November 20, 2017 November 30, 2017 December 31, 2017 $ 0.4508 February 8, 2018 February 20, 2018 February 28, 2018 March 31, 2018 $ 0.4508 May 8, 2018 May 22, 2018 May 31, 2018 June 30, 2018 $ 0.4508 August 8, 2018 August 21, 2018 August 31, 2018 September 30, 2018 $ 0.1500 November 9, 2018 November 20, 2018 November 30, 2018 December 31, 2018 $ 0.1500 February 7, 2019 February 20, 2019 February 28, 2019 The table below reflects the payment of distributions on Class B Preferred Units during the years ended December 31, 2018 and 2017. Cash distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2017 (a) $ 0.2258 May 10, 2017 May 22, 2017 May 31, 2017 June 30, 2017 $ 0.28225 August 9, 2017 August 22, 2017 August 31, 2017 September 30, 2017 $ 0.28225 November 7, 2017 November 20, 2017 November 30, 2017 December 31, 2017 $ 0.28225 February 8, 2018 February 20, 2018 February 28, 2018 March 31, 2018 $ 0.28225 May 8, 2018 May 22, 2018 May 31, 2018 June 30, 2018 (b) $ 0.2258 August 8, 2018 August 21, 2018 August 31, 2018 September 30, 2018 $ 0.28225 November 9, 2018 November 20, 2018 November 30, 2018 December 31, 2018 $ 0.28225 February 7, 2019 February 20, 2019 February 28, 2019 (a) The Partnership elected to pay the first-quarter 2017 distribution on the Class B Preferred Units in part cash and, with 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 184,697 common units, which was paid on May 31, 2017 to holders of record on May 22, 2017. (b) The Partnership elected to pay the second-quarter 2018 distribution on the Class B Preferred Units in part cash and part in Class B Preferred PIK Units. Accordingly, the Partnership declared a cash distribution of $0.2258 per Class B Preferred Unit and an aggregate distribution of 310,009 Class B Preferred PIK Units, which was paid on August 31, 2018 to holders of record on August 21, 2018.

Members' Equity_Partners' Capit

Members' Equity/Partners' Capital	12 Months Ended
	Dec. 31, 2018
Members' Equity/Partners' Capital
Members' Equity/Partners' Capital	17. MEMBERS’ EQUITY/PARTNERS’ CAPITAL Outstanding Units As of December 31, 2018, we had 31,310,896 Class B Preferred Units outstanding and 16,486,239 common units outstanding, which included 513,694 unvested restricted common units issued under LTIP. Common Unit Issuances The following table shows the common units issued by the Partnership in 2017 and 2018 to SP Holdings in connection with providing services under the Services Agreement: Common Date of Three months ended units issuance September 30, 2016 170,750 March 6, 2017 December 31, 2016 154,737 March 6, 2017 March 31, 2017 139,110 June 30, 2017 June 30, 2017 170,497 August 31, 2017 September 30, 2017 186,942 November 30, 2017 December 31, 2017 210,978 March 15, 2018 March 31, 2018 220,214 May 31, 2018 June 30, 2018 224,342 September 10, 2018 September 30, 2018 334,010 November 30, 2018 In April 2017, we issued 84,577 common units in registered offerings for gross proceeds of approximately $1.3 million pursuant to a shelf registration statement originally filed with the SEC on March 6, 2015 as updated by that certain prospectus supplement filed with the SEC on April 6, 2017 (the “Shelf Registration Statement”). The Shelf Registration Statement allows the Partnership to sell up to $50.0 million of common units by any method deemed an “at the market offering” (as such term is defined in Rule 415 of the Securities Act of 1933, as amended). Proceeds from such sales are expected to be used to fund general limited partnership purposes, including possible acquisitions. Proceeds from the 2017 at-the-market equity issuance were used for general limited partnership purposes. Class B Preferred Unit Offering On October 14, 2015, pursuant to that certain Class B Preferred Unit Purchase Agreement dated September 25, 2015 between the Partnership and 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 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 acquisition of Western Catarina Midstream, 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 our partnership agreement, holders of the Class B Preferred Units 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 Class B Preferred PIK Units (4.0% per annum), as defined in the Second Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended Partnership Agreement”). 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. In accordance with the partnership agreement, on December 6, 2016, we issued an additional 9,851,996 Class B Preferred Units to Stonepeak. On January 25, 2017, the Partnership and Stonepeak 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 Amended Partnership Agreement. Pursuant to the Settlement Agreement, and in accordance with Section 5.4 of the Amended Partnership Agreement, the Partnership issued 1,704,446 Class B Preferred Units to Stonepeak 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 Amended Partnership Agreement, the Class B Preferred Units are convertible at any time, at the option of Stonepeak, into common units of the Partnership, subject to the requirement to convert a minimum of $17.5 million of Class B Preferred Units. 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. The Partnership elected to pay the second-quarter 2018 distribution on the Class B Preferred Units in part cash and part Class B Preferred PIK Units in accordance with the partnership agreement. Accordingly, the Partnership issued 310,009 Class B Preferred PIK Units on August 31, 2018, to Stonepeak. The Class B Preferred Units are accounted for as mezzanine equity in the consolidated balance sheet consisting of the following (in thousands): December 31, 2018 2017 Mezzanine equity, beginning balance $ 343,912 $ 342,991 Amortization of discount 2,358 1,796 Distributions 36,925 35,875 Distributions paid (33,338) (36,750) Mezzanine equity, ending balance $ 349,857 $ 343,912 Earnings per Unit 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.

Reporting Segments

Reporting Segments	12 Months Ended
	Dec. 31, 2018
Reporting Segments
Reporting Segments	18. 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 natural gas, NGLs and oil. 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 (“CODM”) 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. We realigned the composition of our operating segments to reflect management's view of the operating results during the fourth-quarter 2017. The following tables present financial information for each operating segment for the periods indicated based on the realignment of our operating segments (in thousands): Years Ended December 31, 2018 2017 Production Midstream Production Midstream Segment revenues Natural gas sales $ 953 $ — $ 6,626 $ — Oil sales 21,272 — 23,701 — Natural gas liquid sales 1,709 — 1,997 — Gathering and transportation sales — 6,651 — 55,825 Gathering and transportation lease revenues — 53,025 — — Total segment revenues 23,934 59,676 32,324 55,825 Segment operating costs Lease operating expenses 6,719 1,145 12,066 928 Transportation operating expenses — 12,316 — 11,600 Cost of sales — — 77 — Production taxes 1,104 — 1,476 — Gain on sale of assets (3,186) — (4,150) — Depreciation, depletion and amortization 4,798 21,189 9,522 25,308 Asset impairments — — 4,688 — Accretion expense 198 299 499 274 Total segment operating costs 9,633 34,949 24,178 38,110 Segment other income (loss) Earnings (loss) from equity investments — 12,859 (101) 7,986 Total segment other income (loss) — 12,859 (101) 7,986 Segment operating income $ 14,301 $ 37,586 $ 8,045 $ 25,701 Years Ended December 31, 2018 2017 Reconciliation of segment operating income to net income (loss) Total production operating income $ 14,301 $ 8,045 Total midstream operating income 37,586 25,701 Total segment operating income 51,887 33,746 General and administrative expense (23,653) (22,655) Unit-based compensation expense (1,938) (3,373) Interest expense, net (10,961) (8,341) Other income (expense) 546 (2,417) Income tax expense (190) — Net income (loss) $ 15,691 $ (3,040) The following table summarizes the total assets and capital expenditures by operating segment based on the segment realignment as of December 31, 2018 and 2017 (in thousands): December 31, 2018 Production Midstream Corporate (a) Total Other financial information Total assets $ 53,556 $ 429,523 $ 3,606 $ 486,685 Capital expenditures (b) $ 11 $ 4,856 $ — $ 4,867 December 31, 2017 Production Midstream Corporate (a) Total Other financial information Total assets $ 58,623 $ 468,656 $ 1,144 $ 528,423 Capital expenditures (b) $ 441 $ 46,452 $ — $ 46,893 (a) Corporate assets not reviewed by the CODM on a segment basis consists of cash, certain prepaid expenses, office furniture and other assets. (b) Inclusive of capital contributions made to equity method investments. The following table summarizes the percentage of revenue earned from those customers in the Midstream segment that exceed 10% of the Partnership's consolidated revenue for the periods presented below. Because all remaining production properties are non-operated, there are no customers in the Production segment that exceed 10% of the Partnership’s consolidated revenue. Years Ended December 31, 2018 2017 Midstream Sanchez Energy 71 % 63 % Total 71 % 63 %

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2018
Variable Interest Entities
Variable Interest Entities	19. VARIABLE INTEREST ENTITIES The Partnership’s investment in Carnero JV represents a variable interest entity (“VIE”) that could expose the Partnership to losses. The amount of losses the Partnership could be exposed to from Carnero JV is limited to the capital investment of approximately $114.5 million. As of December 31, 2018, the Partnership had invested approximately $123.8 million in Carnero JV and no debt has been incurred by Carnero JV. 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, 2018 and 2017 (in thousands): December 31, 2018 2017 Acquisitions and capital investments $ 127,899 $ 125,059 Earnings in equity investments 23,144 10,288 Distributions received (36,578) (11,632) Maximum exposure to loss $ 114,465 $ 123,715

Supplemental Information On Oil

Supplemental Information On Oil And Natural Gas Producing Activities	12 Months Ended
	Dec. 31, 2018
Supplemental Information On Oil And Natural Gas Producing Activities
Supplemental Information On Oil And Natural Gas Producing Activities	20. 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, 2018 and 2017 (in thousands): December 31, 2018 2017 Capitalized costs at the end of the period: ⁽ᵃ⁾ Oil and natural gas properties and related equipment (successful efforts method) Proved property $ 112,173 $ 170,750 Less: Accumulated depreciation, depletion, amortization and impairments (65,647) (115,704) Oil and natural gas properties and equipment, net $ 46,526 $ 55,046 (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, 2018 and 2017 (in thousands): Years Ended December 31, 2018 2017 Costs incurred for the period: Acquisition of properties Proved $ — $ — Development costs 11 441 Oil and natural gas properties and equipment, net $ 11 $ 441 The development costs for the years ended December 31, 2018 and 2017 primarily represent costs related to recompletions. We had no exploration and dry hole costs in 2018 and 2017. 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 Reserves of Natural Gas, NGLs and Oil 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, 2016 6,870 3,514 2,426 930 Sales of reserves in place (1,731) (358) (1,280) (93) Revisions of previous estimates 1,062 504 383 175 Production (936) (414) (420) (102) December 31, 2017 5,265 3,246 1,109 910 Sales of reserves in place (1,105) (272) (322) (511) Revisions of previous estimates (268) (199) (261) 192 Production (439) (296) (72) (71) December 31, 2018 3,453 2,479 454 520 Proved developed reserves: December 31, 2017 5,265 3,246 1,109 910 December 31, 2018 3,453 2,479 454 520 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 year end December 31, 2018 and 2017, proved reserve estimates were 3.5 MMBoe and 5.3 MMBoe, respectively. Reserve estimates for those periods were prepared by, Ryder Scott, an independent petroleum engineering firm, and are used for the applicable disclosures in our financial statements. Our 2018 estimates of total proved reserves decreased 1.8 MMBoe from 2017 primarily due to a decrease in reserves of 1.1 MMBoe due to the Louisiana Divestiture, Briggs Divestiture and Cola Divestiture. For proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report were: $66.95 per Bbl for oil, $23.00 per Bbl for NGLs and $3.21 per Mcf for natural gas. Our 2017 estimates of total proved reserves decreased 1.6 MMBoe from 2016 primarily due to a decrease in reserves of 1.7 MMBoe due to the Oklahoma Production Divestiture and Texas Production Divestiture. For proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report were: $48.69 per Bbl for oil, $21.34 per Bbl for NGLs and $3.04 per Mcf for natural gas. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural 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): Years Ended December 31, 2018 2017 Future cash inflows $ 186,675 $ 197,739 Future production costs (99,187) (101,300) Future estimated development costs (4,043) (4,346) Future net cash flows 83,445 92,093 10% annual discount for estimated timing of cash flows (31,199) (35,396) Standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves $ 52,246 $ 56,697 The following table summarizes the principal sources of change in the standardized measure of estimated discounted future net cash flows (in thousands): Years Ended December 31, 2018 2017 Beginning of the period $ 56,697 $ 49,636 Sales and transfers of oil and natural gas, net of production costs (14,795) (14,758) Net changes in prices and production costs related to future production 17,392 15,036 Changes in development costs 207 3,854 Changes in extensions and discoveries — 160 Revisions of previous quantity estimates (4,203) 9,137 Purchases and sales of reserves in place (5,423) (11,952) Accretion discount 5,670 4,964 Change in production rates, timing, and other (3,299) 620 Standardized measure of discounted future net cash flows related to proved oil and natural gas reserves $ 52,246 $ 56,697

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2018
Subsequent Events
Subsequent Events	21. SUBSEQUENT EVENTS On February 7, 2019, the Board declared a fourth-quarter 2018 cash distribution on its common units of $0.15 per unit ($0.60 per unit annualized), which was paid on February 28, 2019 to holders of record on February 20, 2019. The Partnership also declared a fourth-quarter 2018 cash distribution on the Class B Preferred Units of $0.28225 per Class B Preferred Unit, which was paid on February 28, 2019 to holders of record on February 20, 2019. On February 22, 2019, the Partnership paid $2.0 million in principal outstanding under the Credit Agreement resulting in debt outstanding of $178.0 million under the Credit Agreement as of that date. Effective January 1, 2019, the Partnership increased the Western Catarina Midstream tariff rate for throughput volumes from approximately 71,000 net acres on Sanchez Energy’s Catarina Asset which are not currently dedicated under the Gathering Agreement.

Basis Of Presentation And Sum_2

Basis Of Presentation And Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
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. Our business consists of two reportable segments: Production and Midstream. Midstream includes Western Catarina Midstream, the Carnero JV and Seco Pipeline. Production consists of our oil and natural gas properties in Texas and Louisiana. 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 August 2018, the FASB issued Accounting Standards Update (“ASU”) 2018-13 “Fair Value Measurement (ASC 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements,” which modifies the disclosure requirements on fair value measurements. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2019. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In June 2018, the FASB issued ASU 2018-07 “Compensation - Stock Compensation (Topic 718) - Improvements to Nonemployee Share-Based Payment Accounting,” which expands the scope of Topic 718, Compensation – Stock Compensation, to include share-based payment transactions for acquiring goods and services from nonemployees. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2018. We will adopt this guidance beginning in fiscal year 2019. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In January 2017, the FASB issued 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. The Partnership adopted this ASU on January 1, 2018, using a prospective method and did not have an impact on the Partnership’s unaudited condensed consolidated financial statements and related disclosures. In October 2016, the FASB issued ASU 2016-16 “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” which eliminates a current exception in U.S. GAAP to the recognition of the income tax effects of temporary differences that result from intra-entity transfers of non-inventory assets. The intra-entity exception is being eliminated under the ASU. The standard is required to be applied on a modified retrospective basis and is now effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. The adoption of ASU 2016-16 did not have an impact on the Partnership’s unaudited condensed consolidated financial statements and related disclosures. In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This ASU modifies the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in the more timely recognition of losses. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2019, and earlier adoption is permitted. 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. Additionally, in July 2018, the FASB issued ASU 2018-10, “Codification Improvements to Topic 842 (Leases),” which provides narrow amendments to clarify how to apply certain aspects of ASU 2016-02. The Partnership plans on electing the practical expedients disclosed in ASU 2018-10. The effective date in ASU 2018-10 is the same as that of ASU 2016-02. The standards update 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. The Partnership will not early adopt this standard and will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019. The Partnership has substantially completed its review of the impact of the new standard as well as the implementation of a lease accounting software. Adoption of the standard is expected to result in the recognition of assets and liabilities in our consolidated balance sheets for existing operating leases such as compressors and potentially other equipment still being evaluated. Concurrent with the software implementation, the Partnership is incorporating necessary updates to its business processes and controls. The quantitative impacts of the new standard are dependent on the active leases at the time of adoption. As a result, the evaluation of the effect of the new standards will extend over future periods. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” In March, April, May and December 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 requires 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 adopted the standard effective January 1, 2018. For more information, see Note 3 “Revenue Recognition.” 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.
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 natural gas, NGLs and oil; 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.
Revenue Recognition	Revenue Recognition Midstream We recognize revenue from contracts with customers in accordance with Topic 606 and ASC 840 for our midstream segment. The Seco Pipeline Transportation Agreement is our only contract that we account for using Topic 606. Under the Seco Pipeline Transportation Agreement, we agreed to provide transportation services of certain quantities of natural gas from the receipt point to the delivery point. Each MMBtu of natural gas transported is distinct and the transportation services performed on each distinct molecule of product is substantially the same in nature. As such, we applied the series guidance and treat these services as a single performance obligation satisfied over time using volumes delivered as the measure of progress. Additionally, Seco Pipeline Transportation Agreement contains variable consideration in the form of volume variability. As the distinct goods or services (rather than the series) are considered for the purpose of allocating variable consideration, we have taken the optional exception under ASC 606-10-50-14A(b). Under this exception, revenue is alternatively recognized in the period that control is transferred to the customer and the respective variable component of the total transaction price is resolved. The Gathering Agreement (as defined in Note 14. “Related Party Transactions”) was classified as an operating lease at inception and is accounted for under ASC 840, as Sanchez Energy controls the physical use of the property under the lease. Revenues relating to the Gathering Agreement is recognized in the period service is provided. Under this arrangement, 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. Production Our oil, natural gas, and NGL revenue is marketed and sold on our behalf by the respective asset operators, as we do not currently operate any of our production assets. The Eagle Ford Shale properties are operated by SOG and Marathon Oil Company and the Louisiana properties are operated by SOG. We are not party to the contracts with the third-party customers. How ever, we are party to joint operating agreements, which we account for under ASC 808. Both revenues and expenses for these arrangements are recognized based on the information provided to us by the operators. Accounts Receivable, Net Our accounts receivable are primarily from our contractual agreements with Sanchez Energy and its subsidiaries, operators of our oil and natural gas properties 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, 2018 and 2017. 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 receivable are due from operators of our oil and natural gas properties. These sales are generally unsecured and, in some cases, may carry a parent guarantee. 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. We have no off-balance-sheet credit exposure related to our operations or customers. Sanchez Energy accounted for 71% and 63% of total revenue for the years ended December 31, 2018 and 2017, respectively. We are highly dependent upon Sanchez Energy as our most significant customer, and we expect to derive a substantial portion of our revenue from Sanchez Energy in the foreseeable future. Accordingly, we are indirectly subject to the business risks of Sanchez Energy.
Income Taxes	Income Taxes SNMP 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.
Earnings per Unit	Earnings per Unit 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.
Asset Retirement Obligations	Asset Retirement Obligations Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and the credit-adjusted risk-free rate. The inputs are calculated based on historical data as well as current estimates. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset and is included in “Depreciation, depletion, amortization and accretion” in the Partnership’s Consolidated Statements of Operations. To estimate the fair value of an asset retirement obligation, the Partnership employs a present value technique, which reflects certain assumptions, including its credit‑adjusted risk‑free interest rate, inflation rate, the estimated settlement date of the liability and the estimated current cost to settle the liability. Changes in timing or to the original estimate of cash flows will result in change to the carrying amount of the liability.
Oil and Natural Gas Properties	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. 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. As more fully described in Note 8 “Oil and Natural Gas Properties and Related Equipment” to our consolidated financial statements, proved reserves estimates are subject to future revisions when additional information becomes available. All other properties, including the gathering and transportation assets, are stated at historical acquisition cost, net of any impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, and up to 36 years for gathering facilities. Estimated asset retirement costs are recognized when the asset is acquired or placed in service, and are amortized over proved reserves using the units-of-production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates. Oil and natural gas properties are reviewed for impairment 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. Cash flow estimates for the impairment testing are based on third party reserve reports and exclude derivative instruments. Refer to Note 8 “Oil and Natural Gas Properties and Related Equipment” to our consolidated financial statements for additional information.
Reserves of Natural Gas, NGLs and Oil	Reserves of Natural Gas, NGLs and Oil Our estimate of proved reserves is based on the quantities of natural gas, NGLs and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Management estimates the proved reserves attributable to our ownership based on various factors, including consideration of the reserve report prepared by Ryder Scott, an independent oil and natural gas consulting firm. On an annual basis, our proved reserve estimates and the reserve report prepared by Ryder Scott are reviewed by the Audit Committee and the Board. Our financial statements for 2018 and 2017 were prepared using Ryder Scott’s estimates of our proved reserves. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The accuracy of our 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. Our 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 actual quantities of oil and natural gas eventually recovered.
Unit-Based Compensation	Unit-Based Compensation The Partnership records unit-based compensation expense for awards granted to the directors of its general partner (for their services as directors) in accordance with the provisions of Accounting Standards Codification (“ASC”) Topic 718, “Compensation—Stock Compensation.” Unit-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 unit-based award.
Investments	Investments We follow the equity method of accounting when we do not exercise control over the investee, but we can exercise significant influence over the operating and financial policies of the investee. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. We evaluate our equity investments for impairment when evidence indicates the carrying amount of our investment is no longer recoverable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. When the estimated fair value of an equity investment is less than its carrying value and the loss in value is determined to be other than temporary, we recognize the excess of the carrying value over the estimated fair value as an impairment loss within equity earnings (loss) in our consolidated statements of operations.
Earnout Derivatives	Earnout Derivative As part of the Carnero Gathering Transaction (defined in Note 12 “Investments”), we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at Carnero Gathering’s delivery points from Sanchez Energy and other producers. The earnout derivative is accounted for under ASC 815, and we measure its fair value through the use of a Monte Carlo simulation model which utilized observable inputs such as the earnout price and volume commitment, as well as unobservable inputs related to the weighted probabilities of various throughput scenarios.

Revenue Recognition (Tables)

Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue Recognition
Schedule of disaggregation of revenue	The following table displays revenue disaggregated by type of revenue and product type (in thousands): Year December 31, 2018 Production Midstream Total Revenues: Natural gas sales $ 953 $ — $ 953 Oil sales 21,272 — 21,272 Natural gas liquid sales 1,709 — 1,709 Gathering and transportation sales — 6,651 6,651 Gathering and transportation lease revenues — 53,025 53,025 Total revenues $ 23,934 $ 59,676 $ 83,610
Schedule of cumulative effect of adoption of ASC 606	The impact of adopting Topic 606 on our condensed consolidated statements of operations is as follows (in thousands): Year Ended December 31, 2018 As reported Balances without Adoption Topic 606 Effect of change Higher/(Lower) Statement of Operations Gathering and transportation sales $ 6,651 $ 59,676 $ (53,025) Gathering and transportation lease revenues 53,025 — 53,025 Net earnings $ 59,676 $ 59,676 $ —

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 (in thousands): Fair Value Measurements at December 31, 2018 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative assets $ — $ 3,914 $ — $ 3,914 Midstream derivative instrument Earnout derivative liability — — (5,856) (5,856) Total $ — $ 3,914 $ (5,856) $ (1,942) 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, 2017 (in thousands): Fair Value Measurements at December 31, 2017 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative assets $ — $ 1,231 $ — $ 1,231 Midstream derivative instrument Earnout derivative liability — — (6,402) (6,402) Total $ — $ 1,231 $ (6,402) $ (5,171)
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, 2018 (in thousands): Fair Value Measurements at December 31, 2018 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Impairment $ — $ — $ — Total net assets $ — $ — $ — The following table summarizes the non-recurring fair value measurements of our assets and liabilities as of December 31, 2017 (in thousands): Fair Value Measurements at December 31, 2017 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Impairment (a) $ — $ — $ 7,277 Total net assets $ — $ — $ 7,277 During the year ended December 31, 2017, we recorded a non-cash impairment charge of $4.7 million to impair certain of our producing oil and natural gas properties in Texas. The carrying values of the impaired proved properties were reduced to a fair value of $7.3 million, estimated using inputs characteristic of a Level 3 fair value measurement.
Reconciliation Of Changes In Fair Value Of Derivatives Classified As Level 3	The following table sets forth a reconciliation of changes in the fair value of the Partnership's embedded and earnout derivatives classified as Level 3 in the fair value hierarchy (in thousands): December 31, 2018 2017 Beginning balance $ (6,402) $ (4,270) Initial fair value of earnout derivative — 221 Gain (loss) on earnout derivative 546 (2,353) Ending balance $ (5,856) $ (6,402) Gain (loss) included in earnings related to derivatives still held as of December 31, 2018 and 2017, respectively $ 546 $ (2,353)

Derivative And Financial Inst_2

Derivative And Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative And Financial Instruments
Summary Of Derivative Contracts In Place	MTM Fixed Price Swaps – NYMEX (Henry Hub) Three Months Ended (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 2019 119,832 $ 2.85 115,784 $ 2.85 112,032 $ 2.85 108,552 $ 2.85 456,200 $ 2.85 2020 105,104 $ 2.85 102,008 $ 2.85 99,136 $ 2.85 96,200 $ 2.85 402,448 $ 2.85 858,648 MTM Fixed Price Basis Swaps – West Texas Intermediate (WTI) Three Months Ended (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 2019 62,528 $ 60.41 59,552 $ 60.44 57,024 $ 60.48 54,824 $ 60.52 233,928 $ 60.46 2020 52,776 $ 53.50 50,960 $ 53.50 49,224 $ 53.50 47,624 $ 53.50 200,584 $ 53.50 434,512
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, 2018 and 2017 (in thousands): December 31, 2018 2017 Beginning fair value of commodity derivatives $ 1,231 $ 6,436 Net gains on crude oil derivatives 1,400 3,284 Net gains (losses) on natural gas derivatives (84) 663 Net settlements paid (received) on derivative contracts: Oil 1,330 (6,422) Natural gas 37 (2,730) Ending fair value of commodity derivatives $ 3,914 $ 1,231
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) Years Ended December 31, Derivative Type in Income 2018 2017 Commodity – Mark-to-Market Oil sales $ 1,400 $ 3,284 Commodity – Mark-to-Market Natural gas sales (84) 663 $ 1,316 $ 3,947

Oil And Natural Gas Propertie_2

Oil And Natural Gas Properties And Related Equipment (Tables)	12 Months Ended
	Dec. 31, 2018
Oil And Natural Gas Properties And Related Equipment.
Gathering and Transportation Assets	Gathering and transportation assets consist of the following (in thousands): December 31, 2018 2017 Gathering and transportation assets Midstream assets $ 186,406 $ 184,969 Less: Accumulated depreciation and amortization (34,598) (26,870) Total Gathering and transportation assets, net $ 151,808 $ 158,099
Oil and Natural Gas Properties	Oil and natural gas properties consist of the following (in thousands): December 31, 2018 2017 Oil and natural gas properties and related equipment Proved property $ 112,173 $ 170,750 Less: Accumulated depreciation, depletion, amortization and impairments (65,647) (115,704) Oil and natural gas properties and equipment, net $ 46,526 $ 55,046
Depreciation, Depletion, Amortization and Impairments	Depreciation, depletion, amortization and impairments consisted of the following (in thousands): Years Ended December 31, 2018 2017 Depreciation, depletion and amortization of oil and natural gas-related assets $ 4,798 $ 9,413 Depreciation and amortization of gathering and transportation related assets 7,729 11,849 Amortization of intangible assets 13,460 13,568 Total Depreciation, depletion and amortization 25,987 34,830 Asset impairments — 4,688 Total $ 25,987 $ 39,518

Provision For Income Taxes (Tab

Provision For Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Provision For Income Taxes
Summary of Federal and State Income Tax Provision (Benefit)	Years Ended December 31, 2018 2017 Current: Federal $ — $ — State 64 — Total current 64 — Deferred: Federal — — State 126 — Total deferred 126 — Total provision for income taxes $ 190 $ —
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): Years Ended December 31, 2018 2017 Pre-tax net book income (loss) $ 15,881 $ (3,040) Texas Margin Tax (a) 267 (438) Return to accrual 9 — Valuation allowance (86) 438 Provision for income taxes $ 190 $ — Effective income tax rate 1.20 % % (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, 2018 2017 Deferred tax assets (liabilities): Derivative assets $ (15) $ 7 Depreciable, depletable property, plant and equipment (112) 78 Other 1 1 Deferred tax assets (liabilities): (126) 86 Valuation allowance — (86) Total deferred tax assets (liabilities) $ (126) $ —

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation
Reconciliation of changes in asset retirement obligation	The following table is a reconciliation of the ARO (in thousands): December 31, 2018 2017 Asset retirement obligation, beginning balance $ 6,074 $ 13,579 Liabilities added from escalating working interests 288 198 Sales (613) (8,416) Revisions to cost estimates (46) — Settlements — (60) Accretion expense 497 773 Asset retirement obligation, ending balance $ 6,200 $ 6,074

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2018
Intangible Assets
Schedule of Intangible assets	Intangible assets as of December 31, 2018 and 2017 are detailed below (in thousands): December 31, 2018 2017 Beginning balance $ 172,166 $ 185,766 Disposals — (32) Amortization (13,460) (13,568) Ending balance $ 158,706 $ 172,166

Investments (Tables)

Investments (Tables)	12 Months Ended
	Dec. 31, 2018
Investments
Summarized financial information of unconsolidated entities	Summarized financial information of unconsolidated entities is as follows (in thousands): Years Ended December 31, 2019 2018 Sales $ 321,607 $ 136,178 Total expenses 290,073 118,077 Net income $ 31,534 $ 18,101

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
Unit-Based Compensation
Schedule Of Units Activity	Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2016 219,144 $ 14.22 Granted 220,814 14.73 Vested (153,487) 14.20 Returned/Cancelled (3,333) 13.59 Outstanding at December 31, 2017 283,138 $ 14.64 Granted 622,534 11.94 Vested (301,005) 13.60 Returned/Cancelled (90,973) 12.77 Outstanding at December 31, 2018 513,694 $ 12.31

Distributions To Unitholders (T

Distributions To Unitholders (Tables)	12 Months Ended
	Dec. 31, 2018
Common units
Schedule of payment of cash distributions	The table below reflects the payment of cash distributions on common units relating to the years ended December 31, 2018 and 2017. Distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2017 $ 0.4375 May 10, 2017 May 22, 2017 May 31, 2017 June 30, 2017 $ 0.4441 August 9, 2017 August 22, 2017 August 31, 2017 September 30, 2017 $ 0.4508 November 7, 2017 November 20, 2017 November 30, 2017 December 31, 2017 $ 0.4508 February 8, 2018 February 20, 2018 February 28, 2018 March 31, 2018 $ 0.4508 May 8, 2018 May 22, 2018 May 31, 2018 June 30, 2018 $ 0.4508 August 8, 2018 August 21, 2018 August 31, 2018 September 30, 2018 $ 0.1500 November 9, 2018 November 20, 2018 November 30, 2018 December 31, 2018 $ 0.1500 February 7, 2019 February 20, 2019 February 28, 2019
Class B preferred units
Schedule of payment of cash distributions	Cash distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2017 (a) $ 0.2258 May 10, 2017 May 22, 2017 May 31, 2017 June 30, 2017 $ 0.28225 August 9, 2017 August 22, 2017 August 31, 2017 September 30, 2017 $ 0.28225 November 7, 2017 November 20, 2017 November 30, 2017 December 31, 2017 $ 0.28225 February 8, 2018 February 20, 2018 February 28, 2018 March 31, 2018 $ 0.28225 May 8, 2018 May 22, 2018 May 31, 2018 June 30, 2018 (b) $ 0.2258 August 8, 2018 August 21, 2018 August 31, 2018 September 30, 2018 $ 0.28225 November 9, 2018 November 20, 2018 November 30, 2018 December 31, 2018 $ 0.28225 February 7, 2019 February 20, 2019 February 28, 2019 (a) The Partnership elected to pay the first-quarter 2017 distribution on the Class B Preferred Units in part cash and, with 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 184,697 common units, which was paid on May 31, 2017 to holders of record on May 22, 2017. The Partnership elected to pay the second-quarter 2018 distribution on the Class B Preferred Units in part cash and part in Class B Preferred PIK Units. Accordingly, the Partnership declared a cash distribution of $0.2258 per Class B Preferred Unit and an aggregate distribution of 310,009 Class B Preferred PIK Units, which was paid on August 31, 2018 to holders of record on August 21, 2018.

Members' Equity_Partners' Cap_2

Members' Equity/Partners' Capital (Tables)	12 Months Ended
	Dec. 31, 2018
Members' Equity/Partners' Capital
Schedule of common unit issuances	Common Date of Three months ended units issuance September 30, 2016 170,750 March 6, 2017 December 31, 2016 154,737 March 6, 2017 March 31, 2017 139,110 June 30, 2017 June 30, 2017 170,497 August 31, 2017 September 30, 2017 186,942 November 30, 2017 December 31, 2017 210,978 March 15, 2018 March 31, 2018 220,214 May 31, 2018 June 30, 2018 224,342 September 10, 2018 September 30, 2018 334,010 November 30, 2018
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, 2018 2017 Mezzanine equity, beginning balance $ 343,912 $ 342,991 Amortization of discount 2,358 1,796 Distributions 36,925 35,875 Distributions paid (33,338) (36,750) Mezzanine equity, ending balance $ 349,857 $ 343,912

Reporting Segments (Tables)

Reporting Segments (Tables)	12 Months Ended
	Dec. 31, 2018
Reporting Segments
Schedule of segment information	Years Ended December 31, 2018 2017 Production Midstream Production Midstream Segment revenues Natural gas sales $ 953 $ — $ 6,626 $ — Oil sales 21,272 — 23,701 — Natural gas liquid sales 1,709 — 1,997 — Gathering and transportation sales — 6,651 — 55,825 Gathering and transportation lease revenues — 53,025 — — Total segment revenues 23,934 59,676 32,324 55,825 Segment operating costs Lease operating expenses 6,719 1,145 12,066 928 Transportation operating expenses — 12,316 — 11,600 Cost of sales — — 77 — Production taxes 1,104 — 1,476 — Gain on sale of assets (3,186) — (4,150) — Depreciation, depletion and amortization 4,798 21,189 9,522 25,308 Asset impairments — — 4,688 — Accretion expense 198 299 499 274 Total segment operating costs 9,633 34,949 24,178 38,110 Segment other income (loss) Earnings (loss) from equity investments — 12,859 (101) 7,986 Total segment other income (loss) — 12,859 (101) 7,986 Segment operating income $ 14,301 $ 37,586 $ 8,045 $ 25,701
Schedule of reconciliation of segment operating income to net income (loss)	Years Ended December 31, 2018 2017 Reconciliation of segment operating income to net income (loss) Total production operating income $ 14,301 $ 8,045 Total midstream operating income 37,586 25,701 Total segment operating income 51,887 33,746 General and administrative expense (23,653) (22,655) Unit-based compensation expense (1,938) (3,373) Interest expense, net (10,961) (8,341) Other income (expense) 546 (2,417) Income tax expense (190) — Net income (loss) $ 15,691 $ (3,040)
Summary of assets and capital expenditures by operating segment	The following table summarizes the total assets and capital expenditures by operating segment based on the segment realignment as of December 31, 2018 and 2017 (in thousands): December 31, 2018 Production Midstream Corporate (a) Total Other financial information Total assets $ 53,556 $ 429,523 $ 3,606 $ 486,685 Capital expenditures (b) $ 11 $ 4,856 $ — $ 4,867 December 31, 2017 Production Midstream Corporate (a) Total Other financial information Total assets $ 58,623 $ 468,656 $ 1,144 $ 528,423 Capital expenditures (b) $ 441 $ 46,452 $ — $ 46,893 (a) Corporate assets not reviewed by the CODM on a segment basis consists of cash, certain prepaid expenses, office furniture and other assets. (b) Inclusive of capital contributions made to equity method investments.
Summary of Percentage of Revenue Earned from Customers by Segment	Years Ended December 31, 2018 2017 Midstream Sanchez Energy 71 % 63 % Total 71 % 63 %

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 (in thousands): December 31, 2018 2017 Acquisitions and capital investments $ 127,899 $ 125,059 Earnings in equity investments 23,144 10,288 Distributions received (36,578) (11,632) Maximum exposure to loss $ 114,465 $ 123,715

Supplemental Information On O_2

Supplemental Information On Oil And Natural Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 (in thousands): December 31, 2018 2017 Capitalized costs at the end of the period: ⁽ᵃ⁾ Oil and natural gas properties and related equipment (successful efforts method) Proved property $ 112,173 $ 170,750 Less: Accumulated depreciation, depletion, amortization and impairments (65,647) (115,704) Oil and natural gas properties and equipment, net $ 46,526 $ 55,046 (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, 2018 and 2017 (in thousands): Years Ended December 31, 2018 2017 Costs incurred for the period: Acquisition of properties Proved $ — $ — Development costs 11 441 Oil and natural gas properties and equipment, net $ 11 $ 441
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, 2016 6,870 3,514 2,426 930 Sales of reserves in place (1,731) (358) (1,280) (93) Revisions of previous estimates 1,062 504 383 175 Production (936) (414) (420) (102) December 31, 2017 5,265 3,246 1,109 910 Sales of reserves in place (1,105) (272) (322) (511) Revisions of previous estimates (268) (199) (261) 192 Production (439) (296) (72) (71) December 31, 2018 3,453 2,479 454 520 Proved developed reserves: December 31, 2017 5,265 3,246 1,109 910 December 31, 2018 3,453 2,479 454 520
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): Years Ended December 31, 2018 2017 Future cash inflows $ 186,675 $ 197,739 Future production costs (99,187) (101,300) Future estimated development costs (4,043) (4,346) Future net cash flows 83,445 92,093 10% annual discount for estimated timing of cash flows (31,199) (35,396) Standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves $ 52,246 $ 56,697
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): Years Ended December 31, 2018 2017 Beginning of the period $ 56,697 $ 49,636 Sales and transfers of oil and natural gas, net of production costs (14,795) (14,758) Net changes in prices and production costs related to future production 17,392 15,036 Changes in development costs 207 3,854 Changes in extensions and discoveries — 160 Revisions of previous quantity estimates (4,203) 9,137 Purchases and sales of reserves in place (5,423) (11,952) Accretion discount 5,670 4,964 Change in production rates, timing, and other (3,299) 620 Standardized measure of discounted future net cash flows related to proved oil and natural gas reserves $ 52,246 $ 56,697

Basis Of Presentation And Sum_3

Basis Of Presentation And Summary Of Significant Accounting Policies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)segment	Dec. 31, 2017USD ($)
Number of reportable segments | segment	2
Number of business segments | segment	2
Allowance for doubtful accounts | $	$ 400	$ 400
Deferred liabilities | $	$ 126
Oil reserves
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 | Furniture and Equipment
Useful life	15 years
Maximum | Gathering Facilities
Useful life	36 years
Revenue | Customer Concentration Risk
Percentage of sales revenue	71.00%	63.00%
Midstream | Revenue | Customer Concentration Risk | Sanchez Energy
Percentage of sales revenue	71.00%	63.00%

Revenue Recognition (Disaggrega

Revenue Recognition (Disaggregation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Gathering and transportation lease revenues	$ 53,025
Total revenues	83,610	$ 88,149
Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues	953	6,626
Oil sales
Disaggregation of Revenue [Line Items]
Revenues	21,272	23,701
Natural gas liquid product
Disaggregation of Revenue [Line Items]
Revenues	1,709	1,997
Gathering and transportation
Disaggregation of Revenue [Line Items]
Revenues	6,651	55,825
Production
Disaggregation of Revenue [Line Items]
Total revenues	23,934	32,324
Production | Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues	953	6,626
Production | Oil sales
Disaggregation of Revenue [Line Items]
Revenues	21,272	23,701
Production | Natural gas liquid product
Disaggregation of Revenue [Line Items]
Revenues	1,709	1,997
Midstream
Disaggregation of Revenue [Line Items]
Gathering and transportation lease revenues	53,025
Total revenues	59,676	55,825
Midstream | Gathering and transportation
Disaggregation of Revenue [Line Items]
Revenues	$ 6,651	$ 55,825

Revenue Recognition (Contract B

Revenue Recognition (Contract Balances) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Jan. 01, 2018
Revenue Recognition
Performance obligation	true
Payment term (in days)	30 days
Receivables	$ 0.6	$ 1.1

Revenue Recognition (ASC 606) (

Revenue Recognition (ASC 606) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Gathering and transportation lease revenues	$ 53,025
Total revenues	83,610	$ 88,149
Natural gas liquid product
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	1,709	1,997
Oil sales
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	21,272	23,701
Natural gas sales
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	953	6,626
Gathering and transportation
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	6,651	55,825
Midstream
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Gathering and transportation lease revenues	53,025
Total revenues	59,676	55,825
Midstream | Accounting Standards Update 2014-09 | Balances without Adoption Topic 606
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues	59,676
Midstream | Accounting Standards Update 2014-09 | Effect of change Higher/(Lower)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Gathering and transportation lease revenues	53,025
Midstream | Gathering and transportation
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	6,651	$ 55,825
Midstream | Gathering and transportation | Accounting Standards Update 2014-09 | Balances without Adoption Topic 606
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	59,676
Midstream | Gathering and transportation | Accounting Standards Update 2014-09 | Effect of change Higher/(Lower)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenues	$ (53,025)

Acquisitions and Divestitures (

Acquisitions and Divestitures (Details) - USD ($) $ in Millions	Oct. 22, 2018	Apr. 30, 2018	Oct. 31, 2017	May 31, 2017	Jun. 30, 2018	Dec. 31, 2017	Sep. 30, 2017
Louisiana Divestiture
Business Acquisition [Line Items]
Proceeds from divestiture	$ 1.3
Gain on sale	$ 0.6
Oklahoma Production Divestiture
Business Acquisition [Line Items]
Proceeds from divestiture				$ 5.5
Gain on sale							$ 2.4
Briggs Divestiture
Business Acquisition [Line Items]
Proceeds from divestiture		$ 4.5
Proceeds from divestiture after purchase price adjustments		4.2
Gain on sale					$ 1.8
Texas Production Divestiture
Business Acquisition [Line Items]
Proceeds from divestiture			$ 6.3
Gain on sale						$ 1.4
Cola Divestiture
Business Acquisition [Line Items]
Proceeds from divestiture		$ 1
Gain on sale					$ 1.1

Fair Value Measurements (Recurr

Fair Value Measurements (Recurring) (Details) - Recurring - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	$ 3,914	$ 1,231
Earnout derivative liability	(5,856)	(6,402)
Total net assets	(1,942)	(5,171)
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets	3,914	1,231
Total net assets	3,914	1,231
Fair Value, Inputs, Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Earnout derivative liability	(5,856)	(6,402)
Total net assets	$ (5,856)	$ (6,402)

Fair Value Measurements (Non-Re

Fair Value Measurements (Non-Recurring) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2017USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Asset impairments	$ 4,688
Fair Value, Inputs, Level 3 | Nonrecurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment	7,277
Total net assets	$ 7,277

Fair Value Measurements (Embedd

Fair Value Measurements (Embedded and Earnout Derivative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Fair Value Measurements
Beginning Balance	$ (6,402)	$ (4,270)
Initial fair value of earnout derivative		221
Gain (loss) on earnout derivative	546	(2,353)
Ending Balance	$ (5,856)	$ (6,402)

Derivative And Financial Inst_3

Derivative And Financial Instruments (Hedges In Place) (Details)	12 Months Ended
	Dec. 31, 2018MMBTU$ / MMBTU$ / bblbbl
West Texas Intermediate 2019 Swap Quarter 1
Derivative [Line Items]
Volume (in Bbls) | bbl	62,528
Average Price | $ / bbl	60.41
West Texas Intermediate 2019 Swap Quarter 2
Derivative [Line Items]
Volume (in Bbls) | bbl	59,552
Average Price | $ / bbl	60.44
West Texas Intermediate 2019 Swap Quarter 3
Derivative [Line Items]
Volume (in Bbls) | bbl	57,024
Average Price | $ / bbl	60.48
West Texas Intermediate 2019 Swap Quarter 4
Derivative [Line Items]
Volume (in Bbls) | bbl	54,824
Average Price | $ / bbl	60.52
West Texas Intermediate 2019
Derivative [Line Items]
Volume (in Bbls) | bbl	233,928
Average Price | $ / bbl	60.46
West Texas Intermediate 2020 Swap Quarter 1
Derivative [Line Items]
Volume (in Bbls) | bbl	52,776
Average Price | $ / bbl	53.50
West Texas Intermediate 2020 Swap Quarter 2
Derivative [Line Items]
Volume (in Bbls) | bbl	50,960
Average Price | $ / bbl	53.50
West Texas Intermediate 2020 Swap Quarter 3
Derivative [Line Items]
Volume (in Bbls) | bbl	49,224
Average Price | $ / bbl	53.50
West Texas Intermediate 2020 Swap Quarter 4
Derivative [Line Items]
Volume (in Bbls) | bbl	47,624
Average Price | $ / bbl	53.50
West Texas Intermediate 2020
Derivative [Line Items]
Volume (in Bbls) | bbl	200,584
Average Price | $ / bbl	53.50
West Texas Intermediate
Derivative [Line Items]
Volume (in Bbls) | bbl	434,512
NYMEX 2019 Swap Quarter 1
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	119,832
Average Price | $ / MMBTU	2.85
NYMEX 2019 Swap Quarter 2
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	115,784
Average Price | $ / MMBTU	2.85
NYMEX 2019 Swap Quarter 3
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	112,032
Average Price | $ / MMBTU	2.85
NYMEX 2019 Swap Quarter 4
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	108,552
Average Price | $ / MMBTU	2.85
NYMEX 2,019
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	456,200
Average Price | $ / MMBTU	2.85
NYMEX 2020 Swap Quarter 1
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	105,104
Average Price | $ / MMBTU	2.85
NYMEX 2020 Swap Quarter 2
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	102,008
Average Price | $ / MMBTU	2.85
NYMEX 2020 Swap Quarter 3
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	99,136
Average Price | $ / MMBTU	2.85
NYMEX 2020 Swap Quarter 4
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	96,200
Average Price | $ / MMBTU	2.85
NYMEX 2,020
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	402,448
Average Price | $ / MMBTU	2.85
NYMEX
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	858,648

Derivative And Financial Inst_4

Derivative And Financial Instruments (Changes In Fair Value) (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Aug. 31, 2017USD ($)	Dec. 31, 2018USD ($)item	Dec. 31, 2017USD ($)
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives		$ 1,316	$ 3,947
Early termination of hedges	$ 3,600
Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Beginning fair value of commodity derivatives		1,231	6,436
Ending fair value of commodity derivatives		$ 3,914	1,231
Number of counterparties | item		4
Oil reserves | Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives		$ 1,400	3,284
Net settlements paid (received) on derivative contracts		1,330
Net settlements paid (received) on derivative contracts			(6,422)
Natural gas | Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives		(84)	663
Net settlements paid (received) on derivative contracts		$ 37
Net settlements paid (received) on derivative contracts			$ (2,730)

Derivative And Financial Inst_5

Derivative And Financial Instruments (Effect On Statement Of Operations) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Embedded Derivative [Line Items]
Net gains (losses) on derivatives	$ 1,316	$ 3,947
Oil reserves | Commodity Contract
Embedded Derivative [Line Items]
Net gains (losses) on derivatives	1,400	3,284
Natural gas | Commodity Contract
Embedded Derivative [Line Items]
Net gains (losses) on derivatives	$ (84)	$ 663

Long-Term Debt (Details)

Long-Term Debt (Details)	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Line of Credit Facility [Line Items]
Letters of credit outstanding	$ 0
Unamortized debt issue costs	1,400,000	$ 1,200,000
Amortization of debt issuance costs	783,000	$ 524,000
Credit Agreement
Line of Credit Facility [Line Items]
Maximum borrowing capacity	310,000,000
Sub-limit which may be used for issuance of letters of credit	15,000,000
Initial borrowing capacity	200,000,000
Number of installments	$ 3
Borrowing base term	3 months
Credit agreement, outstanding	$ 180,000,000
Credit agreement available	$ 30,000,000
Commitment fee on unutilized borrowing base	0.50%
Credit Agreement | Scenario One
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4
Credit Facility Maturing March 31, 2020
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 500,000,000
Lender loan
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 210,000,000
Minimum | Credit Agreement
Line of Credit Facility [Line Items]
Required interest coverage ratio	2.5
Ownership percentage by subsidiary	50
Distribution limitation, credit facility excess over borrowing base (as a percent)	90.00%
Required working capital ratio	1
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 Three
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4.5

Oil And Natural Gas Propertie_3

Oil And Natural Gas Properties And Related Equipment (Gathering and Transportation Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Midstream assets	$ 186,406	$ 184,969
Less: Accumulated depreciation and amortization	(65,647)	(115,704)
Midstream
Property, Plant and Equipment [Line Items]
Midstream assets	186,406	184,969
Less: Accumulated depreciation and amortization	(34,598)	(26,870)
Total Gathering and transportation assets, net	$ 151,808	$ 158,099

Oil And Natural Gas Propertie_4

Oil And Natural Gas Properties And Related Equipment (Properties) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Oil And Natural Gas Properties And Related Equipment.
Proved property	$ 112,173	$ 170,750
Less: Accumulated depreciation, depletion, amortization and impairments	(65,647)	(115,704)
Oil and natural gas properties and equipment, net	$ 46,526	$ 55,046

Oil And Natural Gas Propertie_5

Oil And Natural Gas Properties And Related Equipment (DDA and Impairments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Amortization of intangible assets	$ 13,460	$ 13,568
Depreciation, depletion and amortization	12,527	21,262
Asset impairments	0	4,688
Total	25,987	39,518
Exploration and dry hole costs	$ 0	0
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	$ 4,798	9,413
Gathering and Transportation Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	7,729	11,849
Oil and Natural Gas-Related Assets and Gathering and Transportation-Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	$ 25,987	$ 34,830

Provision For Income Taxes (Inc

Provision For Income Taxes (Income Tax Provision (Benefit)) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)
Current:
State	$ 64
Total current	64
Deferred:
State	126
Total deferred	126
Income tax expense	$ 190

Provision For Income Taxes (Rec

Provision For Income Taxes (Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Provision For Income Taxes
Pre-tax net book income (loss)	$ 15,881	$ (3,040)
Texas Margin Tax	267	(438)
Return to accrual	9
Valuation allowance	(86)	$ 438
Provision for income taxes	$ 190
Effective income tax rate	1.20%	0.00%

Provision For Income Taxes (DTA

Provision For Income Taxes (DTA and DTL) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Deferred tax assets (liabilities):
Derivative assets		$ 7
Derivative assets, liability	$ (15)
Depreciable, depletable property, plant and equipment		78
Depreciable, depletable property, plant and equipment	(112)
Other	1	1
Deferred tax assets:		86
Deferred tax liabilities:	(126)
Valuation allowance		$ (86)
Total deferred tax liabilities	$ (126)

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation
Asset retirement obligation, beginning balance	$ 6,074,000	$ 13,579,000
Liabilities added from escalating working interests	288,000	198,000
Sales	(613,000)	(8,416,000)
Revisions to cost estimates	(46,000)
Settlements		(60,000)
Accretion expense	497,000	773,000
Asset retirement obligation, ending balance	6,200,000	6,074,000
Legally restricted assets	$ 0	$ 0

Intangible Assets (Details)

Intangible Assets (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)a	Dec. 31, 2017USD ($)
Finite-Lived Intangible Assets [Line Items]
Beginning balance	$ 172,166	$ 185,766
Disposals		(32)
Amortization	(13,460)	(13,568)
Ending balance	$ 158,706	$ 172,166
Customer Contracts
Finite-Lived Intangible Assets [Line Items]
Agreement term (in years)	15 years
Dedicated acreage | a	35,000
Useful life	15 years

Investments (Details)

Investments (Details) $ in Thousands	1 Months Ended			4 Months Ended	12 Months Ended
	May 31, 2018aMMcf	Nov. 30, 2016USD ($)	Jul. 31, 2016USD ($)	Apr. 30, 2018MMcf	Dec. 31, 2018USD ($)ami	Dec. 31, 2017USD ($)
Schedule of Equity Method Investments [Line Items]
Acquisitions and capital investments					$ 127,899	$ 125,059
Earnings (loss) from equity investments					12,859	7,885
Amortization of intangible assets					13,460	13,568
Distributions received					24,946	$ 8,720
Carnero Gathering, Joint Venture
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)			50.00%
Payments to acquire interest in joint venture			$ 37,000		123,800
Assumption of capital commitments in joint venture			7,400
Daily processing capacity | MMcf	400
Acres dedicated for gathering | a	315,000
Carnero Gathering, Joint Venture | Customer Relationships
Schedule of Equity Method Investments [Line Items]
Intangible asset, fair value			$ 13,000
Agreement term (in years)			15 years
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
Carnero G&P, Joint Venture
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)	50.00%
Payments to acquire interest in joint venture					$ 123,800
Daily processing capacity | MMcf	460			260
Number of miles of high pressure natural gas gathering pipelines | mi					45
Acres dedicated for gathering | a	315,000
Earnings (loss) from equity investments					$ 14,000
Amortization of intangible assets					$ 1,200
Sanchez Energy
Schedule of Equity Method Investments [Line Items]
Assumption of capital commitments in joint venture		$ 24,200
Acres dedicated for gathering | a					473,000
Targa | Carnero G&P, Joint Venture
Schedule of Equity Method Investments [Line Items]
Equity interests in plant transferred to joint venture (as a percent)	100.00%

Investments (Unconsolidated Ent

Investments (Unconsolidated Entities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Investments
Sales	$ 321,607	$ 136,178
Total expenses	290,073	118,077
Net income	$ 31,534	$ 18,101

Commitments And Contingencies (

Commitments And Contingencies (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Recurring
Variable Interest Entity [Line Items]
Earnout derivative liability	$ 5,856	$ 6,402

Related Party Transactions (Det

Related Party Transactions (Details) $ in Millions	Oct. 14, 2015a$ / bbl$ / McfbblMMcf	Jul. 31, 2016USD ($)	Dec. 31, 2018USD ($)a	Dec. 31, 2017USD ($)	Mar. 07, 2019	Feb. 26, 2019	May 31, 2018a	Nov. 30, 2016USD ($)item
Related Party Transaction [Line Items]
Related parties, net receivable			$ 6.7	$ 13.1
Related parties, net payable			$ 5.6	10.4
Sanchez Energy
Related Party Transaction [Line Items]
Acres dedicated for gathering | a			473,000
Assumption of capital commitments in joint venture								$ 24.2
Accrued payable, value				0.1
Net acres assembled | a			271,000
SP Holdings
Related Party Transaction [Line Items]
Quarterly fee (as a percent)			0.375%
Maximum asset acquisition, disposition and financing fee (as a percent)			2.00%
Agreement term (in years)			10 years
Services Agreement renewal term			10 years
Agreement notice period			180 days
Administrative fee			$ 8.6	8.8
SN Catarina
Related Party Transaction [Line Items]
Proceeds from transportation agreement			7.2	0.9
Targa
Related Party Transaction [Line Items]
Ownership interest (as a percent)								50.00%
Carnero Gathering, Joint Venture
Related Party Transaction [Line Items]
Acres dedicated for gathering | a							315,000
Ownership interest (as a percent)		50.00%
Payments to acquire interest in joint venture		$ 37	123.8
Assumption of capital commitments in joint venture		$ 7.4
Acquisition of Wellbore Interests | Sanchez Energy
Related Party Transaction [Line Items]
Producing wellbores | item								23
Acquisition of Working Interests | Sanchez Energy
Related Party Transaction [Line Items]
Producing wellbores | item								11
Western Catarina Midstream
Related Party Transaction [Line Items]
Agreement term (in years)	15 years
Acres dedicated for gathering | a	35,000
Gathering Agreement delivery commitment period	5 years
Western Catarina Midstream | Oil reserves
Related Party Transaction [Line Items]
Gathering Agreement minimum quarterly volume delivery commitment | bbl	10,200
Gathering and processing fees (in dollars per volume) | $ / bbl	0.96
Western Catarina Midstream | Natural gas
Related Party Transaction [Line Items]
Gathering Agreement minimum quarterly volume delivery commitment | MMcf	142,000
Gathering and processing fees (in dollars per volume) | $ / Mcf	0.74
Western Catarina Midstream | Sanchez Energy
Related Party Transaction [Line Items]
Proceeds from gathering and processing agreement			$ 57.9	$ 52.8
Common units | Sanchez Energy
Related Party Transaction [Line Items]
Ownership by related parties (as a percentage)					13.00%
Common units | Sanchez Energy | Antonio R. Sanchez Jr.
Related Party Transaction [Line Items]
Ownership by related parties (as a percentage)						6.50%
Common units | Sanchez Energy | Antonio R. Sanchez, III
Related Party Transaction [Line Items]
Ownership by related parties (as a percentage)						3.20%
Common units | Sanchez Energy | Eduardo A. Sanchez
Related Party Transaction [Line Items]
Ownership by related parties (as a percentage)						1.20%
Common units | Sanchez Energy | Patricio D Sanchez
Related Party Transaction [Line Items]
Ownership by related parties (as a percentage)						1.30%

Unit-Based Compensation (Restri

Unit-Based Compensation (Restricted Units Activity) (Details) - LTIP - $ / shares	1 Months Ended		12 Months Ended
	Apr. 30, 2018	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted	314,091
Units available for issuance			1,309,385
Vesting period			3 years
Executives
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted	244,813
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding			283,138	219,144
Number of Restricted Units, Granted		171,231	622,534	220,814
Number of Restricted Units, Vested			(301,005)	(153,487)
Number of Restricted Units, Returned/Cancelled			(90,973)	(3,333)
Number of Restricted Units, Outstanding			513,694	283,138
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding			$ 14.64	$ 14.22
Weighted Averaged Grant Date Fair Value Per Unit, Granted			11.94	14.73
Weighted Averaged Grant Date Fair Value Per Unit, Vested			13.60	14.20
Weighted Averaged Grant Date Fair Value Per Unit, Returned/Cancelled			12.77	13.59
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding			$ 12.31	$ 14.64
Restricted Stock Units (RSUs) | Director
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted	63,630

Distributions To Unitholders (D

Distributions To Unitholders (Details) - $ / shares	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017
Common units
Distribution paid per unit	$ 0.1500	$ 0.1500	$ 0.4508	$ 0.4508	$ 0.4508	$ 0.4508	$ 0.4441	$ 0.4375
Aggregate distribution of units										393,291
Class B preferred units
Distribution paid per unit	$ 0.28225	$ 0.28225	$ 0.2258	$ 0.28225	$ 0.28225	$ 0.28225	$ 0.28225	$ 0.2258
Aggregate distribution of units								184,697	310,009

Members' Equity_Partners' Cap_3

Members' Equity/Partners' Capital (Details) - USD ($) $ / shares in Units, $ in Thousands	Jan. 25, 2017	Oct. 14, 2015	Apr. 30, 2017	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015	Dec. 31, 2018	Dec. 31, 2017	Aug. 31, 2018	Dec. 06, 2016
Limited Partners' Capital Account [Line Items]
Class B preferred units, outstanding							31,000,887							31,310,896	31,000,887
Common units, outstanding							14,965,134							16,486,239	14,965,134
Units, issued							14,965,134							16,486,239	14,965,134
Proceeds from common units sold															$ 1,290
Class B preferred units, issued							31,000,887							31,310,896	31,000,887
Class B preferred units
Limited Partners' Capital Account [Line Items]
Class B preferred units, outstanding														31,310,896
Units, issued																310,009	9,851,996
Units sold (in units)		19,444,445
Price per unit sold		$ 18
Proceeds from preferred units sold		$ 350,000
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 units per annum													4.00%
Class B preferred units | Settlement Agreement with Stonepeak Catarina Holdings LLC
Limited Partners' Capital Account [Line Items]
Class B preferred units, issued	1,704,446
Class B preferred units, unit price	$ 11.29
Common units
Limited Partners' Capital Account [Line Items]
Common units, outstanding														16,486,239
Units, issued			84,577
Units sold (in units)				334,010	224,342	220,214	210,978	186,942	170,497	139,110	154,737	170,750
Proceeds from common units sold			$ 1,300
Common units authorized for sale, value			$ 50,000
Unvested restricted common units | LTIP
Limited Partners' Capital Account [Line Items]
Common units, outstanding														513,694
Minimum | Class B preferred units
Limited Partners' Capital Account [Line Items]
Preferred unit conversion, amount														$ 17,500

Members' Equity_Partners' Cap_4

Members' Equity/Partners' Capital (Class B Preferred Units) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Mezzanine equity, beginning balance	$ 343,912
Distributions	33,338	$ 31,500
Mezzanine equity, ending balance	349,857	343,912
Class B preferred units
Mezzanine equity, beginning balance	343,912	342,991
Amortization of discount	2,358	1,796
Distributions	36,925	35,875
Distributions paid	(33,338)	(36,750)
Mezzanine equity, ending balance	$ 349,857	$ 343,912

Reporting Segments (Segment Inf

Reporting Segments (Segment Information) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Segment operating revenues:
Gathering and transportation lease revenues	$ 53,025
Total revenues	83,610	$ 88,149
Segment operating costs:
Lease operating expenses	7,864	12,994
Transportation operating expenses	12,316	11,600
Cost of sales		77
Production taxes	1,104	1,476
Gain on sale of assets	(3,186)	(4,150)
Depreciation, depletion and amortization	25,987	34,830
Asset impairments	0	4,688
Accretion expense	497	773
Total operating expenses	70,173	88,316
Segment other income (loss)
Earnings (loss) from equity investments	12,859	7,885
Segment operating income	51,887	33,746
Production
Segment operating revenues:
Total revenues	23,934	32,324
Segment operating costs:
Lease operating expenses	6,719	12,066
Cost of sales		77
Production taxes	1,104	1,476
Gain on sale of assets	(3,186)	(4,150)
Depreciation, depletion and amortization	4,798	9,522
Asset impairments		4,688
Accretion expense	198	499
Total operating expenses	9,633	24,178
Segment other income (loss)
Earnings (loss) from equity investments		(101)
Total segment other income (loss)		(101)
Segment operating income	14,301	8,045
Midstream
Segment operating revenues:
Gathering and transportation lease revenues	53,025
Total revenues	59,676	55,825
Segment operating costs:
Lease operating expenses	1,145	928
Transportation operating expenses	12,316	11,600
Depreciation, depletion and amortization	21,189	25,308
Accretion expense	299	274
Total operating expenses	34,949	38,110
Segment other income (loss)
Earnings (loss) from equity investments	12,859	7,986
Total segment other income (loss)	12,859	7,986
Segment operating income	37,586	25,701
Natural gas sales
Segment operating revenues:
Revenues	953	6,626
Natural gas sales | Production
Segment operating revenues:
Revenues	953	6,626
Oil sales
Segment operating revenues:
Revenues	21,272	23,701
Oil sales | Production
Segment operating revenues:
Revenues	21,272	23,701
Natural gas liquid product
Segment operating revenues:
Revenues	1,709	1,997
Natural gas liquid product | Production
Segment operating revenues:
Revenues	1,709	1,997
Gathering and transportation
Segment operating revenues:
Revenues	6,651	55,825
Gathering and transportation | Midstream
Segment operating revenues:
Revenues	$ 6,651	$ 55,825

Reporting Segments - Reconcilia

Reporting Segments - Reconciliation of Segment Operating Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of segment operating income to net income (loss):
Segment operating income	$ 51,887	$ 33,746
General and administrative expense	(23,653)	(22,655)
Unit-based compensation expense	(1,938)	(3,373)
Interest expense, net	(10,961)	(8,341)
Other income (expense)	546	(2,417)
Income tax expense	(190)
Net income (loss)	15,691	(3,040)
Production
Reconciliation of segment operating income to net income (loss):
Segment operating income	14,301	8,045
Midstream
Reconciliation of segment operating income to net income (loss):
Segment operating income	$ 37,586	$ 25,701

Reporting Segments (Assets by S

Reporting Segments (Assets by Segment) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 486,685	$ 528,423
Capital expenditures	4,867	46,893
Production
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	53,556	58,623
Capital expenditures	11	441
Midstream
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	429,523	468,656
Capital expenditures	4,856	46,452
Corporate
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 3,606	$ 1,144

Reporting Segments (Percentage

Reporting Segments (Percentage of Revenue) (Details) - Revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenue, Major Customer [Line Items]
Percentage of revenue	71.00%	63.00%
Midstream | Sanchez Energy
Revenue, Major Customer [Line Items]
Percentage of revenue	71.00%	63.00%

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Jul. 31, 2016	Dec. 31, 2018	Dec. 31, 2017
Variable Interest Entity [Line Items]
Acquisitions and capital investments		$ 127,899	$ 125,059
Earnings in equity investments		23,144	10,288
Distributions received		(36,578)	(11,632)
Maximum exposure to loss		114,465	$ 123,715
Carnero Gathering, Joint Venture
Variable Interest Entity [Line Items]
Payments to acquire interest in joint venture	$ 37,000	123,800
Debt incurred		$ 0

Supplemental Information On O_3

Supplemental Information On Oil And Natural Gas Producing Activities (Capitalized Costs) (Details) - USD ($) $ in Thousands		Dec. 31, 2018	Dec. 31, 2017
Supplemental Information On Oil And Natural Gas Producing Activities
Proved property	[1]	$ 112,173	$ 170,750
Less: accumulated depreciation, depletion, amortization and impairments	[1]	(65,647)	(115,704)
Oil and natural gas properties and equipment, net	[1]	$ 46,526	$ 55,046
[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 O_4

Supplemental Information On Oil And Natural Gas Producing Activities (Costs Incurred Production) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Supplemental Information On Oil And Natural Gas Producing Activities
Development costs	$ 11	$ 441
Oil and natural gas properties and equipment, net	$ 11	$ 441

Supplemental Information On O_5

Supplemental Information On Oil And Natural Gas Producing Activities (Proved Reserves) (Details) - MMBoe	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Changes in proved developed and undeveloped reserves
Balance	5,265	6,870
Sales of reserves in place	(1,105)	(1,731)
Revisions of previous estimates	(268)	1,062
Production	(439)	(936)
Balance	3,453	5,265
Proved developed reserves	3,453	5,265
Oil reserves
Changes in proved developed and undeveloped reserves
Balance	3,246	3,514
Sales of reserves in place	(272)	(358)
Revisions of previous estimates	(199)	504
Production	(296)	(414)
Balance	2,479	3,246
Proved developed reserves	2,479	3,246
Natural gas
Changes in proved developed and undeveloped reserves
Balance	1,109	2,426
Sales of reserves in place	(322)	(1,280)
Revisions of previous estimates	(261)	383
Production	(72)	(420)
Balance	454	1,109
Proved developed reserves	454	1,109
Natural gas liquids
Changes in proved developed and undeveloped reserves
Balance	910	930
Sales of reserves in place	(511)	(93)
Revisions of previous estimates	192	175
Production	(71)	(102)
Balance	520	910
Proved developed reserves	520	910

Supplemental Information On O_6

Supplemental Information On Oil And Natural Gas Producing Activities (Proved Reserves Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)MMBoe$ / bbl$ / Mcf	Dec. 31, 2017USD ($)MMBoe$ / bbl	Dec. 31, 2016MMBoe
Reserve Quantities [Line Items]
Exploration and dry hole costs | $	$ 0	$ 0
Proved reserve estimates	3,453	5,265	6,870
Reserve revision	3,453	5,265
Oil reserves
Reserve Quantities [Line Items]
Proved reserve estimates	2,479	3,246	3,514
Reserve revision	2,479	3,246
Weighted-average product price | $ / bbl	66.95	48.69
Natural gas
Reserve Quantities [Line Items]
Proved reserve estimates	454	1,109	2,426
Reserve revision	454	1,109
Weighted-average product price	3.21	3.04
Natural gas liquids
Reserve Quantities [Line Items]
Proved reserve estimates	520	910	930
Reserve revision	520	910
Weighted-average product price | $ / bbl	23	21.34
Louisiana, Briggs, and Cola Divestiture
Reserve Quantities [Line Items]
Increase (decrease) in proved reserve estimates	1,800,000	1,100,000
Oklahoma and Texas Production Divestiture
Reserve Quantities [Line Items]
Increase (decrease) in proved reserve estimates		1,600,000	1,700,000

Supplemental Information On O_7

Supplemental Information On Oil And Natural Gas Producing Activities (Standardized Measure) (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Information On Oil And Natural Gas Producing Activities
Future cash inflows	$ 186,675	$ 197,739
Future production costs	(99,187)	(101,300)
Future estimated development costs	(4,043)	(4,346)
Future net cash flows	83,445	92,093
10% annual discount for estimated timing of cash flows	(31,199)	(35,396)
Standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves	$ 52,246	$ 56,697	$ 49,636

Supplemental Information On O_8

Supplemental Information On Oil And Natural Gas Producing Activities (Change Standardized Measure) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Supplemental Information On Oil And Natural Gas Producing Activities
Beginning of the period	$ 56,697	$ 49,636
Sales and transfers of oil and natural gas, net of production costs	(14,795)	(14,758)
Net changes in prices and production costs related to future production	17,392	15,036
Changes in development costs	207	3,854
Changes in extensions and discoveries		160
Revisions of previous quantity estimates	(4,203)	9,137
Purchases and sales of reserves in place	(5,423)	(11,952)
Accretion discount	5,670	4,964
Change in production rates, timing, and other	(3,299)	620
Standardized measure of discounted future net cash flows related to proved oil and natural gas reserves	$ 52,246	$ 56,697

Subsequent Events (Details)

Subsequent Events (Details) $ / shares in Units, $ in Millions	Feb. 22, 2019USD ($)	Feb. 07, 2019$ / shares	Jan. 01, 2019a	Dec. 31, 2018USD ($)a
Sanchez Energy
Subsequent Event [Line Items]
Net acres | a				271,000
Credit Agreement
Subsequent Event [Line Items]
Outstanding debt | $				$ 180
Subsequent event | Sanchez Energy | Western Catarina Midstream
Subsequent Event [Line Items]
Net acres | a			71,000
Subsequent event | Credit Agreement
Subsequent Event [Line Items]
Outstanding debt | $	$ 2
Payment of principal | $	$ 178
Subsequent event | Common units
Subsequent Event [Line Items]
Distribution declared per unit | $ / shares		$ 0.15
Annual distribution declared per unit | $ / shares		0.60
Subsequent event | Class B preferred units
Subsequent Event [Line Items]
Distribution declared per unit | $ / shares		$ 0.28225