Evolve Transition Infrastructure (SNMP) 10-K 13 Mar 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2019	Mar. 13, 2020	Jun. 28, 2019
Document And Entity Information
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Registrant Name	Sanchez Midstream Partners LP
Entity Central Index Key	0001362705
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		19,975,193
Entity Public Float			$ 24,442,184
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, 2019	Dec. 31, 2018
Revenues
Gathering and transportation lease revenues	$ 59,090	$ 53,025
Total revenues	76,649	83,610
Operating expenses
Lease operating expenses	7,378	7,864
Transportation operating expenses	11,553	12,316
Production taxes	621	1,104
General and administrative expenses	17,610	23,653
Unit-based compensation expense	1,351	1,938
Gain on sale of assets		(3,186)
Depreciation, depletion and amortization	25,333	25,987
Asset impairments	32,119
Accretion expense	526	497
Total operating expenses	96,491	70,173
Other (income) expense
Interest expense, net	39,789	10,961
Earnings from equity investments	(2,831)	(12,859)
Other income	(5,860)	(546)
Total other (income) expenses	31,098	(2,444)
Total expenses	127,589	67,729
Income (loss) before income taxes	(50,940)	15,881
Income tax expense	202	190
Net income (loss)	(51,142)	15,691
Preferred unit paid-in-kind distributions	(14,409)	(3,500)
Preferred unit distributions	(8,838)	(33,425)
Preferred unit amortization	(1,708)	(2,358)
Deemed contribution	103,773
Net income (loss) attributable to common unitholders - Basic	27,676	(23,592)
Mark-to-market on Warrant	(3,244)
Net income (loss) attributable to common unitholders - Diluted	$ 24,432	$ (23,592)
Net income (loss) per unit
Common units - Basic (in dollars per share)	$ 1.46	$ (1.55)
Common units - Diluted (in dollars per share)	$ 1.23	$ (1.55)
Common units - Basic	18,939,145	15,264,284
Common units - Diluted	19,810,679	15,264,284
Natural gas sales
Revenues
Revenues	$ 683	$ 953
Oil sales
Revenues
Revenues	9,512	21,272
Natural gas liquid sales
Revenues
Revenues	539	1,709
Gathering and transportation sales
Revenues
Revenues	$ 6,825	$ 6,651

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 5,099	$ 2,934
Accounts receivable	133	277
Accounts receivable - related entities	6,719	6,700
Prepaid expenses	1,193	931
Fair value of commodity derivative instruments	226	3,044
Total current assets	13,370	13,886
Oil and natural gas properties and related equipment
Oil and natural gas properties, equipment and facilities (successful efforts method)	112,476	112,173
Gathering and transportation assets	186,941	186,406
Less: accumulated depreciation, depletion, amortization and impairment	(144,189)	(100,245)
Oil and natural gas properties and equipment, net	155,228	198,334
Other assets
Intangible assets, net	145,246	158,706
Fair value of commodity derivative instruments		876
Equity investments	100,311	114,465
Other non-current assets	285	418
Total assets	414,440	486,685
Current liabilities
Accounts payable and accrued liabilities	5,347	4,678
Accounts payable and accrued liabilities - related entities	631	5,641
Royalties payable	359	359
Short-term debt, net of debt issuance costs	39,374
Fair value of commodity derivative instruments	985	6
Other liabilities		125
Total current liabilities	46,696	10,809
Other liabilities
Long term accrued liabilities - related entities	4,892
Asset retirement obligation	6,898	6,200
Long-term debt, net of debt issuance costs	109,437	178,582
Class C Preferred Units	281,688
Other liabilities	629	5,857
Total other liabilities	403,544	190,639
Total liabilities	450,240	201,448
Commitments and contingencies (See Note 13)
Mezzanine equity
Class B Preferred Units, zero and 31,310,896 units issued and outstanding as of December 31, 2019 and 2018, respectively		349,857
Partners' deficit
Common units, 20,087,462 and 16,486,239 units issued and outstanding as of December 31, 2019 and 2018, respectively	(35,800)	(64,620)
Total partners' deficit	(35,800)	(64,620)
Total liabilities and partners' deficit	$ 414,440	$ 486,685

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - shares	Dec. 31, 2019	Dec. 31, 2018
Consolidated Balance Sheets
Class B preferred units, issued	0	31,310,896
Class B preferred units, outstanding	0	31,310,896
Units, issued	20,087,462	16,486,239
Units, outstanding	20,087,462	16,486,239

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities:
Net income (loss)	$ (51,142)	$ 15,691
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation and depletion	11,873	12,527
Amortization of debt issuance costs	1,266	783
Accretion of Class C discount	13,129
Class C distribution accrual	19,309
Asset impairments	32,119
Accretion expense	526	497
Distributions from equity investments	17,227	24,946
Equity earnings in affiliate	(2,831)	(12,859)
Gain on sale of assets		(3,186)
Mark-to-market on Warrant	(3,244)
Net loss (gain) on commodity derivative contracts	3,772	(1,316)
Net cash settlements received (paid) on commodity derivative contracts	1,101	(1,326)
Unit-based compensation	1,351	1,938
Gain on earnout derivative	(5,856)	(546)
Amortization of intangible assets	13,460	13,460
Changes in Operating Assets and Liabilities:
Accounts receivable	(6)	(377)
Accounts receivable - related entities	(23)	6,389
Prepaid expenses	(262)	1,739
Other assets	83	82
Accounts payable and accrued liabilities	6,378	13,719
Accounts payable and accrued liabilities- related entities	(122)	(5,333)
Royalties payable		(12)
Other long-term liabilities	(123)	126
Net cash provided by operating activities	57,985	66,942
Cash flows from investing activities:
Development of oil and natural gas properties	(131)	(11)
Proceeds from sale of assets		7,692
Construction of gathering and transportation assets	(1,063)	(2,533)
Contributions to equity affiliates	(242)	(2,838)
Net cash provided by (used in) investing activities	(1,436)	2,310
Cash flows from financing activities:
Payments for offering costs		(50)
Payments for Class C Preferred Unit Exchange	(238)
Proceeds from issuance of debt	4,000	2,000
Repayment of debt	(34,000)	(11,000)
Distributions to common unitholders	(5,216)	(23,243)
Class B Preferred Unit cash distributions	(17,675)	(33,338)
Units tendered by SOG employees for tax withholdings	(218)
Debt issuance costs	(1,037)	(1,008)
Net cash used in financing activities	(54,384)	(66,639)
Net increase in cash and cash equivalents	2,165	2,613
Cash and cash equivalents, beginning of period	2,934	321
Cash and cash equivalents, end of period	5,099	2,934
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	528	525
Cash paid during the period for income taxes	138
Cash paid during the period for interest	$ 9,159	$ 9,763

Consolidated Statements of Chan

Consolidated Statements of Changes in Partners’ Capital - USD ($) $ in Thousands	Common units	Total
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 (loss) income	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
Adoption of accounting standards	$ (181)	(181)
Units tendered by SOG employees for tax withholding	$ (218)	(218)
Units tendered by SOG employees for tax withholding (in shares)	(85,417)
Preferred unit exchange	$ 103,773	103,773
Unit-based compensation programs	$ 1,531	1,531
Unit-based compensation programs (in shares)	1,109,880
Common units issued for asset management fee	$ 5,228	5,228
Common units issued for asset management fee (in shares)	2,576,760
Cash distributions to common unit holders	$ (5,216)	(5,216)
Distributions - Class B Preferred Units	(24,955)	(24,955)
Net (loss) income	(51,142)	(51,142)
Partner's Deficit at Dec. 31, 2019	$ (35,800)	$ (35,800)
Partner's Deficit (in shares) at Dec. 31, 2019	20,087,462

Consolidated Statements of Ch_2

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

Organization And Business

Organization And Business	12 Months Ended
	Dec. 31, 2019
Organization And Business
Organization And Business	1. ORGANIZATION AND BUSINESS Organization We are a growth-oriented publicly-traded limited partnership formed in 2005 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 natural gas processing facilities, 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 conduct 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 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, 2019
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 (“GAAP). 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 do not anticipate the adoption of this standard to have a material impact 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. We adopted this ASU effective January 1, 2019, which resulted in the remeasurement of our outstanding unvested awards as of January 1, 2019 and changed the expense recorded for equity awards going forward. The adoption of this standard resulted in an approximately $0.2 million charge to retained earnings. 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 more timely recognition of losses. Additionally, in November 2019, the FASB issued ASU 2019-10 “Financial Instruments – Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): Effective Dates,” which changed the effective date for certain issuers to annual and interim periods in fiscal years beginning after December 15, 2022, 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 elected 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-of-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 adopted this standard effective January 1, 2019. The adoption of this standard did not have a material impact on our consolidated financial statements. 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 consolidated financial statements are prepared in conformity with GAAP, which requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. 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 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 judgment using the data available. 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 account for revenue from contracts with customers in accordance with ASC 606 and ASC 842 for our midstream segment. The Seco Pipeline Transportation Agreement is our only contract that we account for using ASC 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. 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 842, 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. 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, and revenues and expenses for these arrangements is 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 consolidated statements of operations, which is accounted for under ASC 815, “Derivatives and Hedging”. 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, 2019 and 2018. 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 86% and 71% of total revenue for the years ended December 31, 2019 and 2018, 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) based on provisions of the Amended Partnership Agreement, 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) as if all of the income for the period had been distributed in accordance with the Amended Partnership Agreement. 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 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 based on provisions of the Amended Partnership Agreement. 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, asset 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 accretion expense in the our 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 changes 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, up to 36 years for gathering facilities, and up to 40 years for transportation assets. 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 2019 and 2018 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 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. 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 earnings from equity investments 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 designated 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, 2019
Revenue Recognition
Revenue Recognition	3. REVENUE RECOGNITION Revenue from Contracts with Customers We account for revenue from contracts with customers in accordance with ASC 606. The unit of account in ASC 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. ASC 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 recognized revenue of $76.6 and $83.6 million for the years ended December 31, 2019 and 2018, respectively. 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 the only contract that we account for under ASC 606. The Catarina Midstream Gathering Agreement (as defined in Note 14 “Related Party Transactions”) is classified as an operating lease and is accounted for under ASC 842, “Leases”, and is reported as gathering and transportation lease revenue in our 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 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. 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 and revenues for these arrangements is 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 consolidated statements of operations, which is accounted for under ASC 815, “Derivatives and Hedging”. 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. 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 which is available only for wholly unsatisfied performance obligations for which the criteria in ASC 606 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 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

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2019
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 “Louisiana Divestiture”). The Louisiana 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 (collectively, the “Cola Divestiture”). The Cola Divestitures were all closed by May 8, 2018 and we recorded a total gain of approximately $1.1 million on the sale.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2019
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. Substantially all of these inputs are observable in the marketplace throughout the term of the 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, 2019 (in thousands): Fair Value Measurements at December 31, 2019 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative liability $ — $ (759) $ — $ (759) Midstream derivative instrument Earnout derivative liability — — — — Other liabilities Warrant — (629) — (629) Total $ — $ (1,388) $ — $ (1,388) 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) As of December 31, 2019 and 2018, 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 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 and related equipment 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.’’ Class C Preferred Units – As part of the Exchange (defined in Note 17 “Partners’ Capital”), Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units and the Warrant in a privately negotiated transaction. The Class C Preferred Units were measured using valuation techniques that convert a future obligation to a single discounted amount. We have therefore classified the fair value measurements of the Class C Preferred units as Level 2 and are presented within “Class C Preferred Units” on the Consolidated Balance Sheets. Seco Pipeline – We recorded a non-cash impairment charge of $32.1 million to impair the Seco Pipeline. The carrying value of the Seco Pipeline was reduced to a fair value of zero, estimated based on an inputs characteristic of a Level 3 fair value measurement. The fair value of the Seco Pipeline was measured using probabilistic valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of the Seco Pipeline include estimates of: (i) future operating and development costs; (ii) estimated future cash flows; 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. Fair Value of Financial Instruments The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below. 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. Credit Agreement – We believe that the carrying value of our Credit Agreement (defined in Note 7 “Debt”) 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. The Credit Agreement is discussed further in Note 7 “Debt.” Derivative Instruments – The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value measurements of our derivative instruments classified as Level 2 inputs. Our commodity derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of oil and natural gas prices and an appropriate discount rate. Our interest rate derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of the LIBOR interest rates and an appropriate discount rate. We did not have any interest rate derivatives as of December 31, 2019. Warrant – As part of the Exchange, the Partnership issued to Stonepeak the Warrant which entitles the holder to receive junior securities representing ten percent of junior securities deemed outstanding when exercised. The Warrant expires on the later of August 2, 2026 or 30 days following the full redemption of the Class C Preferred Units. There is no strike price associated with the exercise of the Warrant. The Warrant is valued using ten percent of the junior securities deemed outstanding and the common unit price as of the balance sheet date. We have therefore classified the fair value measurements of the Warrant as Level 2 and is presented within other liabilities on the consolidated balance sheets. 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 designated 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 the 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): Years Ended December 31, 2019 2018 Beginning balance $ (5,856) $ (6,402) Gain on earnout derivative 5,856 546 Ending balance $ — $ (5,856) Gain included in earnings related to derivatives still held as of December 31, 2019 and December 31, 2018 $ 5,856 $ 546

Derivative And Financial Instru

Derivative And Financial Instruments	12 Months Ended
	Dec. 31, 2019
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 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 in natural gas sales and oil sales in the consolidated statements of operations. As of December 31, 2019, 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 2020 105,104 $ 2.85 102,008 $ 2.85 99,136 $ 2.85 96,200 $ 2.85 402,448 $ 2.85 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 2020 52,776 $ 53.50 50,960 $ 53.50 49,224 $ 53.50 47,624 $ 53.50 200,584 $ 53.50 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, 2019 and 2018 (in thousands): Years Ended December 31, 2019 2018 Beginning fair value of commodity derivatives $ 3,914 $ 1,231 Net gain (loss) on crude oil derivatives (4,031) 1,400 Net gain (loss) on natural gas derivatives 259 (84) Net settlements paid (received) on derivative contracts: Oil (807) 1,330 Natural gas (94) 37 Ending fair value of commodity derivatives $ (759) $ 3,914 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 2019 2018 Commodity – Mark-to-Market Oil sales $ (4,031) $ 1,400 Commodity – Mark-to-Market Natural gas sales 259 (84) $ (3,772) $ 1,316 Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently contracted with three counterparties. We generally execute commodity derivative instruments under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. We include a measure of counterparty credit risk in our estimates of the fair values of derivative instruments. As of December 31, 2019 and 2018, 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”.

Debt

Debt	12 Months Ended
	Dec. 31, 2019
Debt
Debt	7. DEBT Credit Agreement We have entered into a credit facility with Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto (as amended by the Ninth Amendment to Third Amended and Restated Credit Agreement (the “Credit Agreement”). The Credit Agreement provides a quarterly amortizing term loan of $155.0 million (the “Term Loan”) and a maximum revolving credit amount of $20.0 million (the “Revolving Loan”). The Term Loan and Revolving Loan both have a maturity date of September 30, 2021. Borrowings under the Credit Agreement are secured by various mortgages of both midstream and upstream properties that we own as well as various security and pledge agreements among us, certain of our subsidiaries and the administrative agent. Borrowings under the Credit Agreement are available for limited direct investment in oil and natural gas properties, midstream properties, acquisitions, and working capital and general business purposes. The Credit Agreement has a sub-limit of up to $2.5 million which may be used for the issuance of letters of credit. Pursuant to the Credit Agreement, the initial aggregate commitment amount under the Term Loan is $155.0 million, subject to quarterly $10.0 million principal and other mandatory prepayments. The initial borrowing base under the Credit Agreement was $235.5 million. The borrowing base is equal to the sum of the rolling four quarter EBITDA of our midstream operations and the amount of distributions received from the Carnero JV multiplied by 4.5 or a lower number dependent upon natural gas volumes flowing through Western Catarina Midstream. Outstanding borrowings in excess of our borrowing base must be repaid within 45 days. As of December 31, 2019, the borrowing base under the Credit Agreement was $235.5 million and we had $150.0 million of debt outstanding, consisting of $145.0 million under the Term Loan and $5.0 million under the Revolving Loan. We are required to make mandatory amortizing payments of outstanding principal on the Term Loan of $10 million per fiscal quarter. The maximum revolving credit amount is $20.0 million leaving us with $15.0 million in unused borrowing capacity. There were no letters of credit outstanding under our Credit Agreement as of December 31, 2019. At our election, interest for borrowings under the Credit Agreement are determined by reference to (i) the LIBOR plus an applicable margin between 2.50% and 3.00% per annum based on net debt to EBITDA or (ii) a domestic bank rate (“ABR”) plus an applicable margin between 1.50% and 2.00% per annum based on net debt to EBITDA plus (iii) a commitment fee of 0.500% per annum based on the unutilized maximum revolving credit. 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 to unitholders. 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; and · 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 3.5 to 1.0. 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. At December 31, 2019, 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, 2019 and 2018, our unamortized debt issuance costs were approximately $1.2 million and $1.4 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, 2019 and 2018 were approximately $1.3 million and $0.8 million, respectively.

Oil And Natural Gas Properties

Oil And Natural Gas Properties And Related Equipment	12 Months Ended
	Dec. 31, 2019
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, 2019 2018 Gathering and transportation assets Midstream assets $ 186,941 $ 186,406 Less: Accumulated depreciation, amortization and impairment (74,648) (34,598) Total gathering and transportation assets, net $ 112,293 $ 151,808 Oil and natural gas properties consist of the following (in thousands): December 31, 2019 2018 Oil and natural gas properties and related equipment Proved property $ 112,476 $ 112,173 Less: Accumulated depreciation, depletion, amortization and impairments (69,541) (65,647) Total oil and natural gas properties and equipment, net $ 42,935 $ 46,526 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, 2019 and 2018 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 and proved property acquisition 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, up to 36 years for gathering facilities, and up to 40 years for transportation assets. 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 and amortization consisted of the following (in thousands): Years Ended December 31, 2019 2018 Depreciation, depletion and amortization of oil and natural gas-related assets $ 3,942 $ 4,798 Depreciation and amortization of gathering and transportation related assets 7,931 7,729 Amortization of intangible assets 13,460 13,460 Total Depreciation, depletion and amortization $ 25,333 $ 25,987 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. On January 13, 2020, we received a written notice from Sanchez Energy terminating the Seco Pipeline Transportation Agreement effective February 12, 2020. For the year ended December 31, 2019, we recorded a non-cash charge of $32.1 million, to impair the Seco Pipeline. For the year ended December 31, 2018, we recorded no impairment charges. 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. Costs associated with oil and natural gas properties are amortized over proved developed reserves using the units-of-production method. Costs associated with gathering and transportation assets are depreciated using the straight-line method over the useful lives of the asset. 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, 2019 and 2018. 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, 2019
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, 2019 and 2018 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, 2019 2018 Current: Federal $ — $ — State 328 64 Total current 328 64 Deferred: Federal — — State (126) 126 Total deferred (126) 126 Total provision for income taxes $ 202 $ 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 (loss) before income taxes is as follows (in thousands): Years Ended December 31, 2019 2018 Pre-tax net book income (loss) $ (50,940) $ 15,881 Texas Margin Tax (a) 126 267 Return to accrual 76 9 Valuation allowance — (86) Provision for income taxes $ 202 $ 190 Effective income tax rate (a) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses. The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated (in thousands): December 31, 2019 2018 Deferred tax assets (liabilities): Derivative assets $ (23) $ (15) Depreciable, depletable property, plant and equipment 21 (112) Other 2 1 Deferred tax assets (liabilities): — (126) Valuation allowance — — 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, 2019 and 2018, 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 2016. State statutes vary by jurisdiction.

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation
Asset Retirement Obligation	10. ASSET RETIREMENT OBLIGATION We recognize the fair value of a liability for an 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 or gathering and transportation assets. Subsequently, the ARC is depreciated using the units-of-production method for production assets and the straight-line method 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 properties, equipment and facilities or gathering and transportation assets. The following table is a reconciliation of the ARO (in thousands): December 31, 2019 2018 Asset retirement obligation, beginning balance $ 6,200 $ 6,074 Liabilities added from escalating working interests 172 288 Sales — (613) Revisions to cost estimates — (46) Accretion expense 526 497 Asset retirement obligation, ending balance $ 6,898 $ 6,200 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 and other facilities reduce the liability for AROs. In 2019 and 2018, 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, Louisiana Divestiture and Cola Divestiture.

Intangible Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2019
Intangible Assets
Intangible Assets	11. INTANGIBLE ASSETS Intangible assets are comprised of customer and marketing contracts. The intangible assets balance includes $145.2 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 crude oil, 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, 2019 and 2018 was $13. 5 million, respectively. These costs are amortized to depreciation, depletion, and amortization expense in our consolidated statement of operations. Intangible assets as of December 31, 2019 and 2018 are detailed below (in thousands): December 31, 2019 2018 Beginning balance $ 158,706 $ 172,166 Amortization (13,460) (13,460) Ending balance $ 145,246 $ 158,706

Investments

Investments	12 Months Ended
	Dec. 31, 2019
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 earnings from equity investments in our 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, within Carnero G&P, LLC (“the 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 the Carnero JV, which expands the processing capacity of the Carnero JV 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 the Carnero JV resulting in the Carnero JV 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 acres located in the Western Eagle Ford on Sanchez Energy’s Comanche Asset 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 Carnero JV 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 the Carnero JV using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting. The HLBV is a balance-sheet approach that calculates the amount we would have received if the 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 the 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, 2019, the Partnership had paid approximately $124.1 million for its investment in the 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 Carnero JV and has significant influence with respect to the normal day-to-day capital 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, 2019, the Partnership recorded earnings of approximately $4.0 million in equity investments from the 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 $17.2 million were received during the year ended December 31, 2019. Summarized financial information of unconsolidated entities is as follows (in thousands): Years Ended December 31, 2019 2018 Sales $ 159,508 $ 321,607 Total expenses 145,837 290,073 Net income $ 13,671 $ 31,534

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2019
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 designated delivery points from Sanchez Energy and other producers. This earnout has an approximate value of zero as of December 31, 2019. For the year ended December 31, 2019 payments totaling approximately $32.0 thousand were made. For the year ended December 31, 2018, natural gas received did not exceed the threshold.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2019
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 with the exception of the following modified payment terms under the Services Agreement. In November 2019, a letter agreement was executed modifying the payment terms under the Services Agreement beginning with the fee for the quarter ended September 30, 2019. Under the modified terms, payment is being withheld until such time as all issued and outstanding Class C Units have been redeemed. Following the redemption of all issued and outstanding Class C Units the fee will be paid in our equity. As of December 31, 2019, the amount owed under the Services Agreement was $4.9 million and is presented within long term accrued liabilities - related entities on the consolidated balance sheet. If all Class C Units had been redeemed on December 31, 2019, we would issue approximately 11.4 million common units to Manager to settle the portion of the liability related to the November 2019 letter agreement. During the years ended December 31, 2019 and 2018, we incurred costs of approximately $7.3 million and $8.6 million, respectively, to Manager under the Services Agreement. Manager utilizes SOG to provide the services under the Services Agreement. 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. 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. SOG has successfully built and operated extensive midstream and gathering assets associated with its aforementioned development activities. 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, 2018. 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. On June 30, 2017, the Gathering Agreement was amended to add an incremental infrastructure fee to be paid by Sanchez Energy based on water that is delivered through the gathering system through March 31, 2018, and have subsequently agreed to continue the incremental infrastructure fee on a month-to-month basis. For the years ended December 31, 2019 and 2018, Sanchez Energy paid us approximately $59.1 million and $57.9 million, respectively, pursuant to the terms of the gathering and processing agreement. 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 year ended December 31, 2019, payments totaling approximately $32.0 thousand were made. For the year ended December 31, 2018, natural gas did not exceed the threshold. In September 2017, we entered into the Seco Pipeline Transportation Agreement. For the years ended December 31, 2019 and 2018, Sanchez Energy paid us approximately $6.8 million and $7.2 million, respectively, pursuant to the terms of that agreement. On January 13, 2020, we received a written notice from Sanchez Energy terminating the Seco Pipeline Transportation Agreement effective February 12, 2020. 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 acres located in the Western Eagle Ford on Sanchez Energy’s Comanche Asset 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, 2019 and 2018, the Partnership had a net receivable from related parties of approximately $6.7 million, respectively, which are included in accounts receivable – related entities in the consolidated balance sheets. As of December 31, 2019 and 2018, the Partnership also had a net payable to related parties of approximately $5.5 million, and $5.6 million, respectively. The net receivable/payable as of December 31, 2019 consist primarily of revenues receivable from oil and natural gas production and transportation, offset by costs associated with that production and transportation. 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 415,000 gross leasehold acres (215,000 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 6.1%, 3.0%, 1.1% and 1.2%, respectively , of Sanchez Energy’s shares outstanding as of March 13, 2020. As of March 13, 2020, Sanchez Energy indirectly, through one of its wholly owned subsidiaries, beneficially owns approximately 11.4% 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, 2019
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: As of December 31, 2019, 840,811 common units remained available for future issuance to participants under the LTIP. Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit 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 Granted 1,129,173 2.35 Vested (382,690) 8.50 Returned/Cancelled (104,710) 12.04 Outstanding at December 31, 2019 1,155,467 $ 3.86 In April 2019, the Partnership issued 137,613 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 March 2019, the Partnership issued 991,560 restricted common units pursuant to the LTIP to certain officers and directors of the Partnership’s general partner that vest over three years from the date of grant. The unit-based compensation expense for the awards was based on the fair value on the day before the grant date. 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.

Distributions To Unitholders

Distributions To Unitholders	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018. Distribution Date of Date of Date of Three months ended per unit declaration record distribution 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 March 31, 2019 $ 0.1500 May 3, 2019 May 22, 2019 May 31, 2019 The table below reflects the payment of distributions on Class B Preferred Units relating to the years ended December 31, 2019 and 2018. Cash distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2018 $ 0.28225 May 8, 2018 May 22, 2018 May 31, 2018 June 30, 2018 (a) $ 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 March 31, 2019 $ 0.28225 May 3, 2019 May 22, 2019 May 31, 2019 (a) 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. On August 2, 2019, Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units (the “Class C Preferred Units”). Following the Exchange, no distribution was declared with respect to the Class B Preferred Units. The table below reflects the payment of distributions on Class C Preferred Units related to the periods indicated. Class C Preferred Date of Date of Date of Three months ended PIK distribution declaration record distribution June 30, 2019 939,327 August 8, 2019 August 20, 2019 August 30, 2019 September 30, 2019 1,007,820 October 30, 2019 November 29, 2019 November 20, 2019 December 31, 2019 1,039,314 February 13, 2020 February 28, 2020 February 20, 2020

Partners' Capital

Partners' Capital	12 Months Ended
	Dec. 31, 2019
Partners' Capital
Partners' Capital	17. PARTNERS’ CAPITAL Outstanding Units As of December 31, 2019, we had no Class B Preferred Units outstanding, 33,258,043 Class C Preferred Units outstanding and 20,087,462 common units outstanding, which included 1,155,467 unvested restricted common units issued under the LTIP. Common Unit Issuances The following table shows the common units issued by the Partnership in 2018 and 2019 to SP Holdings in connection with providing services under the Services Agreement: Common Date of Three months ended units issuance 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 December 31, 2018 787,750 March 8, 2019 March 31, 2019 887,269 May 23, 2019 June 30, 2019 901,741 August 2, 2019 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 Catarina Transaction, 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 received 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 were 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 were 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, 2019 2018 Mezzanine equity, beginning balance $ 349,857 $ 343,912 Amortization of discount 1,708 2,358 Distributions 23,247 36,925 Distributions paid (17,675) (33,338) Class B Preferred Unit exchange (357,137) — Mezzanine equity, ending balance $ — $ 349,857 On August 2, 2019, Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units and a warrant exercisable for junior securities (the “Warrant”). Class C Preferred Units On August 2, 2019, Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units and the Warrant in a privately negotiated transaction (the “Exchange”). In connection with the Exchange, the Partnership entered into (i) the Third Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended Partnership Agreement) to set forth the terms of the Class C Preferred Units, (ii) the Amended and Restated Registration Rights Agreement with Stonepeak relating to the registered resale of common units issuable upon the exercise of the Warrant, and (iii) the Amended and Restated Board Representation and Standstill Agreement with Stonepeak. Under the terms of the Amended Partnership Agreement, commencing with the quarter ended on September 30, 2019, the holders of the Class C Preferred Units will receive a quarterly distribution of 12.5% per annum payable in cash. To the extent that Available Cash (as defined in the Amended Partnership Agreement) is insufficient to pay the distribution in cash, all or a portion of the distribution may be paid in Class C Preferred PIK Units. Commencing with the quarter ending March 31, 2022, the distribution rate will increase to 14% per annum. Distributions are to be paid on or about the last day of each of February, May, August and November following the end of each quarter and are charged to interest expense in our consolidated statements of operations. The Exchange was accounted for as an extinguishment with the difference between the book value of the redeemed instrument and the fair value of the new instrument being considered a deemed contribution to common equity of approximately $103.8 million. The Class C Preferred Units are accounted for as a long-term liability on the consolidated balance sheet consisting of the following (in thousands): December 31, 2019 Class C Preferred Units Private placement of Class C Preferred Units $ 353,500 Discount (104,250) Amortization of discount 13,129 Distributions 19,309 Class C Preferred Units, ending balance $ 281,688 Warrant On August 2, 2019, in connection with the Exchange, the Partnership issued to Stonepeak the Warrant which entitles the holder to receive junior securities representing ten percent of junior securities deemed outstanding when exercised. The Warrant expires on the later of August 2, 2026 or 30 days following the full redemption of the Class C Preferred Units. There is no strike price associated with the exercise of the Warrant. The Warrant is accounted for as a liability in accordance with ASC 480 and is presented within other liabilities on the consolidated balance sheet. Changes in the fair value of the Warrant are charged to interest expense in our consolidated statements of operations. 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), based on the provisions of the Amended Partnership Agreement, 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) as if all of the net income for the period had been distributed in accordance with the Amended Partnership Agreement. 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 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 based on provisions of the Amended Partnership Agreement. 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. The Partnership’s 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, 2019
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 reporting 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 crude 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. The following tables present financial information for each operating segment for the periods indicated based on our operating segments (in thousands): Years Ended December 31, 2019 2018 Production Midstream Production Midstream Segment revenues Natural gas sales $ 683 $ — $ 953 $ — Oil sales 9,512 — 21,272 — Natural gas liquid sales 539 — 1,709 — Gathering and transportation sales — 6,825 — 6,651 Gathering and transportation lease revenues — 59,090 — 53,025 Total segment revenues 10,734 65,915 23,934 59,676 Segment operating costs Lease operating expenses 5,879 1,499 6,719 1,145 Transportation operating expenses — 11,553 — 12,316 Production taxes 621 — 1,104 — Gain on sale of assets — — (3,186) — Depreciation, depletion and amortization 3,942 21,391 4,798 21,189 Asset impairments — 32,119 — — Accretion expense 200 326 198 299 Total segment operating costs 10,642 66,888 9,633 34,949 Segment other income Earnings from equity investments — 2,831 — 12,859 Total segment other income — 2,831 — 12,859 Segment operating income $ 92 $ 1,858 $ 14,301 $ 37,586 Years Ended December 31, 2019 2018 Reconciliation of segment operating income to net income (loss) Total production operating income $ 92 $ 14,301 Total midstream operating income 1,858 37,586 Total segment operating income 1,950 51,887 General and administrative expense (17,610) (23,653) Unit-based compensation expense (1,351) (1,938) Interest expense, net (39,789) (10,961) Other income 5,860 546 Income tax expense (202) (190) Net income (loss) $ (51,142) $ 15,691 The following table summarizes the total assets and capital expenditures by operating segment as of December 31, 2019 and 2018 (in thousands): December 31, 2019 Production Midstream Corporate (a) Total Other financial information Total assets $ 45,550 $ 362,961 $ 5,929 $ 414,440 Capital expenditures (b) $ 130 $ 775 $ — $ 905 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 (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. Revenue from Sanchez Energy earned in our Midstream segment accounted for 86% and 71% of total revenue for the years ended December 31, 2019 and 2018, respectively. 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.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2019
Variable Interest Entities
Variable Interest Entities	19. VARIABLE INTEREST ENTITIES The Partnership’s investment in the 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 the Carnero JV is limited to the capital investment of approximately $100.3 million. As of December 31, 2019, the Partnership had invested approximately $124.1 million in the Carnero JV and no debt has been incurred by the Carnero JV. We have included this VIE in other assets, equity investments 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, 2019 and 2018 (in thousands): December 31, 2019 2018 Acquisitions, earnout and capital investments $ 128,140 $ 127,899 Earnings in equity investments 25,976 23,144 Distributions received (53,805) (36,578) Maximum exposure to loss $ 100,311 $ 114,465

Supplemental Information On Oil

Supplemental Information On Oil And Natural Gas Producing Activities	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018 (in thousands): December 31, 2019 2018 Capitalized costs at the end of the period: ⁽ᵃ⁾ Oil and natural gas properties and related equipment (successful efforts method) Proved property $ 112,476 $ 112,173 Less: Accumulated depreciation, depletion, amortization and impairments (69,541) (65,647) Oil and natural gas properties and equipment, net $ 42,935 $ 46,526 (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, 2019 and 2018 (in thousands): Years Ended December 31, 2019 2018 Costs incurred for the period: Acquisition of properties Proved $ — $ — Development costs 131 11 Oil and natural gas properties and equipment, net $ 131 $ 11 The development costs for the years ended December 31, 2019 and 2018 primarily represent costs related to recompletions. We had no exploration and dry hole costs in 2019 and 2018. 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, 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 Sales of reserves in place — — — — Revisions of previous estimates (145) (10) (67) (68) Production (309) (228) (39) (42) December 31, 2019 2,999 2,241 348 410 Proved developed reserves: December 31, 2018 3,453 2,479 454 520 December 31, 2019 2,999 2,241 348 410 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, 2019 and 2018, proved reserve estimates were 3.0 MMBoe and 3.5 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 2019 estimates of total proved reserves decreased 0.5 MMBoe from 2018 due to production of 0.3 MMBoe and revisions of previous estimates of 0.2 MMBoe. For proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report were: $59.55 per Bbl for oil, $13.68 per Bbl for NGLs and $2.66 per Mcf for natural gas. 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. 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, 2019 2018 Future cash inflows $ 144,628 $ 186,675 Future production costs (80,007) (99,187) Future estimated development costs (3,400) (4,043) Future net cash flows 61,221 83,445 10% annual discount for estimated timing of cash flows (22,871) (31,199) Standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves $ 38,350 $ 52,246 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, 2019 2018 Beginning of the period $ 52,246 $ 56,697 Sales and transfers of oil and natural gas, net of production costs (8,006) (14,795) Net changes in prices and production costs related to future production (7,330) 17,392 Changes in development costs 35 207 Revisions of previous quantity estimates (1,942) (4,203) Purchases and sales of reserves in place — (5,423) Accretion discount 5,225 5,670 Change in production rates, timing, and other (1,878) (3,299) Standardized measure of discounted future net cash flows related to proved oil and natural gas reserves $ 38,350 $ 52,246

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2019
Subsequent Events
Subsequent Events	21. SUBSEQUENT EVENTS On February 13, 2020, the Board declared that after establishing a cash reserve for the payment of certain amounts outstanding under the Credit Agreement, the Partnership did not have any available cash and, as a result, there would be no cash distribution on the Partnership’s common units. As required by the Amended Partnership Agreement, the Board declared a fourth quarter distribution on the Class C Preferred Units payable 100% in Class C Preferred PIK Units. Accordingly, the Partnership declared an aggregate distribution of 1,039,314 Class C Preferred PIK Units, which was paid on February 28, 2020 to holders of record on February 20, 2020. On January 13, 2020, we received written notice of termination from Sanchez Energy terminating the Seco Pipeline Transportation Agreement effective February 12, 2020. Since December 31, 2019, the Partnership paid $6.0 million in principal outstanding under the Credit Agreement resulting in total debt outstanding of $144.0 million under the Credit Agreement as of March 13, 2020.

Basis Of Presentation And Sum_2

Basis Of Presentation And Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
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 (“GAAP). 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 do not anticipate the adoption of this standard to have a material impact 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. We adopted this ASU effective January 1, 2019, which resulted in the remeasurement of our outstanding unvested awards as of January 1, 2019 and changed the expense recorded for equity awards going forward. The adoption of this standard resulted in an approximately $0.2 million charge to retained earnings. 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 more timely recognition of losses. Additionally, in November 2019, the FASB issued ASU 2019-10 “Financial Instruments – Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic 842): Effective Dates,” which changed the effective date for certain issuers to annual and interim periods in fiscal years beginning after December 15, 2022, 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 elected 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-of-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 adopted this standard effective January 1, 2019. The adoption of this standard did not have a material impact on our consolidated financial statements. 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 consolidated financial statements are prepared in conformity with GAAP, which requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. 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 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 judgment using the data available. 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 account for revenue from contracts with customers in accordance with ASC 606 and ASC 842 for our midstream segment. The Seco Pipeline Transportation Agreement is our only contract that we account for using ASC 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. 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 842, 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. 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, and revenues and expenses for these arrangements is 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 consolidated statements of operations, which is accounted for under ASC 815, “Derivatives and Hedging”. 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, 2019 and 2018. 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 86% and 71% of total revenue for the years ended December 31, 2019 and 2018, 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) based on provisions of the Amended Partnership Agreement, 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) as if all of the income for the period had been distributed in accordance with the Amended Partnership Agreement. 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 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 based on provisions of the Amended Partnership Agreement. 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, asset 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 accretion expense in the our 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 changes 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, up to 36 years for gathering facilities, and up to 40 years for transportation assets. 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 2019 and 2018 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 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.
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 earnings from equity investments 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 designated 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.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Measurements
Schedule of 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, 2019 (in thousands): Fair Value Measurements at December 31, 2019 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative liability $ — $ (759) $ — $ (759) Midstream derivative instrument Earnout derivative liability — — — — Other liabilities Warrant — (629) — (629) Total $ — $ (1,388) $ — $ (1,388) 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)
Schedule of reconciliation of changes in fair value of derivatives	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): Years Ended December 31, 2019 2018 Beginning balance $ (5,856) $ (6,402) Gain on earnout derivative 5,856 546 Ending balance $ — $ (5,856) Gain included in earnings related to derivatives still held as of December 31, 2019 and December 31, 2018 $ 5,856 $ 546

Derivative And Financial Inst_2

Derivative And Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2019
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 2020 105,104 $ 2.85 102,008 $ 2.85 99,136 $ 2.85 96,200 $ 2.85 402,448 $ 2.85 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 2020 52,776 $ 53.50 50,960 $ 53.50 49,224 $ 53.50 47,624 $ 53.50 200,584 $ 53.50
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, 2019 and 2018 (in thousands): Years Ended December 31, 2019 2018 Beginning fair value of commodity derivatives $ 3,914 $ 1,231 Net gain (loss) on crude oil derivatives (4,031) 1,400 Net gain (loss) on natural gas derivatives 259 (84) Net settlements paid (received) on derivative contracts: Oil (807) 1,330 Natural gas (94) 37 Ending fair value of commodity derivatives $ (759) $ 3,914
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 2019 2018 Commodity – Mark-to-Market Oil sales $ (4,031) $ 1,400 Commodity – Mark-to-Market Natural gas sales 259 (84) $ (3,772) $ 1,316

Oil And Natural Gas Propertie_2

Oil And Natural Gas Properties And Related Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
Oil And Natural Gas Properties And Related Equipment.
Schedule of gathering and transportation assets	Gathering and transportation assets consist of the following (in thousands): December 31, 2019 2018 Gathering and transportation assets Midstream assets $ 186,941 $ 186,406 Less: Accumulated depreciation, amortization and impairment (74,648) (34,598) Total gathering and transportation assets, net $ 112,293 $ 151,808
Schedule of oil and natural gas properties	Oil and natural gas properties consist of the following (in thousands): December 31, 2019 2018 Oil and natural gas properties and related equipment Proved property $ 112,476 $ 112,173 Less: Accumulated depreciation, depletion, amortization and impairments (69,541) (65,647) Total oil and natural gas properties and equipment, net $ 42,935 $ 46,526
Schedule of depreciation, depletion, and amortization	Depreciation, depletion and amortization consisted of the following (in thousands): Years Ended December 31, 2019 2018 Depreciation, depletion and amortization of oil and natural gas-related assets $ 3,942 $ 4,798 Depreciation and amortization of gathering and transportation related assets 7,931 7,729 Amortization of intangible assets 13,460 13,460 Total Depreciation, depletion and amortization $ 25,333 $ 25,987

Provision For Income Taxes (Tab

Provision For Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Provision For Income Taxes
Summary of Federal and State Income Tax Provision (Benefit)	Years Ended December 31, 2019 2018 Current: Federal $ — $ — State 328 64 Total current 328 64 Deferred: Federal — — State (126) 126 Total deferred (126) 126 Total provision for income taxes $ 202 $ 190
Reconciliation of Provision for (Benefit from) Income Taxes	Years Ended December 31, 2019 2018 Current: Federal $ — $ — State 328 64 Total current 328 64 Deferred: Federal — — State (126) 126 Total deferred (126) 126 Total provision for income taxes $ 202 $ 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 (loss) before income taxes is as follows (in thousands): Years Ended December 31, 2019 2018 Pre-tax net book income (loss) $ (50,940) $ 15,881 Texas Margin Tax (a) 126 267 Return to accrual 76 9 Valuation allowance — (86) Provision for income taxes $ 202 $ 190 Effective income tax rate (a) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.
Significant Components of Deferred Tax Assets and Deferred Tax Liabilities	The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated (in thousands): December 31, 2019 2018 Deferred tax assets (liabilities): Derivative assets $ (23) $ (15) Depreciable, depletable property, plant and equipment 21 (112) Other 2 1 Deferred tax assets (liabilities): — (126) Valuation allowance — — Total deferred tax assets (liabilities) $ — $ (126)

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation
Reconciliation of changes in asset retirement obligation	The following table is a reconciliation of the ARO (in thousands): December 31, 2019 2018 Asset retirement obligation, beginning balance $ 6,200 $ 6,074 Liabilities added from escalating working interests 172 288 Sales — (613) Revisions to cost estimates — (46) Accretion expense 526 497 Asset retirement obligation, ending balance $ 6,898 $ 6,200

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2019
Intangible Assets
Schedule of Intangible assets	Intangible assets as of December 31, 2019 and 2018 are detailed below (in thousands): December 31, 2019 2018 Beginning balance $ 158,706 $ 172,166 Amortization (13,460) (13,460) Ending balance $ 145,246 $ 158,706

Investments (Tables)

Investments (Tables)	12 Months Ended
	Dec. 31, 2019
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 $ 159,508 $ 321,607 Total expenses 145,837 290,073 Net income $ 13,671 $ 31,534

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2019
Unit-Based Compensation
Schedule of units activity	Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit 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 Granted 1,129,173 2.35 Vested (382,690) 8.50 Returned/Cancelled (104,710) 12.04 Outstanding at December 31, 2019 1,155,467 $ 3.86

Distributions To Unitholders (T

Distributions To Unitholders (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018. Distribution Date of Date of Date of Three months ended per unit declaration record distribution 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 March 31, 2019 $ 0.1500 May 3, 2019 May 22, 2019 May 31, 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, 2018 $ 0.28225 May 8, 2018 May 22, 2018 May 31, 2018 June 30, 2018 (a) $ 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 March 31, 2019 $ 0.28225 May 3, 2019 May 22, 2019 May 31, 2019 (a) 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.
Class C preferred units
Schedule of payment of cash distributions	Class C Preferred Date of Date of Date of Three months ended PIK distribution declaration record distribution June 30, 2019 939,327 August 8, 2019 August 20, 2019 August 30, 2019 September 30, 2019 1,007,820 October 30, 2019 November 29, 2019 November 20, 2019 December 31, 2019 1,039,314 February 13, 2020 February 28, 2020 February 20, 2020

Partners' Capital (Tables)

Partners' Capital (Tables)	12 Months Ended
	Dec. 31, 2019
Partners' Capital
Schedule of common unit issuances	Common Date of Three months ended units issuance 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 December 31, 2018 787,750 March 8, 2019 March 31, 2019 887,269 May 23, 2019 June 30, 2019 901,741 August 2, 2019
Schedule of 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, 2019 2018 Mezzanine equity, beginning balance $ 349,857 $ 343,912 Amortization of discount 1,708 2,358 Distributions 23,247 36,925 Distributions paid (17,675) (33,338) Class B Preferred Unit exchange (357,137) — Mezzanine equity, ending balance $ — $ 349,857
Schedule of Class C preferred units	The Class C Preferred Units are accounted for as a long-term liability on the consolidated balance sheet consisting of the following (in thousands): December 31, 2019 Class C Preferred Units Private placement of Class C Preferred Units $ 353,500 Discount (104,250) Amortization of discount 13,129 Distributions 19,309 Class C Preferred Units, ending balance $ 281,688

Reporting Segments (Tables)

Reporting Segments (Tables)	12 Months Ended
	Dec. 31, 2019
Reporting Segments
Schedule of segment information	Years Ended December 31, 2019 2018 Production Midstream Production Midstream Segment revenues Natural gas sales $ 683 $ — $ 953 $ — Oil sales 9,512 — 21,272 — Natural gas liquid sales 539 — 1,709 — Gathering and transportation sales — 6,825 — 6,651 Gathering and transportation lease revenues — 59,090 — 53,025 Total segment revenues 10,734 65,915 23,934 59,676 Segment operating costs Lease operating expenses 5,879 1,499 6,719 1,145 Transportation operating expenses — 11,553 — 12,316 Production taxes 621 — 1,104 — Gain on sale of assets — — (3,186) — Depreciation, depletion and amortization 3,942 21,391 4,798 21,189 Asset impairments — 32,119 — — Accretion expense 200 326 198 299 Total segment operating costs 10,642 66,888 9,633 34,949 Segment other income Earnings from equity investments — 2,831 — 12,859 Total segment other income — 2,831 — 12,859 Segment operating income $ 92 $ 1,858 $ 14,301 $ 37,586
Schedule of reconciliation of segment operating income to net income (loss)	Years Ended December 31, 2019 2018 Reconciliation of segment operating income to net income (loss) Total production operating income $ 92 $ 14,301 Total midstream operating income 1,858 37,586 Total segment operating income 1,950 51,887 General and administrative expense (17,610) (23,653) Unit-based compensation expense (1,351) (1,938) Interest expense, net (39,789) (10,961) Other income 5,860 546 Income tax expense (202) (190) Net income (loss) $ (51,142) $ 15,691
Summary of assets and capital expenditures by operating segment	The following table summarizes the total assets and capital expenditures by operating segment as of December 31, 2019 and 2018 (in thousands): December 31, 2019 Production Midstream Corporate (a) Total Other financial information Total assets $ 45,550 $ 362,961 $ 5,929 $ 414,440 Capital expenditures (b) $ 130 $ 775 $ — $ 905 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 (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.

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018 (in thousands): December 31, 2019 2018 Acquisitions, earnout and capital investments $ 128,140 $ 127,899 Earnings in equity investments 25,976 23,144 Distributions received (53,805) (36,578) Maximum exposure to loss $ 100,311 $ 114,465

Supplemental Information On O_2

Supplemental Information On Oil And Natural Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018 (in thousands): December 31, 2019 2018 Capitalized costs at the end of the period: ⁽ᵃ⁾ Oil and natural gas properties and related equipment (successful efforts method) Proved property $ 112,476 $ 112,173 Less: Accumulated depreciation, depletion, amortization and impairments (69,541) (65,647) Oil and natural gas properties and equipment, net $ 42,935 $ 46,526 (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, 2019 and 2018 (in thousands): Years Ended December 31, 2019 2018 Costs incurred for the period: Acquisition of properties Proved $ — $ — Development costs 131 11 Oil and natural gas properties and equipment, net $ 131 $ 11
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, 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 Sales of reserves in place — — — — Revisions of previous estimates (145) (10) (67) (68) Production (309) (228) (39) (42) December 31, 2019 2,999 2,241 348 410 Proved developed reserves: December 31, 2018 3,453 2,479 454 520 December 31, 2019 2,999 2,241 348 410
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, 2019 2018 Future cash inflows $ 144,628 $ 186,675 Future production costs (80,007) (99,187) Future estimated development costs (3,400) (4,043) Future net cash flows 61,221 83,445 10% annual discount for estimated timing of cash flows (22,871) (31,199) Standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves $ 38,350 $ 52,246
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, 2019 2018 Beginning of the period $ 52,246 $ 56,697 Sales and transfers of oil and natural gas, net of production costs (8,006) (14,795) Net changes in prices and production costs related to future production (7,330) 17,392 Changes in development costs 35 207 Revisions of previous quantity estimates (1,942) (4,203) Purchases and sales of reserves in place — (5,423) Accretion discount 5,225 5,670 Change in production rates, timing, and other (1,878) (3,299) Standardized measure of discounted future net cash flows related to proved oil and natural gas reserves $ 38,350 $ 52,246

Basis Of Presentation And Sum_3

Basis Of Presentation And Summary Of Significant Accounting Policies (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)segment	Dec. 31, 2018USD ($)
Number of reportable segments | segment	2
Number of business segments | segment	2
Adoption of accounting standards | $		$ (181)
Allowance for doubtful accounts | $	$ 400	$ 400
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
Maximum | Transportation assets
Useful life	40 years
Midstream | Revenue | Customer Concentration Risk | Sanchez Energy
Percentage of sales revenue	86.00%	71.00%

Revenue Recognition (Details)

Revenue Recognition (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue Recognition
Performance obligation	true
Revenues	$ 76,649	$ 83,610
Payment term (in days)	30 days
Receivables	$ 1,100	$ 600

Acquisitions and Divestitures (

Acquisitions and Divestitures (Details) - USD ($) $ in Millions	Oct. 22, 2018	May 08, 2018	Apr. 30, 2018
Louisiana Divestiture
Business Acquisition [Line Items]
Proceeds from divestiture	$ 1.3
Gain on sale	$ 0.6
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
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, 2019	Dec. 31, 2018
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets		$ 3,914
Earnout derivative liability		(5,856)
Derivative liability	$ (759)
Other liabilities: Warrant	(629)
Total net assets	(1,388)	(1,942)
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets		3,914
Derivative liability	(759)
Other liabilities: Warrant	(629)
Total net assets	$ (1,388)	3,914
Fair Value, Inputs, Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Earnout derivative liability		(5,856)
Total net assets		$ (5,856)

Fair Value Measurements (Non-Re

Fair Value Measurements (Non-Recurring) (Details) - Seco Pipeline, LLC - Nonrecurring	12 Months Ended
	Dec. 31, 2019USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Asset impairments	$ 32,100,000
Fair Value, Inputs, Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair value	$ 0

Fair Value Measurements (Embedd

Fair Value Measurements (Embedded and Earnout Derivative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value Measurements
Beginning Balance	$ (5,856)	$ (6,402)
Gain on embedded derivative	$ 5,856	546
Ending Balance		$ (5,856)

Derivative And Financial Inst_3

Derivative And Financial Instruments (Hedges In Place) (Details)	12 Months Ended
	Dec. 31, 2019MMBTU$ / MMBTU$ / bblbbl
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
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 2020
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	402,448
Average Price | $ / MMBTU	2.85

Derivative And Financial Inst_4

Derivative And Financial Instruments (Changes In Fair Value) (Details) - Commodity Contract $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)item	Dec. 31, 2018USD ($)
Derivative Instruments Gain Loss [Line Items]
Beginning fair value of commodity derivatives	$ 3,914	$ 1,231
Net gain (loss) on derivatives	(3,772)	1,316
Ending fair value of commodity derivatives	$ (759)	3,914
Number of counterparties | item	3
Oil reserves
Derivative Instruments Gain Loss [Line Items]
Net gain (loss) on derivatives	$ (4,031)	1,400
Net settlements paid (received) on derivative contracts		1,330
Net settlements paid (received) on derivative contracts	(807)
Natural gas
Derivative Instruments Gain Loss [Line Items]
Net gain (loss) on derivatives	259	(84)
Net settlements paid (received) on derivative contracts		$ 37
Net settlements paid (received) on derivative contracts	$ (94)

Derivative And Financial Inst_5

Derivative And Financial Instruments (Effect On Statement Of Operations) (Details) - Commodity Contract - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Embedded Derivative [Line Items]
Net gain (loss) on derivatives	$ (3,772)	$ 1,316
Oil reserves
Embedded Derivative [Line Items]
Net gain (loss) on derivatives	(4,031)	1,400
Natural gas
Embedded Derivative [Line Items]
Net gain (loss) on derivatives	$ 259	$ (84)

Debt (Details)

Debt (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Nov. 22, 2019USD ($)
Line of Credit Facility [Line Items]
Remaining borrowing capacity	$ 15,000
Unamortized debt issue costs	1,200	$ 1,400
Amortization of debt issuance costs	1,266	$ 783
Letter of Credit
Line of Credit Facility [Line Items]
Maximum borrowing capacity			$ 155,000
Credit agreement, outstanding	145,000
Debt Instrument, Periodic Payment, Total	10,000
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity	20,000		$ 20,000
Credit agreement, outstanding	5,000
Credit Agreement
Line of Credit Facility [Line Items]
Maximum borrowing capacity	235,500
Sub-limit which may be used for issuance of letters of credit	2,500
Initial borrowing capacity	$ 235,500
Borrowing base term	45 days
Credit agreement, outstanding	$ 150,000
Commitment fee on unutilized borrowing base	0.50%
Credit Agreement | Letter of Credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Periodic Payment	$ 10,000
Initial borrowing capacity	$ 155,000
Minimum | Credit Agreement
Line of Credit Facility [Line Items]
Ownership percentage by subsidiary	0.50
Required working capital ratio	1
Minimum | Credit Agreement | London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Variable interest rate	2.50%
Minimum | Credit Agreement | ABR
Line of Credit Facility [Line Items]
Variable interest rate	1.50%
Maximum | Credit Agreement | Scenario One
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	3.5
Maximum | Credit Agreement | London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Variable interest rate	3.00%
Maximum | Credit Agreement | ABR
Line of Credit Facility [Line Items]
Variable interest rate	2.00%
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, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Midstream assets	$ 186,941	$ 186,406
Less: Accumulated depreciation, amortization and impairment	(69,541)	(65,647)
Midstream
Property, Plant and Equipment [Line Items]
Midstream assets	186,941	186,406
Less: Accumulated depreciation, amortization and impairment	(74,648)	(34,598)
Total gathering and transportation assets, net	$ 112,293	$ 151,808

Oil And Natural Gas Propertie_4

Oil And Natural Gas Properties And Related Equipment (Properties) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Oil And Natural Gas Properties And Related Equipment.
Proved property	$ 112,476	$ 112,173
Less: Accumulated depreciation, depletion, amortization and impairments	(69,541)	(65,647)
Total oil and natural gas properties and equipment, net	$ 42,935	$ 46,526

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, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Amortization of intangible assets	$ 13,460	$ 13,460
Depreciation and depletion	11,873	12,527
Asset impairments	32,119
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
Transportation assets | Maximum
Property, Plant and Equipment [Line Items]
Useful lives	40 years
Oil and Natural Gas-Related Assets
Property, Plant and Equipment [Line Items]
Depreciation and depletion	$ 3,942	4,798
Gathering and Transportation Related Assets
Property, Plant and Equipment [Line Items]
Depreciation and depletion	7,931	7,729
Oil and Natural Gas-Related Assets and Gathering and Transportation-Related Assets
Property, Plant and Equipment [Line Items]
Total Depreciation, depletion and amortization	25,333	25,987
Seco Pipeline, LLC
Property, Plant and Equipment [Line Items]
Asset impairments	$ 32,100	$ 0

Provision For Income Taxes (Inc

Provision For Income Taxes (Income Tax Provision (Benefit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Current:
State	$ 328	$ 64
Total current	328	64
Deferred:
State	(126)	126
Total deferred	(126)	126
Income tax expense	$ 202	$ 190

Provision For Income Taxes (Rec

Provision For Income Taxes (Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Provision For Income Taxes
Pre-tax net book income (loss)	$ (50,940)	$ 15,881
Texas Margin Tax	126	267
Return to accrual	76	9
Valuation allowance		(86)
Provision for income taxes	$ 202	$ 190
Effective income tax rate	(0.40%)	1.20%

Provision For Income Taxes (DTA

Provision For Income Taxes (DTA and DTL) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets (liabilities):
Derivative assets, liability	$ (23)	$ (15)
Depreciable, depletable property, plant and equipment	21
Depreciable, depletable property, plant and equipment		(112)
Other	2	1
Deferred tax assets:
Deferred tax liabilities:		(126)
Total deferred tax liabilities		$ (126)
Total deferred tax assets

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation
Asset retirement obligation, beginning balance	$ 6,200	$ 6,074
Liabilities added from escalating working interests	172	288
Sales		(613)
Revisions to cost estimates		(46)
Accretion expense	526	497
Asset retirement obligation, ending balance	6,898	6,200
Legally restricted assets	$ 0	$ 0

Intangible Assets (Details)

Intangible Assets (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)a	Dec. 31, 2018USD ($)
Finite-Lived Intangible Assets [Line Items]
Beginning balance	$ 158,706	$ 172,166
Amortization	(13,460)	(13,460)
Ending balance	$ 145,246	$ 158,706
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				12 Months Ended
	May 31, 2018amiMMcf	Apr. 30, 2018MMcf	Nov. 30, 2016USD ($)	Jul. 31, 2016USD ($)	Dec. 31, 2019USD ($)a	Dec. 31, 2018USD ($)
Schedule of Equity Method Investments [Line Items]
Earnings (loss) from equity investments					$ 2,831	$ 12,859
Amortization of intangible assets					13,460	13,460
Distributions received					17,227	$ 24,946
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	124,100
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					124,100
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					4,000
Amortization of intangible assets					1,200
Distributions received					$ 17,200
Sanchez Energy
Schedule of Equity Method Investments [Line Items]
Acres dedicated for gathering | a					415,000
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, 2019	Dec. 31, 2018
Investments
Sales	$ 159,508	$ 321,607
Total expenses	145,837	290,073
Net income	$ 13,671	$ 31,534

Commitments And Contingencies (

Commitments And Contingencies (Details) - Carnero Gathering, Joint Venture	12 Months Ended
	Dec. 31, 2019USD ($)
Variable Interest Entity [Line Items]
Earnout derivative liability	$ 0
Earnout payments	$ 32,000

Related Party Transactions (Det

Related Party Transactions (Details) shares in Millions	Oct. 14, 2015a$ / bbl$ / McfbblMMcf	Nov. 30, 2016USD ($)	Jul. 31, 2016USD ($)	Dec. 31, 2019USD ($)ashares	Dec. 31, 2018USD ($)	Mar. 13, 2020	May 31, 2018a
Related Party Transaction [Line Items]
Related parties, net receivable				$ 6,700,000
Related parties, net payable				$ 5,500,000	$ 5,600,000
Sanchez Energy
Related Party Transaction [Line Items]
Acres dedicated for gathering | a				415,000
Proceeds from transportation agreement				$ 6,800,000	7,200,000
Net acres assembled | a				215,000
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				$ 7,300,000	8,600,000
Carnero Processing, Joint Venture
Related Party Transaction [Line Items]
Ownership interest (as a percent)		50.00%
Payments to acquire interest in joint venture		$ 55,500,000
Assumption of capital commitments in joint venture		$ 24,500,000
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			$ 37,000,000	124,100,000
Assumption of capital commitments in joint venture			$ 7,400,000
Earnout payments				32,000
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				$ 59,100,000	$ 57,900,000
Common units
Related Party Transaction [Line Items]
Common stock issued | shares				11.4
Common units | Sanchez Energy | Subsequent event
Related Party Transaction [Line Items]
Ownership by related parties (as a percentage)						11.40%
Common units | Sanchez Energy | Antonio R. Sanchez Jr. | Subsequent event
Related Party Transaction [Line Items]
Ownership by related parties (as a percentage)						6.10%
Common units | Sanchez Energy | Antonio R. Sanchez, III | Subsequent event
Related Party Transaction [Line Items]
Ownership by related parties (as a percentage)						3.00%
Common units | Sanchez Energy | Eduardo A. Sanchez | Subsequent event
Related Party Transaction [Line Items]
Ownership by related parties (as a percentage)						1.10%
Common units | Sanchez Energy | Patricio D Sanchez | Subsequent event
Related Party Transaction [Line Items]
Ownership by related parties (as a percentage)						1.20%
Class C preferred units | SP Holdings | Long Term Accrued Liabilities
Related Party Transaction [Line Items]
Management Fee Payable				$ 4,900,000

Unit-Based Compensation (Detail

Unit-Based Compensation (Details) - $ / shares	1 Months Ended			12 Months Ended
	Apr. 30, 2019	Mar. 31, 2019	Apr. 30, 2018	Dec. 31, 2019	Dec. 31, 2018
LTIP
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units available for issuance				840,811
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding				513,694	283,138
Number of Restricted Units, Granted				1,129,173	622,534
Number of Restricted Units, Vested				(382,690)	(301,005)
Number of Restricted Units, Returned/Cancelled				(104,710)	(90,973)
Number of Restricted Units, Outstanding				1,155,467	513,694
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding				$ 12.31	$ 14.64
Weighted Averaged Grant Date Fair Value Per Unit, Granted				2.35	11.94
Weighted Averaged Grant Date Fair Value Per Unit, Vested				8.50	13.60
Weighted Averaged Grant Date Fair Value Per Unit, Returned/Cancelled				12.04	12.77
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding				$ 3.86	$ 12.31
Restricted Stock Units (RSUs) | Directors
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted	137,613		63,630
Restricted Stock Units (RSUs) | Executives
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted		991,560	244,813
Vesting period		3 years	3 years
Restricted Stock Units (RSUs) | Non executive employees
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted			314,091

Distributions To Unitholders (D

Distributions To Unitholders (Details) - $ / shares	Feb. 13, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2018
Common units
Distribution paid per unit					$ 0.1500	$ 0.1500	$ 0.1500	$ 0.4508	$ 0.4508
Class B preferred units
Distribution paid per unit					$ 0.28225	$ 0.28225	$ 0.28225	$ 0.2258	$ 0.28225
Aggregate distribution of units										310,009
Class C preferred units
Paid-in-kind units distributed		1,039,314	1,007,820	939,327
Class C preferred units | Subsequent event
Class C Preferred Units Payable In Class C Preferred PIK Units Percentage	100.00%

Partners' Capital (Details)

Partners' Capital (Details) - USD ($) $ / shares in Units, $ in Millions

Jan. 25, 2017

Oct. 14, 2015

Jun. 30, 2019

Mar. 31, 2019

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Dec. 31, 2015

Dec. 31, 2019

Aug. 31, 2018

Dec. 06, 2016

Limited Partners' Capital Account [Line Items]

Class B preferred units, outstanding

31,310,896

0

Common units, outstanding

16,486,239

20,087,462

Units, issued

16,486,239

20,087,462

Class B preferred units, issued

31,310,896

0

Class B preferred units

Limited Partners' Capital Account [Line Items]

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

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

Class C preferred units

Limited Partners' Capital Account [Line Items]

Class B preferred units, outstanding

33,258,043

Common units

Limited Partners' Capital Account [Line Items]

Common units, outstanding

20,087,462

Units sold (in units)

901,741

887,269

787,750

334,010

224,342

220,214

210,978

Unvested restricted common units | LTIP

Limited Partners' Capital Account [Line Items]

Common units, outstanding

1,155,467

Minimum | Class B preferred units

Limited Partners' Capital Account [Line Items]

Preferred unit conversion, amount

$ 17.5

Partners' Capital (Preferred Un

Partners' Capital (Preferred Units) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Mezzanine equity, beginning balance	$ 349,857
Distributions	17,675	$ 33,338
Mezzanine equity, ending balance		349,857
Deemed contribution from exchange	103,773
Class C preferred units, ending balance	281,688
Class B preferred units
Mezzanine equity, beginning balance	349,857	343,912
Amortization of discount	1,708	2,358
Distributions	23,247	36,925
Distributions paid	(17,675)	(33,338)
Class B Preferred Unit exchange	(357,137)
Mezzanine equity, ending balance		$ 349,857
Class C preferred units
Deemed contribution from exchange	103,800
Private placement of Class C Preferred Units	353,500
Discount	(104,250)
Amortization of discount	13,129
Distributions	19,309
Class C preferred units, ending balance	$ 281,688
Warrant exercise period	30 days
Class C preferred units | Distribution period commencing with the quarter ended on September 30, 2019
Distributions (as a percent)	12.50%
Class C preferred units | Distribution period commencing with the quarter ending March 31, 2022
Distributions (as a percent)	14.00%

Reporting Segments (Segment Inf

Reporting Segments (Segment Information) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Segment operating revenues:
Gathering and transportation lease revenues	$ 59,090	$ 53,025
Total revenues	76,649	83,610
Segment operating costs:
Lease operating expenses	7,378	7,864
Transportation operating expenses	11,553	12,316
Production taxes	621	1,104
Gain on sale of assets		(3,186)
Depreciation, depletion and amortization	25,333	25,987
Asset impairments	32,119
Accretion expense	526	497
Total operating expenses	96,491	70,173
Segment other income (loss)
Earnings (loss) from equity investments	2,831	12,859
Segment operating income	1,950	51,887
Production
Segment operating revenues:
Total revenues	10,734	23,934
Segment operating costs:
Lease operating expenses	5,879	6,719
Production taxes	621	1,104
Gain on sale of assets		(3,186)
Depreciation, depletion and amortization	3,942	4,798
Accretion expense	200	198
Total operating expenses	10,642	9,633
Segment other income (loss)
Segment operating income	92	14,301
Midstream
Segment operating revenues:
Gathering and transportation lease revenues	59,090	53,025
Total revenues	65,915	59,676
Segment operating costs:
Lease operating expenses	1,499	1,145
Transportation operating expenses	11,553	12,316
Depreciation, depletion and amortization	21,391	21,189
Asset impairments	32,119
Accretion expense	326	299
Total operating expenses	66,888	34,949
Segment other income (loss)
Earnings (loss) from equity investments	2,831	12,859
Total segment other income (loss)	2,831	12,859
Segment operating income	1,858	37,586
Natural gas sales
Segment operating revenues:
Revenues	683	953
Natural gas sales | Production
Segment operating revenues:
Revenues	683	953
Oil sales
Segment operating revenues:
Revenues	9,512	21,272
Oil sales | Production
Segment operating revenues:
Revenues	9,512	21,272
Natural gas liquid sales
Segment operating revenues:
Revenues	539	1,709
Natural gas liquid sales | Production
Segment operating revenues:
Revenues	539	1,709
Gathering and transportation sales
Segment operating revenues:
Revenues	6,825	6,651
Gathering and transportation sales | Midstream
Segment operating revenues:
Revenues	$ 6,825	$ 6,651

Reporting Segments - Reconcilia

Reporting Segments - Reconciliation of Segment Operating Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of segment operating income (loss) to net income (loss)
Segment operating income	$ 1,950	$ 51,887
General and administrative expense	(17,610)	(23,653)
Unit-based compensation expense	(1,351)	(1,938)
Interest expense, net	(39,789)	(10,961)
Other income	5,860	546
Income tax expense	(202)	(190)
Net income (loss)	(51,142)	15,691
Production
Reconciliation of segment operating income (loss) to net income (loss)
Segment operating income	92	14,301
Midstream
Reconciliation of segment operating income (loss) to net income (loss)
Segment operating income	$ 1,858	$ 37,586

Reporting Segments (Assets by S

Reporting Segments (Assets by Segment) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 414,440	$ 486,685
Capital expenditures	905	4,867
Production
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	45,550	53,556
Capital expenditures	130	11
Midstream
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	362,961	429,523
Capital expenditures	775	4,856
Corporate
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 5,929	$ 3,606

Reporting Segments (Percentage

Reporting Segments (Percentage of Revenue) (Details) - Revenue - Customer Concentration Risk - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue, Major Customer [Line Items]
Number of major customers	0	0
Midstream | Sanchez Energy
Revenue, Major Customer [Line Items]
Concentration risk, percentage of revenue	86.00%	71.00%

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Jul. 31, 2016	Dec. 31, 2019	Dec. 31, 2018
Variable Interest Entity [Line Items]
Acquisitions, earnout and capital investments		$ 128,140	$ 127,899
Earnings in equity investments		25,976	23,144
Distributions received		(53,805)	(36,578)
Maximum exposure to loss		100,311	$ 114,465
Carnero Gathering, Joint Venture
Variable Interest Entity [Line Items]
Payments to acquire interest in joint venture	$ 37,000	124,100
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, 2019	Dec. 31, 2018
Supplemental Information On Oil And Natural Gas Producing Activities
Proved property	$ 112,476	$ 112,173
Less: accumulated depreciation, depletion, amortization and impairments	(69,541)	(65,647)
Oil and natural gas properties and equipment, net	$ 42,935	$ 46,526

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, 2019	Dec. 31, 2018
Supplemental Information On Oil And Natural Gas Producing Activities
Development costs	$ 131	$ 11
Oil and natural gas properties and equipment, net	$ 131	$ 11

Supplemental Information On O_5

Supplemental Information On Oil And Natural Gas Producing Activities (Proved Reserves) (Details) - MMBoe	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Changes in proved developed and undeveloped reserves
Balance	3,453	5,265
Sales of reserves in place		(1,105)
Revisions of previous estimates	(145)	(268)
Production	(309)	(439)
Balance	2,999	3,453
Proved developed reserves	2,999	3,453
Oil reserves
Changes in proved developed and undeveloped reserves
Balance	2,479	3,246
Sales of reserves in place		(272)
Revisions of previous estimates	(10)	(199)
Production	(228)	(296)
Balance	2,241	2,479
Proved developed reserves	2,241	2,479
Natural gas
Changes in proved developed and undeveloped reserves
Balance	454	1,109
Sales of reserves in place		(322)
Revisions of previous estimates	(67)	(261)
Production	(39)	(72)
Balance	348	454
Proved developed reserves	348	454
Natural gas liquids
Changes in proved developed and undeveloped reserves
Balance	520	910
Sales of reserves in place		(511)
Revisions of previous estimates	(68)	192
Production	(42)	(71)
Balance	410	520
Proved developed reserves	410	520

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, 2019USD ($)MMBoe$ / bbl$ / Mcf	Dec. 31, 2018USD ($)MMBoe$ / bbl$ / Mcf	Dec. 31, 2017MMBoe
Reserve Quantities [Line Items]
Exploration and dry hole costs | $	$ 0	$ 0
Proved reserve estimates	2,999	3,453	5,265
Reserve revision	2,999	3,453
Increase (decrease) in proved reserve estimates	0.5
Production	(309)	(439)
Revisions of previous estimates	(145)	(268)
Oil reserves
Reserve Quantities [Line Items]
Proved reserve estimates	2,241	2,479	3,246
Reserve revision	2,241	2,479
Production	(228)	(296)
Revisions of previous estimates	(10)	(199)
Weighted-average product price | $ / bbl	59.55	66.95
Natural gas
Reserve Quantities [Line Items]
Proved reserve estimates	348	454	1,109
Reserve revision	348	454
Production	(39)	(72)
Revisions of previous estimates	(67)	(261)
Weighted-average product price | $ / Mcf	2.66	3.21
Natural gas liquids
Reserve Quantities [Line Items]
Proved reserve estimates	410	520	910
Reserve revision	410	520
Production	(42)	(71)
Revisions of previous estimates	(68)	192
Weighted-average product price | $ / bbl	13.68	23
Louisiana, Briggs, and Cola Divestiture
Reserve Quantities [Line Items]
Increase (decrease) in proved reserve estimates		1.8	1.1

Supplemental Information On O_7

Supplemental Information On Oil And Natural Gas Producing Activities (Standardized Measure) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental Information On Oil And Natural Gas Producing Activities
Future cash inflows	$ 144,628	$ 186,675
Future production costs	(80,007)	(99,187)
Future estimated development costs	(3,400)	(4,043)
Future net cash flows	61,221	83,445
10% annual discount for estimated timing of cash flows	(22,871)	(31,199)
Standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves	$ 38,350	$ 52,246	$ 56,697

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, 2019	Dec. 31, 2018
Supplemental Information On Oil And Natural Gas Producing Activities
Beginning of the period	$ 52,246	$ 56,697
Sales and transfers of oil and natural gas, net of production costs	(8,006)	(14,795)
Net changes in prices and production costs related to future production	(7,330)	17,392
Changes in development costs	35	207
Revisions of previous quantity estimates	(1,942)	(4,203)
Purchases and sales of reserves in place		(5,423)
Accretion discount	5,225	5,670
Change in production rates, timing, and other	(1,878)	(3,299)
Standardized measure of discounted future net cash flows related to proved oil and natural gas reserves	$ 38,350	$ 52,246

Subsequent Events (Details)

Subsequent Events (Details) - Subsequent event - USD ($) $ in Millions	Feb. 13, 2020	Mar. 13, 2020
Credit Agreement
Subsequent Event [Line Items]
Payment of principal		$ 6
Outstanding debt on credit facility		$ 144
Class C preferred units
Subsequent Event [Line Items]
Class C Preferred Units payable in Class C Preferred PIK Units (as a percent)	100.00%
Class C Preferred Units Declared	1,039,314