Evolve Transition Infrastructure (SNMP) 10-Q 12 Aug 20 2020 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2020	Aug. 12, 2020
Document And Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2020
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q2
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		19,953,880
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Revenues
Gathering and transportation lease revenues	$ 11,339	$ 15,969	$ 23,945	$ 32,226
Total revenues	11,680	21,855	32,523	39,345
Operating expenses
Lease operating expenses	1,332	2,065	3,241	3,780
Transportation operating expenses	2,355	3,048	4,913	5,724
Production taxes	44	141	150	324
General and administrative expenses	4,512	4,171	8,287	8,920
Unit-based compensation expense	725	175	1,123	810
Depreciation, depletion and amortization	5,900	6,174	11,815	12,603
Asset impairments			23,247
Accretion expense	140	126	278	259
Total operating expenses	15,008	15,900	53,054	32,420
Other (income) expense
Interest expense, net	23,164	2,814	46,173	5,600
Earnings from equity investments	(3,897)	(791)	(2,695)	(2,233)
Other income	(8)	(21)	(8)	(67)
Total other expenses	19,259	2,002	43,470	3,300
Total expenses	34,267	17,902	96,524	35,720
Income (loss) before income taxes	(22,587)	3,953	(64,001)	3,625
Income tax expense (benefit)	30	76	(43)	122
Net income (loss)	(22,617)	3,877	(63,958)	3,503
Preferred unit paid-in-kind distributions		(10,605)		(10,605)
Preferred unit distributions				(8,838)
Preferred unit amortization		(745)		(1,442)
Net loss attributable to common unitholders - Basic and Diluted	$ (22,617)	$ (7,473)	$ (63,958)	$ (17,382)
Net loss per unit
Common units - Basic and Diluted (in dollars per share)	$ (1.18)	$ (0.42)	$ (3.35)	$ (1.02)
Common Units - Basic and Diluted (in units)	19,220,593	17,684,563	19,113,498	16,968,736
Natural gas sales
Revenues
Revenues	$ 84	$ 256	$ 318	$ 366
Oil sales
Revenues
Revenues	187	3,811	7,374	3,072
Natural gas liquid sales
Revenues
Revenues	$ 70	117	101	296
Gathering and transportation sales
Revenues
Revenues		$ 1,702	$ 785	$ 3,385

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Current assets
Cash and cash equivalents	$ 2,196	$ 5,099
Accounts receivable	7,010	133
Accounts receivable - related entities		6,719
Prepaid expenses	859	1,193
Fair value of commodity derivative instruments	1,517	226
Total current assets	11,582	13,370
Oil and natural gas properties and related equipment
Oil and natural gas properties, equipment and facilities (successful efforts method)	112,471	112,476
Gathering and transportation assets	187,075	186,941
Less: accumulated depreciation, depletion, amortization and impairment	(172,249)	(144,189)
Oil and natural gas properties and equipment, net	127,297	155,228
Other assets
Intangible assets, net	138,516	145,246
Equity investments	97,772	100,311
Other non-current assets	123	285
Total assets	375,290	414,440
Current liabilities
Accounts payable and accrued liabilities	5,955	5,347
Accounts payable and accrued liabilities - related entities	60	631
Royalties payable	359	359
Short-term debt, net of debt issuance costs	39,287	39,374
Fair value of commodity derivative instruments		985
Total current liabilities	45,661	46,696
Other liabilities
Long term accrued liabilities - related entities	6,854	4,892
Asset retirement obligation	7,176	6,898
Long-term debt, net of debt issuance costs	89,781	109,437
Class C Preferred Units	324,314	281,688
Other liabilities	795	629
Total other liabilities	428,920	403,544
Total liabilities	474,581	450,240
Commitments and contingencies (See Note 11)
Partners' deficit
Common units, 19,955,263 and 20,087,462 units issued and outstanding as of June 30, 2020 and December 31, 2019, respectively	(99,291)	(35,800)
Total partners' deficit	(99,291)	(35,800)
Total liabilities and partners' capital	$ 375,290	$ 414,440

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Parenthetical) - shares	Jun. 30, 2020	Dec. 31, 2019
Condensed Consolidated Balance Sheets
Units, issued	19,955,263	20,087,462
Units, outstanding	19,955,263	20,087,462

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019
Cash flows from operating activities:
Net (income) loss	$ (63,958)	$ 3,503
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	5,085	5,873
Amortization of debt issuance costs	366	578
Accretion of Class C discount	18,046
Class C distribution accrual	24,580
Asset impairments	23,247
Accretion expense	278	259
Distributions from equity investments	5,234	8,164
Equity earnings in affiliate	(2,695)	(2,233)
Mark-to-market on Warrant	166
Net (gain) loss on commodity derivative contracts	(4,178)	3,524
Net cash settlements received on commodity derivative contracts	1,660	469
Unit-based compensation	509	810
Gain on earnout derivative		(63)
Amortization of intangible assets	6,730	6,730
Changes in Operating Assets and Liabilities:
Accounts receivable	(6,685)	23
Accounts receivable - related entities	6,719	176
Prepaid expenses	334	(501)
Other assets	(110)	42
Accounts payable and accrued liabilities	738	2,585
Accounts payable and accrued liabilities- related entities	1,308	176
Other long-term liabilities		22
Net cash provided by operating activities	17,374	30,137
Cash flows from investing activities:
Development of oil and natural gas properties	5	(103)
Construction of gathering and transportation assets	(132)	(357)
Contributions to equity affiliates		(242)
Net cash used in investing activities	(127)	(702)
Cash flows from financing activities:
Proceeds from issuance of debt	2,000
Repayment of debt	(22,000)	(8,000)
Distributions to common unitholders		(5,216)
Class B preferred unit cash distributions		(17,675)
Units tendered by SOG employees for tax withholdings	(41)	(218)
Debt issuance costs	(109)	(7)
Net cash used in financing activities	(20,150)	(31,116)
Net decrease in cash and cash equivalents	(2,903)	(1,681)
Cash and cash equivalents, beginning of period	5,099	2,934
Cash and cash equivalents, end of period	2,196	1,253
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	2	82
Cash paid during the period for interest	$ 3,055	$ 5,070

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Changes in Partners’ Capital - USD ($) $ in Thousands	Common units	Total
Adoption of accounting standards	$ (181)	$ (181)
Partner's Deficit at Dec. 31, 2018	$ (64,620)	(64,620)
Partner's Deficit (in shares) at Dec. 31, 2018	16,486,239
Unit-based compensation programs	$ 815	815
Unit-based compensation programs (in shares)	978,076
Issuance of common units	$ 1,355	1,355
Issuance of common units (in shares)	787,750
Cash distributions to common unit holders	$ (2,471)	(2,471)
Distributions - Class B Preferred Units	(9,535)	(9,535)
Net income (loss)	(374)	(374)
Partner's Deficit at Mar. 31, 2019	$ (75,011)	(75,011)
Partner's Deficit (in shares) at Mar. 31, 2019	18,252,065
Partner's Deficit at Dec. 31, 2018	$ (64,620)	(64,620)
Partner's Deficit (in shares) at Dec. 31, 2018	16,486,239
Net income (loss)		3,503
Partner's Deficit at Jun. 30, 2019	$ (83,238)	(83,238)
Partner's Deficit (in shares) at Jun. 30, 2019	19,188,086
Partner's Deficit at Mar. 31, 2019	$ (75,011)	(75,011)
Partner's Deficit (in shares) at Mar. 31, 2019	18,252,065
Units tendered by SOG employees for tax withholding	$ (218)	(218)
Units tendered by SOG employees for tax withholding (in shares)	(84,711)
Unit-based compensation programs	$ 175	175
Unit-based compensation programs (in shares)	133,463
Issuance of common units	$ 2,034	2,034
Issuance of common units (in shares)	887,269
Cash distributions to common unit holders	$ (2,745)	(2,745)
Distributions - Class B Preferred Units	(11,350)	(11,350)
Net income (loss)	3,877	3,877
Partner's Deficit at Jun. 30, 2019	$ (83,238)	(83,238)
Partner's Deficit (in shares) at Jun. 30, 2019	19,188,086
Partner's Deficit at Dec. 31, 2019	$ (35,800)	(35,800)
Partner's Deficit (in shares) at Dec. 31, 2019	20,087,462
Units tendered by SOG employees for tax withholding	$ (31)	(31)
Units tendered by SOG employees for tax withholding (in shares)	(88,819)
Unit-based compensation programs	$ 243	243
Unit-based compensation programs (in shares)	(23,387)
Net income (loss)	$ (41,341)	(41,341)
Partner's Deficit at Mar. 31, 2020	$ (76,929)	(76,929)
Partner's Deficit (in shares) at Mar. 31, 2020	19,975,256
Partner's Deficit at Dec. 31, 2019	$ (35,800)	(35,800)
Partner's Deficit (in shares) at Dec. 31, 2019	20,087,462
Net income (loss)		(63,958)
Partner's Deficit at Jun. 30, 2020	$ (99,291)	(99,291)
Partner's Deficit (in shares) at Jun. 30, 2020	19,955,263
Partner's Deficit at Mar. 31, 2020	$ (76,929)	(76,929)
Partner's Deficit (in shares) at Mar. 31, 2020	19,975,256
Units tendered by SOG employees for tax withholding	$ (11)	(11)
Units tendered by SOG employees for tax withholding (in shares)	(19,867)
Unit-based compensation programs	$ 266	266
Unit-based compensation programs (in shares)	(126)
Net income (loss)	$ (22,617)	(22,617)
Partner's Deficit at Jun. 30, 2020	$ (99,291)	$ (99,291)
Partner's Deficit (in shares) at Jun. 30, 2020	19,955,263

Organization And Business

Organization And Business	6 Months Ended
	Jun. 30, 2020
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 a shared services agreement (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. 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	6 Months Ended
	Jun. 30, 2020
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 (as defined in Note 9 “Intangible Assets”) and the Carnero JV (as defined in Note 10 “Investments”). Production consists of our oil and natural gas properties in Texas and Louisiana. Our management evaluates performance based on these two business segments. These unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures, normally included in annual financial statements prepared in accordance with GAAP, have been condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information presented not misleading. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to fairly state the financial position, results of operations and cash flows with respect to the interim condensed consolidated financial statements have been included. The results of operations for the interim periods are not necessarily indicative of the results for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2019, which was filed with the SEC on March 13, 2020. Recent Accounting Pronouncements From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our consolidated financial statements upon adoption. In January 2020, the FASB issued Accounting Standards Update (“ASU”) 2020-01 “Investments—Equity Securities (Topic 321), Investments—Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815) ,” which clarifies the interaction among the accounting standards for equity securities, equity method investments and certain derivatives. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2020. We are currently in the process of evaluating the impact of adoption of this guidance on our condensed consolidated financial statements. In August 2018, the FASB issued 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. The Partnership adopted this standard effective January 1, 2020. The adoption of this standard did not have a material impact on our condensed consolidated financial statements. 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 condensed 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 condensed consolidated financial statements are prepared in conformity with GAAP, which requires management to make estimates and assumptions that affect the amounts reported in the condensed 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	6 Months Ended
	Jun. 30, 2020
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 $11.7 million and $32.5 million for the three and six months ended June 30, 2020, 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 Firm Transportation Service Agreement, dated September 1, 2017, by and between Seco Pipeline, LLC and SN Catarina, LLC (the “Seco Pipeline Transportation Agreement”) is the only contract that we account for under ASC 606. On January 13, 2020, we received written notice of termination from Mesquite terminating the Seco Pipeline Transportation Agreement effective February 12, 2020. The Gathering Agreement (as defined in Note 12 “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 condensed consolidated statements of operations. Both of these contracts are further discussed in Note 12 “Related Party Transactions.” We account for income from our unconsolidated equity method investments as earnings from equity investments in our condensed consolidated statements of operations. Earnings from these equity method investments are further discussed in Note 10 “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 our 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 treated these services as a single performance obligation satisfied over time using volumes delivered as the measure of progress. The Seco Pipeline Transportation Agreement required payment within 30 days following the calendar month of delivery. The Seco Pipeline Transportation Agreement contained 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 condensed consolidated financial statements and have a low probability of occurrence. As significant reversals of revenue due to this variability are not probable, no estimation is required. Contract Balances Under our sales contracts, we invoice customers after our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities under

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2020
Fair Value Measurements
Fair Value Measurements	4. FAIR VALUE MEASUREMENTS Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories: Level 1: Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. 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 June 30, 2020 (in thousands): Fair Value Measurements at June 30, 2020 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative assets $ — $ 1,517 $ — $ 1,517 Other liabilities Warrant — (795) — (795) Total $ — $ 722 $ — $ 722 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 liabilities $ — $ (759) $ — $ (759) Other liabilities Warrant — (629) — (629) Total $ — $ (1,388) $ — $ (1,388) As of June 30, 2020 and December 31, 2019, 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 8 “Asset Retirement Obligation.” The following table summarizes the non-recurring fair value measurements of our production assets as of June 30, 2020 (in thousands): Fair Value Measurements at June 30, 2020 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Impairment (a) $ — $ — $ 12,852 Total net assets $ — $ — $ 12,852 (a) During the six months ended June 30, 2020, we recorded a non-cash impairment charge of $23.2 million to impair our producing oil and natural gas properties. The carrying values of the impaired properties were reduced to a fair value of $12.9 million, estimated using inputs characteristic of a Level 3 fair value measurement. We had no non-recurring fair value measurements of our production assets as of December 31, 2019. The fair values of oil and natural gas properties and related equipment were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties and related equipment include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; (v) estimated throughput; and (vi) a market-based weighted average cost of capital rate of 15%. 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. Class C Preferred Units – On August 2, 2019, as part of the Exchange (as defined in Note 15 “Partners’ Capital”), Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units and the Warrant (as defined in Note 15 “Partners’ Capital”) in a private placement transaction. The fair value of the Class C Preferred Units was measured using valuation techniques that convert a future obligation to a single discounted amount. Significant inputs used to determine the fair value were observable and we have therefore classified the fair value measurements of the Class C Preferred units as Level 2. Seco Pipeline – As of December 31, 2019, 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 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 (as defined in Note 6 “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 6 “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. 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 condensed consolidated balance sheets. Earnout Derivative – As part of the Carnero Gathering Transaction (as defined in Note 10 “Investments”), we are required to pay Mesquite an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Mesquite 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 earnout derivative liability classified as Level 3 in the fair value hierarchy (in thousands): Six Months Ended Year Ended June 30, 2020 December 31, 2019 Beginning balance $ — $ (5,856) Gain on earnout derivative — 5,856 Ending balance $ — $ — Gain included in earnings related to derivatives still held as of June 30, 2020 and December 31, 2019, respectively $ — $ 5,856

Derivative And Financial Instru

Derivative And Financial Instruments	6 Months Ended
	Jun. 30, 2020
Derivative And Financial Instruments
Derivative And Financial Instruments	5. DERIVATIVE AND FINANCIAL INSTRUMENTS To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that fix or modify the future prices to be realized. These 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 condensed 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 condensed consolidated statements of operations. As of June 30, 2020, we had the following derivative contracts in place for the periods indicated, all of which are accounted for as mark-to-market activities: Fixed Price Basis Swaps – West Texas Intermediate (WTI) September 30, December 31, Total Average Average Average Volume Price Volume Price Volume Price 2020 49,224 $ 53.50 47,624 $ 53.50 96,848 $ 53.50 Fixed Price Swaps – NYMEX (Henry Hub) September 30, December 31, Total Average Average Average Volume Price Volume Price Volume Price 2020 99,136 $ 2.85 96,200 $ 2.85 195,336 $ 2.85 The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the six months ended June 30, 2020 and the year ended December 31, 2019 (in thousands): Six Months Ended Year Ended June 30, 2020 December 31, 2019 Beginning fair value of commodity derivatives $ (759) $ 3,914 Net gains (losses) on crude oil derivatives 4,027 (4,031) Net gains on natural gas derivatives 151 259 Net settlements received on derivative contracts: Oil (1,692) (807) Natural gas (210) (94) Ending fair value of commodity derivatives $ 1,517 $ (759) The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands): Location of Gain (Loss) Three Months Ended June 30, Six Months Ended June 30, Derivative Type in Income 2020 2019 2020 2019 Commodity – Mark-to-Market Oil sales $ (799) $ 807 $ 4,027 $ (3,677) Commodity – Mark-to-Market Natural gas sales 29 193 151 153 $ (770) $ 1,000 $ 4,178 $ (3,524) Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently contracted with two 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 June 30, 2020 and December 31, 2019, the impact of non-performance credit risk on the valuation of our derivative instruments was not significant. Earnout Derivative Refer to Note 4 “Fair Value Measurements.”

Debt

Debt	6 Months Ended
	Jun. 30, 2020
Debt
Debt	6. 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, dated as of November 22, 2019 (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 June 30, 2020, the borrowing base under the Credit Agreement was $171.2 million and we had $130.0 million of debt outstanding, consisting of $125.0 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 $10.0 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 June 30, 2020. 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, excluding any current maturities of debt, 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 June 30, 2020, 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 June 30, 2020 and December 31, 2019 , our unamortized debt issuance costs were approximately $0.9 million and $1.2 million, respectively. These costs are amortized to interest expense in our condensed consolidated statements of operations over the life of our Credit Agreement. Amortization of debt issuance costs recorded during the three months ended June 30, 2020 and 2019 was approximately $0.2 million and $0.3 million, respectively. Amortization of debt issuance costs recorded during the six months ended June 30, 2020 and 2019 was approximately $0.4 million and $0.6 million, respectively.

Oil And Natural Gas Properties

Oil And Natural Gas Properties And Related Equipment	6 Months Ended
	Jun. 30, 2020
Oil And Natural Gas Properties And Related Equipment.
Oil And Natural Gas Properties And Related Equipment	7. OIL AND NATURAL GAS PROPERTIES AND RELATED EQUIPMENT Gathering and transportation assets consisted of the following (in thousands): June 30, December 31, 2020 2019 Gathering and transportation assets Midstream assets $ 187,075 $ 186,941 Less: Accumulated depreciation, amortization and impairment (78,237) (74,648) Total gathering and transportation assets, net $ 108,838 $ 112,293 Oil and natural gas properties and related equipment consisted of the following (in thousands): June 30, December 31, 2020 2019 Oil and natural gas properties and related equipment Proved property $ 112,471 $ 112,476 Less: Accumulated depreciation, depletion, amortization and impairments (94,012) (69,541) Total oil and natural gas properties and equipment, net $ 18,459 $ 42,935 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. 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 five to 15 years for furniture and equipment, up to 36 years for gathering facilities, and up to 40 years for transportation assets. Depreciation, depletion and amortization consisted of the following (in thousands): Three Months Ended Six Months Ended June 30, June 30, 2020 2019 2020 2019 Depreciation, depletion and amortization of oil and natural gas-related assets $ 724 $ 828 $ 1,496 $ 1,923 Depreciation and amortization of gathering and transportation related assets 1,810 1,981 3,589 3,950 Amortization of intangible assets 3,366 3,365 6,730 6,730 Total Depreciation, depletion and amortization $ 5,900 $ 6,174 $ 11,815 $ 12,603 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. 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. During the six months ended June 30, 2020, we recorded a non-cash impairment charge of $23.2 million to impair our producing oil and natural gas properties. At year end December 31, 2019, we recorded a non-cash impairment charge of $32.1 million to fully impair the Seco Pipeline after receiving the written notice from Mesquite, terminating the Seco Pipeline Transportation Agreement.

Asset Retirement Obligation

Asset Retirement Obligation	6 Months Ended
	Jun. 30, 2020
Asset Retirement Obligation
Asset Retirement Obligation	8. ASSET RETIREMENT OBLIGATION We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred if a reasonable estimate of fair value can be made. Each period, we accrete the ARO to its then present value. The associated asset retirement cost (“ARC”) is capitalized as part of the carrying amount of our oil and natural gas properties, equipment and facilities 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 AROs 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 changes in ARO for the six months ended June 30, 2020 and the year ended December 31, 2019 (in thousands): Six Months Ended Year Ended June 30, 2020 December 31, 2019 Asset retirement obligation, beginning balance $ 6,898 $ 6,200 Liabilities added from escalating working interests — 172 Accretion expense 278 526 Asset retirement obligation, ending balance $ 7,176 $ 6,898 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. During the six months ended June 30, 2020 and the year ended December 31, 2019, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing AROs.

Intangible Assets

Intangible Assets	6 Months Ended
	Jun. 30, 2020
Intangible Assets
Intangible Assets	9. INTANGIBLE ASSETS Intangible assets are comprised of customer and marketing contracts. The intangible assets balance includes $138.5 million related to the Gathering Agreement with Mesquite that was entered into as part of the acquisition of the Western Catarina gathering system. The Western Catarina gathering system (“Western Catarina Midstream”) is located on the western portion of Mesquite’s acreage position in Dimmit, La Salle and Webb counties, Texas (the western portion of such acreage, “Western Catarina”). Pursuant to the 15-year agreement, Mesquite tenders all of its crude oil, natural gas and other hydrocarbon-based product volumes produced 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 each of the six months ended June 30, 2020 and 2019 was approximately $6.7 million. These costs are amortized to depreciation, depletion, and amortization expense in our condensed consolidated statements of operations. The following table is a reconciliation of changes in intangible assets (in thousands): June 30, December 31, 2020 2019 Beginning balance $ 145,246 $ 158,706 Amortization (6,730) (13,460) Ending balance $ 138,516 $ 145,246

Investments

Investments	6 Months Ended
	Jun. 30, 2020
Investments
Investments	10. INVESTMENTS In July 2016, we completed a transaction pursuant to which we acquired from Mesquite 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 e arnings from equity investments in our condensed consolidated statements of operations. As part of the Carnero Gathering Transaction, we are required to pay Mesquite an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Mesquite and other producers. See Note 4 “Fair Value Measurements” for further discussion of the earnout derivative. In November 2016, we completed a transaction pursuant to which we acquired from Mesquite 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 Mesquite and its working interest partners of over 315,000 acres located in the Western Eagle Ford on Mesquite’s acreage in Dimmit, Webb, La Salle, Zavala and Maverick counties, Texas (such acreage is collectively referred to as Mesquite’s “Comanche Asset”) pursuant to a new long-term firm gas gathering and processing agreement. The agreement with Mesquite, which was approved by all of the unaffiliated Comanche Asset 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 condensed 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 June 30, 2020, 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 the condensed consolidated balance sheets. For the three months ended June 30, 2020, the Partnership recorded earnings of approximately $4.2 million in equity investments from the Carnero JV, which was offset by approximately $0.3 million related to the amortization of the contractual customer intangible asset. For the six months ended June 30, 2020, the Partnership recorded earnings of approximately $3.3 million in equity investments from the Carnero JV, which was offset by approximately $0.6 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 condensed consolidated statements of operations. Cash distributions of approximately $5.2 million were received during the six months ended June 30, 2020. Summarized financial information of unconsolidated entities is as follows (in thousands): Six Months Ended June 30, 2020 2019 Sales $ 37,146 $ 97,061 Total expenses 27,692 88,647 Net income $ 9,454 $ 8,414

Commitments And Contingencies

Commitments And Contingencies	6 Months Ended
	Jun. 30, 2020
Commitments And Contingencies
Commitments And Contingencies	11. COMMITMENTS AND CONTINGENCIES As part of the Carnero Gathering Transaction, we are required to pay Mesquite an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Mesquite and other producers. This earnout has an approximate value of zero as of June 30, 2020. For the six months ended June 30, 2020, we made no payments to Mesquite related to the earnout. For the six months ended June 30, 2019, we paid Mesquite $32.1 thousand related to the earnout.

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2020
Related Party Transactions
Related Party Transactions	12. RELATED PARTY TRANSACTIONS Please read the disclosure under the headings “Sanchez-Related Agreements” and “Sanchez-Related Transactions” in Note 14 “Related Party Transactions” of our Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2019 for a more complete description of certain related party transactions that were entered into prior to 2020. The following is an update to such disclosure: In conjunction with the acquisition of Western Catarina Midstream, we entered into a 15-year gas gathering agreement with Mesquite pursuant to which Mesquite agreed to tender all of its crude oil, natural gas and other hydrocarbon-based product volumes produced 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, Mesquite 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. Mesquite 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, we and Mesquite amended the Gathering Agreement to add an incremental infrastructure fee to be paid by Mesquite based on water that is delivered through the gathering system through March 31, 2018 and we and Mesquite subsequently agreed to continue the incremental infrastructure fee on a month-to-month basis. On June 30, 2020, the SN Debtors emerged from the SN Chapter 11 Case, with Sanchez Energy Corporation becoming a privately held corporation named Mesquite Energy, Inc. As a result, and in accordance with the terms of the Settlement Agreement, we entered into Amendment No. 2 to the Gathering Agreement (“Amendment No. 2”) to provide, among other things, (i) a new gathering & processing fee, (ii) removal of the minimum volume commitments and related deficiency fee obligations and (iii) expansion of the dedicated acreage thereunder. Amendment No. 2 will only become effective upon the satisfaction of certain closing conditions (as described in the Settlement Agreement) which have not yet occurred and may not occur at all. As of June 30, 2020, Mesquite is not considered a related party of the Partnership. As of June 30, 2020 and December 31, 2019, the Partnership also had a net payable of approximately $6.9 million, and $5.5 million, respectively, which are included in the accounts payable and accrued liabilities – related entities and long term accrued liabilities – related entities on the condensed consolidated balance sheets. The payables as of June 30, 2020 and December 31, 2019 consist primarily of obligations for general and administrative costs and costs associated with transportation. The Partnership had a net receivable of zero and approximately $6.7 million as of June 30, 2020 and December 31, 2020, respectively. These amounts are included in accounts receivable – related entities on the condensed consolidated balance sheets and primarily consist of revenues receivable from oil and natural gas production and transportation, offset by costs associated with that production and transportation pursuant to the terms of the Settlement Agreement, $1.9 million of past due receivables from Mesquite were waived by the Partnership, this receivable will be reclassified as a contract asset upon the satisfaction of certain closing conditions (as described in the Settlement Agreement) which have not yet occurred and may not occur at all.

Unit-Based Compensation

Unit-Based Compensation	6 Months Ended
	Jun. 30, 2020
Unit-Based Compensation
Unit-Based Compensation	13. UNIT-BASED COMPENSATION The Sanchez Midstream Partners LP Long-Term Incentive Plan (the “LTIP”) allows for grants of restricted common units. Restricted common unit activity under the LTIP during the period is presented in the following table: Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2019 1,155,467 $ 3.86 Vested (291,318) 4.01 Returned/Cancelled (132,073) 5.55 Outstanding at June 30, 2020 732,076 $ 3.49 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. As of June 30, 2020, 973,010 common units remained available for future issuance to participants under the LTIP.

Distributions To Unitholders

Distributions To Unitholders	6 Months Ended
	Jun. 30, 2020
Distributions To Unitholders
Distributions To Unitholders	14. DISTRIBUTIONS TO UNITHOLDERS The table below reflects the payment of cash distributions on common units related to the periods indicated. Distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2019 $ 0.1500 May 3, 2019 May 22, 2019 May 31, 2019 Beginning with the determination of the distribution for the second-quarter 2019, the Board determined to establish a cash reserve to pay down a portion of the Partnership’s debt outstanding under the Credit Agreement. Following the establishment of the cash reserve, each quarter since the first-quarter 2019, the Board has determined that the Partnership did not have any available cash and, as a result, no cash distribution has been declared for the common units since the quarter ended March 31, 2019. As previously disclosed, our partnership agreement currently prohibits us from paying any distributions on our common units until we have redeemed all of the Class C Preferred Units. Following such redemption, the Credit Agreement may further limit our ability to pay distributions to unitholders. The table below reflects the payment of distributions on Class B Preferred Units (defined below) related to the periods indicated. Cash distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2019 $ 0.28225 May 3, 2019 May 22, 2019 May 31, 2019 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”). As a result, the Partnership paid a distribution on the Class C Preferred Units in Class C Preferred PIK Units in lieu of a distribution on the Class B Preferred Units for second-quarter 2019. 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 March 31, 2020 1,071,793 April 29, 2020 May 20, 2020 May 29, 2020 June 30, 2020 1,105,286 July 31, 2020 August 20, 2020 August 31, 2020

Partners' Capital

Partners' Capital	6 Months Ended
	Jun. 30, 2020
Partners' Capital
Partners' Capital	15. PARTNERS’ CAPITAL Outstanding Units As of June 30, 2020, we had no Class B Preferred Units outstanding, 35,369,150 Class C Preferred Units outstanding, and 19,955,263 common units outstanding which included 732,076 unvested restricted common units issued under the LTIP. Common Unit Issuances The following table shows the common units issued by the Partnership in 2019 to Manager in connection with providing services under the Services Agreement: Common Date of Three months ended units issuance December 31, 2018 787,750 March 8, 2019 March 31, 2019 887,269 May 23, 2019 June 30, 2019 901,741 August 2, 2019 We entered into a letter agreement with Manager providing that during the period beginning with the fiscal quarter ended September 30, 2019 and continuing until the end of the fiscal quarter after the fiscal quarter in which we redeem all of our issued and outstanding Class C Preferred Units, Manager agrees to delay receipt of its fees, not including reimbursement of costs, as a result, we have not issued any common units to Manager in connection with providing services under the Services Agreement for any quarter following the quarter ended June 30, 2019. Class B Preferred Unit Offering On October 14, 2015, pursuant to the Class B Preferred Unit Purchase Agreement dated September 25, 2015, by and between the Partnership and Stonepeak Catarina Holdings LLC (“Stonepeak”), the Partnership sold and Stonepeak purchased 19,444,445 of the Partnership’s newly created Class B Preferred Units (the “Class B Preferred Units”) in a private placement transaction for an aggregate cash purchase price of $18.00 per Class B Preferred Unit, which resulted in gross proceeds to the Partnership of approximately $350.0 million. The Partnership used the net proceeds to pay a portion of the consideration for the acquisition of Western Catarina Midstream, along with the payment to Stonepeak of a fee equal to 2.25% of the consideration paid for the Class B Preferred Units. On December 6, 2016, the Partnership 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 “Stonepeak Settlement Agreement”) to settle a dispute arising from the calculation of an adjustment to the number of Class B Preferred Units issued. Pursuant to the Stonepeak Settlement Agreement, the Partnership issued 1,704,446 Class B Preferred Units to Stonepeak in a private placement 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. The Class B Preferred Units were accounted for as mezzanine equity on our condensed consolidated balance sheets. The following table sets forth a reconciliation of the changes in mezzanine equity (in thousands): December 31, 2019 Mezzanine equity, beginning balance $ 349,857 Amortization of discount 1,708 Distributions 23,247 Distributions paid (17,675) Class B Preferred Unit exchange (357,137) Mezzanine equity, ending balance $ — 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”) in a private placement transaction (the “Exchange”). Class C Preferred Units 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 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 condensed 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 our condensed consolidated balance sheet consisting of the following (in thousands): June 30, December 31, 2020 2019 Class C Preferred Units, beginning balance $ 281,688 $ — Private placement of Class C Preferred Units — 353,500 Discount — (104,250) Amortization of discount 18,046 13,129 Distribution accrual 24,580 19,309 Class C Preferred Units, ending balance $ 324,314 $ 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 condensed consolidated balance sheet. Changes in the fair value of the Warrant are charged to interest expense in our condensed 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 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	6 Months Ended
	Jun. 30, 2020
Reporting Segments
Reporting Segments	16. 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): Three Months Ended June 30, 2020 2019 Production Midstream Production Midstream Segment revenues Natural gas sales $ 84 $ — $ 256 $ — Oil sales 187 — 3,811 — Natural gas liquid sales 70 — 117 — Gathering and transportation sales — — — 1,702 Gathering and transportation lease revenues — 11,339 — 15,969 Total segment revenues 341 11,339 4,184 17,671 Segment operating costs Lease operating expenses 1,110 222 1,688 377 Transportation operating expenses — 2,355 — 3,048 Production taxes 44 — 141 — Depreciation, depletion and amortization 724 5,176 828 5,346 Accretion expense 52 88 46 80 Total segment operating costs 1,930 7,841 2,703 8,851 Segment other income Earnings from equity investments — 3,897 — 791 Total segment other income — 3,897 — 791 Segment operating income (loss) $ (1,589) $ 7,395 $ 1,481 $ 9,611 Six Months Ended June 30, 2020 2019 Production Midstream Production Midstream Segment revenues Natural gas sales $ 318 $ — $ 366 $ — Oil sales 7,374 — 3,072 — Natural gas liquid sales 101 — 296 — Gathering and transportation sales — 785 — 3,385 Gathering and transportation lease revenues — 23,945 — 32,226 Total segment revenues 7,793 24,730 3,734 35,611 Segment operating costs Lease operating expenses 2,968 273 3,007 773 Transportation operating expenses — 4,913 — 5,724 Production taxes 150 — 324 — Depreciation, depletion and amortization 1,496 10,319 1,923 10,680 Asset impairments 23,247 — — — Accretion expense 104 174 100 159 Total segment operating costs 27,965 15,679 5,354 17,336 Segment other income Earnings from equity investments — 2,695 — 2,233 Total segment other income — 2,695 — 2,233 Segment operating income (loss) $ (20,172) $ 11,746 $ (1,620) $ 20,508 Three Months Ended Six Months Ended June 30, June 30, 2020 2019 2020 2019 Reconciliation of segment operating income (loss) to net income (loss) Total production operating income (loss) $ (1,589) $ 1,481 $ (20,172) $ (1,620) Total midstream operating income 7,395 9,611 11,746 20,508 Total segment operating income (loss) 5,806 11,092 (8,426) 18,888 General and administrative expenses (4,512) (4,171) (8,287) (8,920) Unit-based compensation expense (725) (175) (1,123) (810) Interest expense, net (23,164) (2,814) (46,173) (5,600) Other income 8 21 8 67 Income tax benefit (expense) (30) (76) 43 (122) Net income (loss) $ (22,617) $ 3,877 $ (63,958) $ 3,503 The following table summarizes the total assets by operating segment as of June 30, 2020 and December 31, 2019 and total capital expenditures for the six months ended June 30, 2020 and the year ended December 31, 2019 (in thousands): June 30, 2020 Production Midstream Corporate (a) Total Other financial information Total assets $ 22,128 $ 350,749 $ 2,413 $ 375,290 Capital expenditures (b) $ (5) $ 134 $ — $ 129 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 (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

Variable Interest Entities	6 Months Ended
	Jun. 30, 2020
Variable Interest Entities
Variable Interest Entities	17. 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 $97.8 million. As of June 30, 2020, 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 our condensed consolidated 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 June 30, 2020 and December 31, 2019 (in thousands): June 30, December 31, 2020 2019 Acquisitions, earnout and capital investments $ 128,140 $ 128,140 Earnings in equity investments 28,671 25,976 Distributions received (59,039) (53,805) Maximum exposure to loss $ 97,772 $ 100,311

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2020
Subsequent Events
Subsequent Events	18. SUBSEQUENT EVENTS On July 10, 2020, Kirsten A. Hink, the Chief Accounting Officer of our general partner informed the Board of Directors of our general partner (the “Board”) of her resignation to be deemed effective as of June 30, 2020. Ms. Hink’s decision to resign from her role as Chief Accounting Officer of our general partner was not due to any disagreement with our general partner, the Board or the Partnership, rather it is due to the resolution of the SN Chapter 11 Case. Ms. Hink is serving as Vice President and Controller of Mesquite and will no longer hold any roles with our general partner. On July 31, 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 second quarter distribution on the Class C Preferred Units payable 100% in Class C Preferred PIK Units. The aggregate distribution of 1,105,286 Class C Preferred PIK Units is payable on August 31, 2020 to holders of record on August 20, 2020.

Basis Of Presentation And Sum_2

Basis Of Presentation And Summary Of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2020
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 (as defined in Note 9 “Intangible Assets”) and the Carnero JV (as defined in Note 10 “Investments”). Production consists of our oil and natural gas properties in Texas and Louisiana. Our management evaluates performance based on these two business segments. These unaudited condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures, normally included in annual financial statements prepared in accordance with GAAP, have been condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information presented not misleading. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to fairly state the financial position, results of operations and cash flows with respect to the interim condensed consolidated financial statements have been included. The results of operations for the interim periods are not necessarily indicative of the results for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2019, which was filed with the SEC on March 13, 2020.
Recent Accounting Pronouncements	Recent Accounting Pronouncements From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our consolidated financial statements upon adoption. In January 2020, the FASB issued Accounting Standards Update (“ASU”) 2020-01 “Investments—Equity Securities (Topic 321), Investments—Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815) ,” which clarifies the interaction among the accounting standards for equity securities, equity method investments and certain derivatives. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2020. We are currently in the process of evaluating the impact of adoption of this guidance on our condensed consolidated financial statements. In August 2018, the FASB issued 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. The Partnership adopted this standard effective January 1, 2020. The adoption of this standard did not have a material impact on our condensed consolidated financial statements. 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 condensed 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 condensed consolidated financial statements are prepared in conformity with GAAP, which requires management to make estimates and assumptions that affect the amounts reported in the condensed 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.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2020
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 June 30, 2020 (in thousands): Fair Value Measurements at June 30, 2020 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative assets $ — $ 1,517 $ — $ 1,517 Other liabilities Warrant — (795) — (795) Total $ — $ 722 $ — $ 722 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 liabilities $ — $ (759) $ — $ (759) Other liabilities Warrant — (629) — (629) Total $ — $ (1,388) $ — $ (1,388)
Non-Recurring Fair Value Measurements Of Assets And Liabilities	The following table summarizes the non-recurring fair value measurements of our production assets as of June 30, 2020 (in thousands): Fair Value Measurements at June 30, 2020 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Impairment (a) $ — $ — $ 12,852 Total net assets $ — $ — $ 12,852
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 earnout derivative liability classified as Level 3 in the fair value hierarchy (in thousands): Six Months Ended Year Ended June 30, 2020 December 31, 2019 Beginning balance $ — $ (5,856) Gain on earnout derivative — 5,856 Ending balance $ — $ — Gain included in earnings related to derivatives still held as of June 30, 2020 and December 31, 2019, respectively $ — $ 5,856

Derivative And Financial Inst_2

Derivative And Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2020
Derivative And Financial Instruments
Summary Of Derivative Contracts In Place	Fixed Price Basis Swaps – West Texas Intermediate (WTI) September 30, December 31, Total Average Average Average Volume Price Volume Price Volume Price 2020 49,224 $ 53.50 47,624 $ 53.50 96,848 $ 53.50 Fixed Price Swaps – NYMEX (Henry Hub) September 30, December 31, Total Average Average Average Volume Price Volume Price Volume Price 2020 99,136 $ 2.85 96,200 $ 2.85 195,336 $ 2.85
Schedule Of Effect Of Derivative Instruments On Consolidated Statements Of Operations	Six Months Ended Year Ended June 30, 2020 December 31, 2019 Beginning fair value of commodity derivatives $ (759) $ 3,914 Net gains (losses) on crude oil derivatives 4,027 (4,031) Net gains on natural gas derivatives 151 259 Net settlements received on derivative contracts: Oil (1,692) (807) Natural gas (210) (94) Ending fair value of commodity derivatives $ 1,517 $ (759) The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands): Location of Gain (Loss) Three Months Ended June 30, Six Months Ended June 30, Derivative Type in Income 2020 2019 2020 2019 Commodity – Mark-to-Market Oil sales $ (799) $ 807 $ 4,027 $ (3,677) Commodity – Mark-to-Market Natural gas sales 29 193 151 153 $ (770) $ 1,000 $ 4,178 $ (3,524)

Oil And Natural Gas Propertie_2

Oil And Natural Gas Properties And Related Equipment (Tables)	6 Months Ended
	Jun. 30, 2020
Oil And Natural Gas Properties And Related Equipment.
Schedule of gathering and transportation assets	Gathering and transportation assets consisted of the following (in thousands): June 30, December 31, 2020 2019 Gathering and transportation assets Midstream assets $ 187,075 $ 186,941 Less: Accumulated depreciation, amortization and impairment (78,237) (74,648) Total gathering and transportation assets, net $ 108,838 $ 112,293
Schedule of oil and natural gas properties	June 30, December 31, 2020 2019 Gathering and transportation assets Midstream assets $ 187,075 $ 186,941 Less: Accumulated depreciation, amortization and impairment (78,237) (74,648) Total gathering and transportation assets, net $ 108,838 $ 112,293 Oil and natural gas properties and related equipment consisted of the following (in thousands): June 30, December 31, 2020 2019 Oil and natural gas properties and related equipment Proved property $ 112,471 $ 112,476 Less: Accumulated depreciation, depletion, amortization and impairments (94,012) (69,541) Total oil and natural gas properties and equipment, net $ 18,459 $ 42,935
Schedule of depreciation, depletion, and amortization	Depreciation, depletion and amortization consisted of the following (in thousands): Three Months Ended Six Months Ended June 30, June 30, 2020 2019 2020 2019 Depreciation, depletion and amortization of oil and natural gas-related assets $ 724 $ 828 $ 1,496 $ 1,923 Depreciation and amortization of gathering and transportation related assets 1,810 1,981 3,589 3,950 Amortization of intangible assets 3,366 3,365 6,730 6,730 Total Depreciation, depletion and amortization $ 5,900 $ 6,174 $ 11,815 $ 12,603

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	6 Months Ended
	Jun. 30, 2020
Asset Retirement Obligation
Reconciliation of changes in asset retirement obligation	The following table is a reconciliation of changes in ARO for the six months ended June 30, 2020 and the year ended December 31, 2019 (in thousands): Six Months Ended Year Ended June 30, 2020 December 31, 2019 Asset retirement obligation, beginning balance $ 6,898 $ 6,200 Liabilities added from escalating working interests — 172 Accretion expense 278 526 Asset retirement obligation, ending balance $ 7,176 $ 6,898

Intangible Assets (Tables)

Intangible Assets (Tables)	6 Months Ended
	Jun. 30, 2020
Intangible Assets
Schedule of Intangible assets	The following table is a reconciliation of changes in intangible assets (in thousands): June 30, December 31, 2020 2019 Beginning balance $ 145,246 $ 158,706 Amortization (6,730) (13,460) Ending balance $ 138,516 $ 145,246

Investments (Tables)

Investments (Tables)	6 Months Ended
	Jun. 30, 2020
Investments
Summarized financial information of unconsolidated entities	Summarized financial information of unconsolidated entities is as follows (in thousands): Six Months Ended June 30, 2020 2019 Sales $ 37,146 $ 97,061 Total expenses 27,692 88,647 Net income $ 9,454 $ 8,414

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2020
Unit-Based Compensation
Schedule of units activity	Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2019 1,155,467 $ 3.86 Vested (291,318) 4.01 Returned/Cancelled (132,073) 5.55 Outstanding at June 30, 2020 732,076 $ 3.49

Distributions To Unitholders (T

Distributions To Unitholders (Tables)	6 Months Ended
	Jun. 30, 2020
Common units
Schedule of payment of cash distributions	Distribution Date of Date of Date of Three months ended per unit declaration record distribution 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, 2019 $ 0.28225 May 3, 2019 May 22, 2019 May 31, 2019
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 March 31, 2020 1,071,793 April 29, 2020 May 20, 2020 May 29, 2020 June 30, 2020 1,105,286 July 31, 2020 August 20, 2020 August 31, 2020

Partners' Capital (Tables)

Partners' Capital (Tables)	6 Months Ended
	Jun. 30, 2020
Partners' Capital
Schedule of common unit issuances	Common Date of Three months ended units issuance 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 were accounted for as mezzanine equity on our condensed consolidated balance sheets. The following table sets forth a reconciliation of the changes in mezzanine equity (in thousands): December 31, 2019 Mezzanine equity, beginning balance $ 349,857 Amortization of discount 1,708 Distributions 23,247 Distributions paid (17,675) Class B Preferred Unit exchange (357,137) Mezzanine equity, ending balance $ —
Schedule of Class C preferred units	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 our condensed consolidated balance sheet consisting of the following (in thousands): June 30, December 31, 2020 2019 Class C Preferred Units, beginning balance $ 281,688 $ — Private placement of Class C Preferred Units — 353,500 Discount — (104,250) Amortization of discount 18,046 13,129 Distribution accrual 24,580 19,309 Class C Preferred Units, ending balance $ 324,314 $ 281,688

Reporting Segments (Tables)

Reporting Segments (Tables)	6 Months Ended
	Jun. 30, 2020
Reporting Segments
Schedule of segment information	The following tables present financial information for each operating segment for the periods indicated based on our operating segments (in thousands): Three Months Ended June 30, 2020 2019 Production Midstream Production Midstream Segment revenues Natural gas sales $ 84 $ — $ 256 $ — Oil sales 187 — 3,811 — Natural gas liquid sales 70 — 117 — Gathering and transportation sales — — — 1,702 Gathering and transportation lease revenues — 11,339 — 15,969 Total segment revenues 341 11,339 4,184 17,671 Segment operating costs Lease operating expenses 1,110 222 1,688 377 Transportation operating expenses — 2,355 — 3,048 Production taxes 44 — 141 — Depreciation, depletion and amortization 724 5,176 828 5,346 Accretion expense 52 88 46 80 Total segment operating costs 1,930 7,841 2,703 8,851 Segment other income Earnings from equity investments — 3,897 — 791 Total segment other income — 3,897 — 791 Segment operating income (loss) $ (1,589) $ 7,395 $ 1,481 $ 9,611 Six Months Ended June 30, 2020 2019 Production Midstream Production Midstream Segment revenues Natural gas sales $ 318 $ — $ 366 $ — Oil sales 7,374 — 3,072 — Natural gas liquid sales 101 — 296 — Gathering and transportation sales — 785 — 3,385 Gathering and transportation lease revenues — 23,945 — 32,226 Total segment revenues 7,793 24,730 3,734 35,611 Segment operating costs Lease operating expenses 2,968 273 3,007 773 Transportation operating expenses — 4,913 — 5,724 Production taxes 150 — 324 — Depreciation, depletion and amortization 1,496 10,319 1,923 10,680 Asset impairments 23,247 — — — Accretion expense 104 174 100 159 Total segment operating costs 27,965 15,679 5,354 17,336 Segment other income Earnings from equity investments — 2,695 — 2,233 Total segment other income — 2,695 — 2,233 Segment operating income (loss) $ (20,172) $ 11,746 $ (1,620) $ 20,508
Schedule of reconciliation of segment operating income to net income (loss)	Three Months Ended Six Months Ended June 30, June 30, 2020 2019 2020 2019 Reconciliation of segment operating income (loss) to net income (loss) Total production operating income (loss) $ (1,589) $ 1,481 $ (20,172) $ (1,620) Total midstream operating income 7,395 9,611 11,746 20,508 Total segment operating income (loss) 5,806 11,092 (8,426) 18,888 General and administrative expenses (4,512) (4,171) (8,287) (8,920) Unit-based compensation expense (725) (175) (1,123) (810) Interest expense, net (23,164) (2,814) (46,173) (5,600) Other income 8 21 8 67 Income tax benefit (expense) (30) (76) 43 (122) Net income (loss) $ (22,617) $ 3,877 $ (63,958) $ 3,503
Summary of assets and capital expenditures by operating segment	The following table summarizes the total assets by operating segment as of June 30, 2020 and December 31, 2019 and total capital expenditures for the six months ended June 30, 2020 and the year ended December 31, 2019 (in thousands): June 30, 2020 Production Midstream Corporate (a) Total Other financial information Total assets $ 22,128 $ 350,749 $ 2,413 $ 375,290 Capital expenditures (b) $ (5) $ 134 $ — $ 129 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 (a) Corporate assets not reviewed by the CODM on a segment basis consists of cash, certain prepaid expenses, office furniture, and other assets. Inclusive of capital contributions made to equity method investments.

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	6 Months Ended
	Jun. 30, 2020
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 June 30, 2020 and December 31, 2019 (in thousands): June 30, December 31, 2020 2019 Acquisitions, earnout and capital investments $ 128,140 $ 128,140 Earnings in equity investments 28,671 25,976 Distributions received (59,039) (53,805) Maximum exposure to loss $ 97,772 $ 100,311

Basis Of Presentation And Sum_3

Basis Of Presentation And Summary Of Significant Accounting Policies (Details)	6 Months Ended
	Jun. 30, 2020segment
Basis Of Presentation And Summary Of Significant Accounting Policies
Number of business segments	2

Revenue Recognition (Details)

Revenue Recognition (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Revenue Recognition
Revenues	$ 11,680	$ 21,855	$ 32,523	$ 39,345
Payment term (in days)			30 days
Receivables	$ 1,900		$ 1,900		$ 1,100

Fair Value Measurements (Recurr

Fair Value Measurements (Recurring) (Details) - Recurring - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative liabilities	$ 1,517	$ (759)
Other liabilities: Warrant	(795)	(629)
Total	722	(1,388)
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative liabilities	1,517	(759)
Other liabilities: Warrant	(795)	(629)
Total	$ 722	$ (1,388)

Fair Value Measurements (Non-Re

Fair Value Measurements (Non-Recurring) (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2020	Dec. 31, 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Market-based weighted average cost of capital rate	15.00%
Nonrecurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total net assets		$ 0
Fair Value, Inputs, Level 3 | Nonrecurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment	$ 12,852
Total net assets	12,852
Asset impairments	$ 23,200
Fair Value, Inputs, Level 3 | Seco Pipeline, LLC | Nonrecurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Total net assets		0
Asset impairments		$ 32,100

Fair Value Measurements (Embedd

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

Derivative And Financial Inst_3

Derivative And Financial Instruments (Hedges In Place) (Details)	6 Months Ended
	Jun. 30, 2020$ / bblbbl
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	96,848
Average Price | $ / bbl	53.50
NYMEX 2020 Swap Quarter 3
Derivative [Line Items]
Volume (in Bbls) | bbl	99,136
Average Price | $ / bbl	2.85
NYMEX 2020 Swap Quarter 4
Derivative [Line Items]
Volume (in Bbls) | bbl	96,200
Average Price | $ / bbl	2.85
NYMEX 2020
Derivative [Line Items]
Volume (in Bbls) | bbl	195,336
Average Price | $ / bbl	2.85

Derivative And Financial Inst_4

Derivative And Financial Instruments (Changes In Fair Value) (Details) - Commodity Contract $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2020USD ($)	Jun. 30, 2019USD ($)	Jun. 30, 2020USD ($)item	Jun. 30, 2019USD ($)	Dec. 31, 2019USD ($)
Derivative Instruments Gain Loss [Line Items]
Beginning fair value of commodity derivatives			$ (759)	$ 3,914	$ 3,914
Net gain (loss) on derivatives	$ (770)	$ 1,000	4,178	(3,524)
Ending fair value of commodity derivatives	1,517		$ 1,517		(759)
Number of counterparties | item			2
Oil reserves
Derivative Instruments Gain Loss [Line Items]
Net gain (loss) on derivatives	(799)	807	$ 4,027	(3,677)	(4,031)
Net settlements received on derivative contracts			(1,692)		(807)
Natural gas
Derivative Instruments Gain Loss [Line Items]
Net gain (loss) on derivatives	$ 29	$ 193	151	$ 153	259
Net settlements received on derivative contracts			$ (210)		$ (94)

Derivative And Financial Inst_5

Derivative And Financial Instruments (Effect On Statement Of Operations) (Details) - Commodity Contract - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Embedded Derivative [Line Items]
Net gain (loss) on derivatives	$ (770)	$ 1,000	$ 4,178	$ (3,524)
Oil reserves
Embedded Derivative [Line Items]
Net gain (loss) on derivatives	(799)	807	4,027	(3,677)	$ (4,031)
Natural gas
Embedded Derivative [Line Items]
Net gain (loss) on derivatives	$ 29	$ 193	$ 151	$ 153	$ 259

Debt (Details)

Debt (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020USD ($)	Jun. 30, 2019USD ($)	Jun. 30, 2020USD ($)	Jun. 30, 2019USD ($)	Dec. 31, 2019USD ($)	Nov. 22, 2019USD ($)
Line of Credit Facility [Line Items]
Credit agreement available	$ 15,000		$ 15,000
Letters of credit outstanding	0		0
Credit agreement, outstanding	130,000		130,000
Amortization of debt issuance costs	200	$ 300	366	$ 578
Unamortized debt issue costs	900		900		$ 1,200
Credit Agreement
Line of Credit Facility [Line Items]
Maximum borrowing capacity	171,200		171,200		$ 155,000	$ 235,500
Quarterly principal and other mandatory prepayments			$ 10,000
Commitment fee on unutilized borrowing base			0.50%
Credit agreement, outstanding	$ 125,000		$ 125,000
Current assets to current liabilities ratio			1
Debt to Adjusted EBITDA ratio	3.5		3.5
Borrowing base term			45 days
Line of Credit Facility, Periodic Payment			$ 10,000
Revolving Loan
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 20,000		20,000
Credit agreement, outstanding	5,000		5,000
Letter of Credit
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 2,500		$ 2,500
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 | 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
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4.5		4.5

Oil And Natural Gas Propertie_3

Oil And Natural Gas Properties And Related Equipment (Gathering and Transportation Assets) (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Midstream assets	$ 187,075	$ 186,941
Less: Accumulated depreciation, amortization and impairment	(94,012)	(69,541)
Midstream
Property, Plant and Equipment [Line Items]
Midstream assets	187,075	186,941
Less: Accumulated depreciation, amortization and impairment	(78,237)	(74,648)
Total gathering and transportation assets, net	$ 108,838	$ 112,293

Oil And Natural Gas Propertie_4

Oil And Natural Gas Properties And Related Equipment (Properties) (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Oil And Natural Gas Properties And Related Equipment.
Proved property	$ 112,471	$ 112,476
Less: Accumulated depreciation, depletion, amortization and impairments	(94,012)	(69,541)
Total oil and natural gas properties and equipment, net	$ 18,459	$ 42,935

Oil And Natural Gas Propertie_5

Oil And Natural Gas Properties And Related Equipment (DDA and Impairments) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Amortization of intangible assets	$ 3,366	$ 3,365	$ 6,730	$ 6,730
Depreciation, depletion and amortization			5,085	5,873
Asset impairments			$ 23,247
Gathering Facilities
Property, Plant and Equipment [Line Items]
Useful lives			36 years
Transportation assets
Property, Plant and Equipment [Line Items]
Useful lives			40 years
Oil and Natural Gas-Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	724	828	$ 1,496	1,923
Non-cash impairment charges			23,200
Gathering and Transportation Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	1,810	1,981	$ 3,589	3,950
Gathering and Transportation Related Assets | Minimum
Property, Plant and Equipment [Line Items]
Useful lives			5 years
Gathering and Transportation Related Assets | Maximum
Property, Plant and Equipment [Line Items]
Useful lives			15 years
Oil and Natural Gas-Related Assets and Gathering and Transportation-Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	$ 5,900	$ 6,174	$ 11,815	$ 12,603
Seco Pipeline, LLC
Property, Plant and Equipment [Line Items]
Non-cash impairment charges					$ 32,100

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Asset Retirement Obligation
Asset retirement obligation, beginning balance			$ 6,898	$ 6,200	$ 6,200
Liabilities added from escalating working interests					172
Accretion expense	$ 140	$ 126	278	$ 259	526
Asset retirement obligation, ending balance	7,176		7,176		6,898
Legally restricted assets	$ 0		$ 0		$ 0

Intangible Assets (Details)

Intangible Assets (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Finite-Lived Intangible Assets [Line Items]
Beginning balance	$ 145,246	$ 158,706	$ 158,706
Amortization	(6,730)	$ 6,700	(13,460)
Ending balance	$ 138,516		$ 145,246
Customer Contracts
Finite-Lived Intangible Assets [Line Items]
Agreement term (in years)	15 years
Useful life	15 years

Investments (Details)

Investments (Details) $ in Thousands	1 Months Ended		3 Months Ended		6 Months Ended
	Nov. 30, 2016USD ($)	Jul. 31, 2016USD ($)	Jun. 30, 2020USD ($)	Jun. 30, 2019USD ($)	Jun. 30, 2020USD ($)	Jun. 30, 2019USD ($)	May 31, 2018a
Schedule of Equity Method Investments [Line Items]
Earnings from equity investments			$ 3,897	$ 791	$ 2,695	$ 2,233
Amortization of intangible assets			3,366	$ 3,365	6,730	6,730
Distributions received					5,234	$ 8,164
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
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
Earnings from equity investments			4,200		3,300
Distributions received					5,200
Carnero G&P, Joint Venture | Customer Relationships
Schedule of Equity Method Investments [Line Items]
Amortization of intangible assets			$ 300		$ 600
Carnero Gathering and Carnero Processing [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)							50.00%
Mesquite Energy, Inc. | Carnero Gathering, Joint Venture | Western Eagle Ford [Member]
Schedule of Equity Method Investments [Line Items]
Acres dedicated for gathering | a							315,000
Targa | Carnero Gathering, Joint Venture
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)		50.00%
Targa | Carnero Processing, Joint Venture
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)	50.00%
Targa | SIlver Oak II [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)							100.00%

Investments (Unconsolidated Ent

Investments (Unconsolidated Entities) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019
Investments
Sales	$ 37,146	$ 97,061
Total expenses	27,692	88,647
Net income	$ 9,454	$ 8,414

Commitments And Contingencies (

Commitments And Contingencies (Details) - USD ($)	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019
Carnero Gathering, Joint Venture
Variable Interest Entity [Line Items]
Earnout derivative liability	$ 0
Mesquite Energy, Inc.
Variable Interest Entity [Line Items]
Earnout payments	$ 0	$ 32,100

Related Party Transactions (Det

Related Party Transactions (Details) $ in Millions	Oct. 14, 2015$ / bblbbl	Jun. 30, 2020USD ($)	Dec. 31, 2019USD ($)
Related Party Transaction [Line Items]
Related parties, net receivable		$ 0	$ 6.7
Related parties, net payable		6.9	$ 5.5
Mesquite Energy, Inc.
Related Party Transaction [Line Items]
Past due receivables waived		$ 1.9
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 sales
Related Party Transaction [Line Items]
Gathering Agreement minimum quarterly volume delivery commitment | bbl	142,000
Gathering and processing fees (in dollars per volume) | $ / bbl	0.74
Western Catarina Midstream | Mesquite Energy, Inc.
Related Party Transaction [Line Items]
Agreement term (in years)		15 years

Unit-Based Compensation (Detail

Unit-Based Compensation (Details) - LTIP - $ / shares	1 Months Ended		6 Months Ended
	Apr. 30, 2019	Mar. 31, 2019	Jun. 30, 2020
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units available for issuance			973,010
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding			1,155,467
Number of Restricted Units, Vested			(291,318)
Number of Restricted Units, Returned/Cancelled			(132,073)
Number of Restricted Units, Outstanding			732,076
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding			$ 3.86
Weighted Averaged Grant Date Fair Value Per Unit, Vested			4.01
Weighted Averaged Grant Date Fair Value Per Unit, Returned/Cancelled			5.55
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding			$ 3.49
Restricted Stock Units (RSUs) | Directors
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted	137,613
Units available for issuance		991,560
Vesting period		3 years

Distributions To Unitholders (D

Distributions To Unitholders (Details) - $ / shares	Jul. 31, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019
Common units
Distribution paid per unit							$ 0.1500
Class B preferred units
Distribution paid per unit							$ 0.28225
Class C preferred units
Paid-in-kind units distributed		1,105,286	1,071,793	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	Jun. 30, 2020	Dec. 31, 2019	Dec. 06, 2016
Limited Partners' Capital Account [Line Items]
Common units, outstanding						19,955,263	20,087,462
Units, issued						19,955,263	20,087,462
Class B preferred units
Limited Partners' Capital Account [Line Items]
Units sold (in units)		19,444,445
Price per unit sold		$ 18
Proceeds from preferred units sold		$ 350
Percent of consideration paid		2.25%
Class B preferred units, issued								9,851,996
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						35,369,150
Common units
Limited Partners' Capital Account [Line Items]
Common units, outstanding						19,955,263
Units sold (in units)			901,741	887,269	787,750
Unvested restricted common units | LTIP
Limited Partners' Capital Account [Line Items]
Common units, outstanding						732,076

Partners' Capital (Preferred Un

Partners' Capital (Preferred Units) (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Distributions		$ 17,675
Class C preferred units, ending balance	$ 324,314		$ 281,688
Class B preferred units
Mezzanine equity, beginning balance		349,857	349,857
Amortization of discount			1,708
Distributions			23,247
Distributions paid			(17,675)
Class B Preferred Unit exchange			(357,137)
Mezzanine equity, ending balance
Class C preferred units
Mezzanine equity, beginning balance	281,688
Private placement of Class C Preferred Units			353,500
Discount			(104,250)
Amortization of discount	18,046		13,129
Distributions	24,580		19,309
Mezzanine equity, ending balance	324,314		$ 281,688
Deemed contribution from exchange	$ 103,800
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	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Segment operating revenues:
Gathering and transportation lease revenues	$ 11,339	$ 15,969	$ 23,945	$ 32,226
Total revenues	11,680	21,855	32,523	39,345
Segment operating costs:
Lease operating expenses	1,332	2,065	3,241	3,780
Transportation operating expenses	2,355	3,048	4,913	5,724
Production taxes	44	141	150	324
Depreciation, depletion and amortization	5,900	6,174	11,815	12,603
Asset impairments			23,247
Accretion expense	140	126	278	259	$ 526
Total operating expenses	15,008	15,900	53,054	32,420
Segment other income
Earnings from equity investments	3,897	791	2,695	2,233
Segment operating income (loss)	5,806	11,092	(8,426)	18,888
Production
Segment operating revenues:
Total revenues	341	4,184	7,793	3,734
Segment operating costs:
Lease operating expenses			2,968	3,007
Transportation operating expenses	1,110	1,688
Production taxes	44	141	150	324
Depreciation, depletion and amortization	724	828	1,496	1,923
Asset impairments			23,247
Accretion expense	52	46	104	100
Total operating expenses	1,930	2,703	27,965	5,354
Segment other income
Segment operating income (loss)	(1,589)	1,481	(20,172)	(1,620)
Midstream
Segment operating revenues:
Gathering and transportation lease revenues	11,339	15,969	23,945	32,226
Total revenues	11,339	17,671	24,730	35,611
Segment operating costs:
Lease operating expenses	2,355	3,048	273	773
Transportation operating expenses	222	377	4,913	5,724
Depreciation, depletion and amortization	5,176	5,346	10,319	10,680
Accretion expense	88	80	174	159
Total operating expenses	7,841	8,851	15,679	17,336
Segment other income
Earnings from equity investments	3,897	791	2,695	2,233
Total segment other income	3,897	791	2,695	2,233
Segment operating income (loss)	7,395	9,611	11,746	20,508
Natural gas sales
Segment operating revenues:
Revenues	84	256	318	366
Natural gas sales | Production
Segment operating revenues:
Revenues	84	256	318	366
Oil sales
Segment operating revenues:
Revenues	187	3,811	7,374	3,072
Oil sales | Production
Segment operating revenues:
Revenues	187	3,811	7,374	3,072
Natural gas liquid sales
Segment operating revenues:
Revenues	70	117	101	296
Natural gas liquid sales | Production
Segment operating revenues:
Revenues	$ 70	117	101	296
Gathering and transportation sales
Segment operating revenues:
Revenues		1,702	785	3,385
Gathering and transportation sales | Midstream
Segment operating revenues:
Revenues		$ 1,702	$ 785	$ 3,385

Reporting Segments - Reconcilia

Reporting Segments - Reconciliation of Segment Operating Income (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2020	Mar. 31, 2020	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2020	Jun. 30, 2019
Reconciliation of segment operating income (loss) to net loss
Segment operating income (loss)	$ 5,806		$ 11,092		$ (8,426)	$ 18,888
General and administrative expenses	(4,512)		(4,171)		(8,287)	(8,920)
Unit-based compensation expense	(725)		(175)		(1,123)	(810)
Interest expense, net	(23,164)		(2,814)		(46,173)	(5,600)
Other income	8		21		8	67
Income tax benefit (expense)	(30)		(76)		43	(122)
Net income (loss)	(22,617)	$ (41,341)	3,877	$ (374)	(63,958)	3,503
Production
Reconciliation of segment operating income (loss) to net loss
Segment operating income (loss)	(1,589)		1,481		(20,172)	(1,620)
Midstream
Reconciliation of segment operating income (loss) to net loss
Segment operating income (loss)	$ 7,395		$ 9,611		$ 11,746	$ 20,508

Reporting Segments (Assets by S

Reporting Segments (Assets by Segment) (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2020	Dec. 31, 2019
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 375,290	$ 414,440
Capital expenditures	129	905
Production
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	22,128	45,550
Capital expenditures	(5)	130
Midstream
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	350,749	362,961
Capital expenditures	134	775
Corporate
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 2,413	$ 5,929

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Thousands	1 Months Ended	6 Months Ended	12 Months Ended
	Jul. 31, 2016	Jun. 30, 2020	Dec. 31, 2019
Variable Interest Entity [Line Items]
Acquisitions, earnout and capital investments		$ 128,140	$ 128,140
Earnings in equity investments		28,671	25,976
Distributions received		(59,039)	(53,805)
Maximum exposure to loss		97,772	$ 100,311
Carnero Gathering, Joint Venture
Variable Interest Entity [Line Items]
Payments to acquire interest in joint venture	$ 37,000	124,100
Debt incurred		$ 0

Subsequent Events (Details)

Subsequent Events (Details) - Subsequent event	Jul. 31, 2020$ / sharesshares
Common units
Subsequent Event [Line Items]
Distribution declared per unit | $ / shares	$ 0
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 (in shares) | shares	1,105,286