Evolve Transition Infrastructure (SNMP) 10-Q 13 May 21 2021 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2021	May 12, 2021
Document And Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2021
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q1
Title of 12(b) Security	Common Units
Trading Symbol	SNMP
Security Exchange Name	NYSEAMER
Entity Registrant Name	Evolve Transition Infrastructure 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		56,185,378
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Revenues
Gathering and transportation lease revenues	$ 9,294	$ 12,606
Total revenues	11,810	20,843
Operating expenses
Lease operating expenses	1,840	1,909
Transportation operating expenses	1,903	2,558
Production taxes	105	106
General and administrative expenses	6,933	3,775
Unit-based compensation expense	337	398
Depreciation, depletion and amortization	5,461	5,915
Asset impairments		23,247
Accretion expense	148	138
Total operating expenses	16,727	38,046
Other (income) expense
Interest expense, net	30,447	23,009
Earnings from equity investments	(599)	1,202
Total other expenses	29,848	24,211
Total expenses	46,575	62,257
Loss before income taxes	(34,765)	(41,414)
Income tax expense	40	(73)
Net loss	$ (34,805)	$ (41,341)
Net loss per unit
Common units - Basic and Diluted (in dollars per share)	$ (0.89)	$ (2.18)
Common Units - Basic and Diluted (in units)	38,921,661	19,006,403
Natural gas sales
Revenues
Revenues	$ 75	$ 234
Oil sales
Revenues
Revenues	2,306	7,187
Natural gas liquid sales
Revenues
Revenues	$ 135	31
Gathering and transportation sales
Revenues
Revenues		$ 785

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Current assets
Cash and cash equivalents	$ 1,626	$ 1,718
Accounts receivable	7,404	6,670
Prepaid expenses	1,014	595
Total current assets	10,044	8,983
Oil and natural gas properties and related equipment
Oil and natural gas properties, equipment and facilities (successful efforts method)	112,471	112,471
Gathering and transportation assets	187,977	187,977
Less: accumulated depreciation, depletion, amortization and impairment	(179,649)	(177,553)
Oil and natural gas properties and equipment, net	120,799	122,895
Other assets
Intangible assets, net	128,423	131,786
Equity investments	87,670	89,635
Other non-current assets	119	129
Total assets	347,055	353,428
Current liabilities
Accounts payable and accrued liabilities	3,408	4,420
Accounts payable and accrued liabilities - related entities	12,869	25,737
Royalties payable	359	359
Short-term debt, net of debt issuance costs	103,942	110,233
Class C preferred units	356,855	345,205
Total current liabilities	477,433	485,954
Other liabilities
Long term accrued liabilities - related entities	16,584	12,137
Asset retirement obligation	7,613	7,465
Other liabilities	6,210	1,416
Total other liabilities	30,407	21,018
Total liabilities	507,840	506,972
Commitments and contingencies (See Note 11)
Partners' deficit
Common units, 56,185,378 and 19,953,880 units issued and outstanding as of March 31, 2021 and December 31, 2020, respectively	(160,785)	(153,544)
Total partners' deficit	(160,785)	(153,544)
Total liabilities and partners' capital	$ 347,055	$ 353,428

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Parenthetical) - shares	Mar. 31, 2021	Dec. 31, 2020
Condensed Consolidated Balance Sheets
Units, issued	56,185,378	19,953,880
Units, outstanding	56,185,378	19,953,880

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Cash flows from operating activities:
Net loss	$ (34,805)	$ (41,341)
Adjustments to reconcile net loss to cash provided by operating activities:
Depreciation, depletion and amortization	2,098	2,551
Amortization of debt issuance costs	209	181
Accretion of Class C discount	11,650	8,693
Class C distribution accrual		12,101
Asset impairments		23,247
Accretion expense	148	138
Distributions from equity investments	2,564	1,615
Equity earnings in affiliate	(599)	1,202
Mark-to-market on warrant	4,792	271
Net (gain) loss on commodity derivative contracts		(4,948)
Net cash settlements received on commodity derivative contracts	101	87
Unit-based compensation	1,879	243
Amortization of intangible assets	3,363	3,364
Changes in Operating Assets and Liabilities:
Accounts receivable	(835)	(1)
Accounts receivable - related entities		(1,006)
Prepaid expenses	(419)	77
Other assets	10	(108)
Accounts payable and accrued liabilities	24,673	(1,420)
Accounts payable and accrued liabilities- related entities	(8,421)	1,547
Net cash provided by operating activities	6,408	6,493
Cash flows from investing activities:
Development of oil and natural gas properties		5
Construction of gathering and transportation assets		(59)
Net cash used in investing activities		(54)
Cash flows from financing activities:
Repayment of debt	(12,000)	(10,000)
Proceeds from issuance of debt	5,500
Units tendered by SOG employees for tax withholdings		(31)
Debt issuance costs		(62)
Net cash used in financing activities	(6,500)	(10,093)
Net decrease in cash and cash equivalents	(92)	(3,654)
Cash and cash equivalents, beginning of period	1,718	5,099
Cash and cash equivalents, end of period	1,626	1,445
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures		62
Cash paid during the period for interest	$ 781	$ 1,767

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Changes in Partners’ Capital - USD ($) $ in Thousands	Common units	Total
Partner's Deficit at Dec. 31, 2019	$ (35,800)	$ (35,800)
Partner's Deficit (in shares) at Dec. 31, 2019	20,087,462
Unit-based compensation programs	$ 243	243
Unit-based compensation programs (in shares)	(23,387)
Units tendered by SOG employees for tax withholding	$ (31)	(31)
Units tendered by SOG employees for tax withholding (in shares)	(88,819)
Net 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, 2020	$ (153,544)	(153,544)
Partner's Deficit (in shares) at Dec. 31, 2020	19,953,880
Unit-based compensation programs	$ 1,879	1,879
Unit-based compensation programs (in shares)	1,511,138
Common units issued as Class C Preferred distributions	$ 25,685	25,685
Common units issued as Class C Preferred distributions (in shares)	34,720,360
Net loss	$ (34,805)	(34,805)
Partner's Deficit at Mar. 31, 2021	$ (160,785)	$ (160,785)
Partner's Deficit (in shares) at Mar. 31, 2021	56,185,378

Organization And Business

Organization And Business	3 Months Ended
	Mar. 31, 2021
Organization And Business
Organization And Business	1. ORGANIZATION AND BUSINESS Organization We are a publicly-traded limited partnership formed in 2005 focused on the acquisition, development, and ownership of infrastructure critical to the transition of energy supply to lower carbon sources. We own natural gas gathering systems, pipelines, and processing facilities in South Texas and continue to pursue energy transition infrastructure opportunities. Our common units are currently listed on the NYSE American under the symbol “SNMP.” On February 26, 2021, in connection with our management team’s focus on expanding our business strategy to focus on the ongoing energy transition in the industries in which we operate, we changed our name to Evolve Transition Infrastructure LP and our general partner changed its name to Evolve Transition Infrastructure GP LLC.

Basis Of Presentation And Summa

Basis Of Presentation And Summary Of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2021
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”), the Carnero JV (as defined in Note 10 “Investments”) and Seco Pipeline (as defined in Note 4 “Fair Value Measurements”). 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, 2020, which was filed with the SEC on March 16, 2021. 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. 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. Liquidity and Going Concern The Partnership’s inability to generate sufficient liquidity to meet future debt obligations raises substantial doubt regarding our ability to continue as a going concern. The Credit Agreement matures September 30, 2021 and our ability to continue as a going concern is contingent upon our ability to either (i) refinance or extend the maturity of the Credit Agreement, or (ii) obtain adequate new debt or equity financing to repay the Credit Agreement in full at maturity. We intend to refinance or extend the maturity of the Credit Agreement prior to its maturity date. However, we may not be able to refinance or extend the maturity of the Credit Agreement or, if we are able to refinance or extend the maturity, we may not be able to do so with borrowing and debt issue costs, terms, covenants, restrictions, commitment amount or a borrowing base favorable to us. The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of substantial doubt as to the Partnership’s ability to continue as a going concern. If the Partnership cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material. 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	3 Months Ended
	Mar. 31, 2021
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, “Revenue from Contracts with Customers.” 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 $11.8 million for the three months ended March 31, 2021. 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. The Seco Pipeline Transportation Agreement was terminated by Mesquite 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 revenues in our condensed consolidated statements of operations. 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, “Collaborative Agreements,” 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	3 Months Ended
	Mar. 31, 2021
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 March 31, 2021 (in thousands): Fair Value Measurements at March 31, 2021 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Other liabilities Warrant $ — $ (6,210) $ — $ (6,210) Total $ — $ (6,210) $ — $ (6,210) 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, 2020 (in thousands): Fair Value Measurements at December 31, 2020 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Other liabilities Warrant — (1,418) — (1,418) Total $ — $ (1,418) $ — $ (1,418) As of March 31, 2021and December 31, 2020, 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, “Fair Value Measurement,” 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 December 31, 2020 (in thousands): Fair Value Measurements at December 31, 2020 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Impairment (a) $ — $ — $ 12,884 Total net assets $ — $ — $ 12,884 (a) During the year ended December 31, 2020, we recorded a non-cash impairment charge of $23.4 million to impair our producing oil and natural gas properties and $0.9 million to impair the Seco Pipeline. 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. 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. Seco Pipeline – We own and operate a 30-mile natural gas pipeline with 400 MMcf/d capacity that is designed to transport dry gas to multiple markets in South Texas (the “Seco Pipeline”). As of December 31, 2020, we recorded a non-cash impairment charge of $0.9 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.” 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 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. As of March 31, 2021 and December 31, 2020, the fair value of the earnout was determined to be zero.

Derivative And Financial Instru

Derivative And Financial Instruments	3 Months Ended
	Mar. 31, 2021
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. We do not have derivative contracts related to production in 2021 and beyond. The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the year ended December 31, 2020 (in thousands): Year Ended December 31, 2020 Beginning fair value of commodity derivatives $ (759) Net gains (losses) on crude oil derivatives 3,814 Net gains on natural gas derivatives 87 Net settlements received on derivative contracts: Oil (2,829) Natural gas (313) Ending fair value of commodity derivatives $ — The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands): Location of Gain (Loss) Three Months Ended March 31, Derivative Type in Income 2020 Commodity – Mark-to-Market Oil sales $ 4,826 Commodity – Mark-to-Market Natural gas sales 122 $ 4,948 Earnout Derivative Refer to Note 4 “Fair Value Measurements.”

Debt

Debt	3 Months Ended
	Mar. 31, 2021
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 $17.5 million, which was reduced to the lesser of (i) $15.0 million through May 14, 2021 and (ii) from and after May 15, 2021, the positive difference of the Borrowing Base minus the aggregate outstanding principal amount of the Term Loan (the “Revolving Loan”). The Credit Agreement is a current liability that matures on September 30, 2021. We expect to refinance or extend the maturity of the Credit Agreement prior to its maturity date. However, we may not be able to refinance or extend the maturity of the Credit Agreement or, if we are able to refinance or extend the maturity, we may not be able to do so with borrowing and debt issue costs, terms, covenants, restrictions, commitment amount or a borrowing base favorable to us. 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. On November 6, 2020, the Partnership, as borrower, entered into that certain Tenth Amendment to the Third Amended and Restated Credit Agreement with the guarantors party thereto, Royal Bank of Canada, as administrative agent and collateral agent (the “Agent”) and the lenders party thereto (each a “Lender”) (the “Credit Agreement Amendment” and the Third Amended and Restated Credit Agreement, as amended by the Tenth Amendment, the “Amended Credit Agreement”). Pursuant to the Credit Agreement Amendment, the parties thereto agreed to, among other things: (a) amend the initial aggregate commitment amount under the first lien revolving credit facility to reduce such amount to $17.5 million, which was reduced to the lesser of (i) $15.0 million through May 14, 2021 and (ii) from and after May 15, 2021, the positive difference of the Borrowing Base minus the aggregate outstanding principal amount of the Term Loan; (b) amend the conditions precedent to the obligations of any Lender to make a Loan (as defined in the Amended Credit Agreement) to provide that through May 14, 2021, a Borrowing Base Deficiency (as defined in the Amended Credit Agreement) may exist; (c) amend the annual financial statements and annual budget affirmative covenant to provide that the Partnership’s audited annual financial statements as reported on by the Partnership’s independent public accountants may be delivered with a “going concern” or like qualification or exception, if such qualification or exception results from (i) any actual or prospective breach of the financial covenants set forth in Section 9.01 of the Amended Credit Agreement or (ii) the fact that the final maturity date of any Debt (as defined in the Amended Credit Agreement) is less than one year after the date of such report, and does not otherwise include any qualification or exception as to the scope of such audit; and (d) include a new post-closing covenant requiring the Partnership to either engage an Advisory Firm (as defined in the Credit Agreement Amendment) or certify that the Partnership has taken material steps, in either case, to implement a strategic transaction generating net cash proceeds reasonably expected to be greater than an amount that will allow the Partnership to repay in full all outstanding obligations under the Loan Documents (as defined in the Amended Credit Agreement) that is anticipated to close by August 31, 2021. 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 March 31, 2021, the borrowing base under the Credit Agreement was $113.7 million and we had $104.5 million of debt outstanding, consisting of $95.0 million under the Term Loan and $9.5 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 $15.0 million leaving us with $5.5 million in unused borrowing capacity. There were no letters of credit outstanding under our Credit Agreement as of March 31, 2021. 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 March 31, 2021, 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 March 31, 2021 and December 31, 2020 , our unamortized debt issuance costs were approximately $0.6 million and $0.8 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 March 31, 2021 and 2020 was approximately $0.2 million and $0.2 million, respectively.

Oil And Natural Gas Properties

Oil And Natural Gas Properties And Related Equipment	3 Months Ended
	Mar. 31, 2021
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): March 31, December 31, 2021 2020 Gathering and transportation assets Midstream assets $ 187,977 $ 187,977 Less: Accumulated depreciation, amortization and impairment (84,491) (82,710) Total gathering and transportation assets, net $ 103,486 $ 105,267 Oil and natural gas properties and related equipment consisted of the following (in thousands): March 31, December 31, 2021 2020 Oil and natural gas properties and related equipment Proved property $ 112,471 $ 112,471 Less: Accumulated depreciation, depletion, amortization and impairments (95,158) (94,843) Total oil and natural gas properties and equipment, net $ 17,313 $ 17,628 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 three 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 March 31, 2021 2020 Depreciation, depletion and amortization of oil and natural gas-related assets $ 317 $ 772 Depreciation and amortization of gathering and transportation related assets 1,781 1,779 Amortization of intangible assets 3,363 3,364 Total depreciation, depletion and amortization $ 5,461 $ 5,915 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 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. 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. At year end December 31, 2020, we recorded non-cash impairment charges of $23.4 million to impair our producing oil and natural gas properties.

Asset Retirement Obligation

Asset Retirement Obligation	3 Months Ended
	Mar. 31, 2021
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 three months ended March 31, 2021 and the year ended December 31, 2020 (in thousands): Three Months Ended Year Ended March 31, 2021 December 31, 2020 Asset retirement obligation, beginning balance $ 7,465 $ 6,898 Accretion expense 148 567 Asset retirement obligation, ending balance $ 7,613 $ 7,465 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 three months ended March 31, 2021 and the year ended December 31, 2020, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing AROs.

Intangible Assets

Intangible Assets	3 Months Ended
	Mar. 31, 2021
Intangible Assets
Intangible Assets	9. INTANGIBLE ASSETS Intangible assets are comprised of customer and marketing contracts. The intangible assets balance as of March 31, 2021 is 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 three months ended March 31, 2021 and 2020 was approximately $3.4 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): March 31, December 31, 2021 2020 Beginning balance $ 131,786 $ 145,246 Amortization (3,363) (13,460) Ending balance $ 128,423 $ 131,786

Investments

Investments	3 Months Ended
	Mar. 31, 2021
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 March 31, 2021 the Partnership had paid approximately $124.2 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 March 31, 2021, the Partnership recorded earnings of approximately $0.9 million in equity investments from the Carnero JV, which was partially offset by approximately $0.3 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 $2.6 million were received during the three months ended March 31, 2021. Summarized financial information of unconsolidated entities is as follows (in thousands): Three Months Ended March 31, 2021 2020 Sales $ 22,829 $ 14,252 Total expenses 19,578 14,606 Net income $ 3,251 $ (354)

Commitments And Contingencies

Commitments And Contingencies	3 Months Ended
	Mar. 31, 2021
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 March 31, 2021. For the three months ended March 31, 2021, we made no payments to Mesquite related to the earnout.

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2021
Related Party Transactions
Related Party Transactions	12. RELATED PARTY TRANSACTIONS Please read the disclosure under the headings “Relationship with Stonepeak,” “Relationship with Mesquite,” “Relationship with SP Holdings” and “Shared Services Agreement” in Note 13 “Related Party Transactions” of our Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2020 for a more complete description of certain related party transactions that were entered into prior to 2021.

Unit-Based Compensation

Unit-Based Compensation	3 Months Ended
	Mar. 31, 2021
Unit-Based Compensation
Unit-Based Compensation	13. UNIT-BASED COMPENSATION The Sanchez Production 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, 2020 683,171 $ 2.68 Granted 1,651,785 1.12 Returned/Cancelled (140,647) 2.37 Outstanding at March 31, 2021 2,194,309 $ 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 March 31, 2021, 1,577,847 common units remained available for future issuance to participants under the LTIP.

Distributions To Unitholders

Distributions To Unitholders	3 Months Ended
	Mar. 31, 2021
Distributions To Unitholders
Distributions To Unitholders	14. DISTRIBUTIONS TO UNITHOLDERS 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 On November 16, 2020, the Partnership and Stonepeak entered into a letter agreement (the “Stonepeak Letter Agreement”) wherein the parties agreed that the distribution on the Class C Preferred Units for the three months ended September 30, 2020 would be paid in common units instead of Class C Preferred PIK Units, cash or a combination thereof. The aggregate distribution of 22,274,869 common units was made payable to Stonepeak on February 1, 2021. The Stonepeak Letter Agreement also provides that Stonepeak will be able to elect to receive distributions on the Class C Preferred Units in common units for any quarter following the third quarter of 2020 by providing written notice to the Partnership no later than the last day of the calendar month following the end of such quarter. In accordance with the Stonepeak Letter Agreement, on January 28, 2021, the Partnership received written notice of Stonepeak’s election to receive distributions on the Class C Preferred Units for the quarter ended December 31, 2020 in common units. The aggregate distribution of 12,445,491 common units was paid to Stonepeak on February 25, 2021. In accordance with the Stonepeak Letter Agreement, on April 30, 2021, the Partnership received written notice of Stonepeak’s election to receive distributions on the Class C Preferred Units for the quarter ended March 31, 2021 in common units. The aggregate distribution of 13,763,249 common units will be paid to Stonepeak on May 20, 2021.

Partners' Capital

Partners' Capital	3 Months Ended
	Mar. 31, 2021
Partners' Capital
Partners' Capital	15. PARTNERS’ CAPITAL Outstanding Units As of March 31, 2021, we had 36,474,436 Class C Preferred Units outstanding and 56,185,378 common units outstanding which included 2,194,309 unvested restricted common units issued under the LTIP. Common Unit Issuances We entered into a letter agreement with SP Holdings 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, SP Holdings agrees to delay receipt of its fees, not including reimbursement of costs, as a result, we have not issued any common units to SP Holdings in connection with providing services under the Shared Services Agreement for any quarter following the quarter ended June 30, 2019. As of March 31, 2021, the number of units to be issued under the Shared Services Agreement is 15,294,741. Class C Preferred Units On August 2, 2019, Stonepeak exchanged all of their current equity ownership for newly issued Class C Preferred Units and a warrant exercisable for junior securities (the “Warrant”) in a private placement transaction (the “Exchange”). 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 Third Amended and Restated Agreement of Limited Partnership of the Partnership (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 Class C Preferred Units are accounted for as a liability on our condensed consolidated balance sheet consisting of the following (in thousands): March 31, December 31, 2021 2020 Class C Preferred Units, beginning balance $ 345,205 $ 281,688 Accretion of discount 11,650 38,938 Distribution accrual — 24,579 Class C Preferred Units, ending balance $ 356,855 $ 345,205 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	3 Months Ended
	Mar. 31, 2021
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 March 31, 2021 2020 Production Midstream Production Midstream Segment revenues Natural gas sales $ 75 $ — $ 234 $ — Oil sales 2,306 — 7,187 — Natural gas liquid sales 135 — 31 — Gathering and transportation sales — — — 785 Gathering and transportation lease revenues — 9,294 — 12,606 Total segment revenues 2,516 9,294 7,452 13,391 Segment operating costs Lease operating expenses 1,483 357 1,858 51 Transportation operating expenses — 1,903 — 2,558 Production taxes 105 — 106 — Depreciation, depletion and amortization 317 5,144 772 5,143 Asset impairments — — 23,247 — Accretion expense 55 93 52 86 Total segment operating costs 1,960 7,497 26,035 7,838 Segment other income Earnings from equity investments — 599 — (1,202) Total segment other income — 599 — (1,202) Segment operating income $ 556 $ 2,396 $ (18,583) $ 4,351 Three Months Ended March 31, 2021 2020 Reconciliation of segment operating income (loss) to net loss Total midstream operating income $ 2,396 $ 4,351 Total production operating income (loss) 556 (18,583) Total segment operating income (loss) 2,952 (14,232) General and administrative expenses (6,933) (3,775) Unit-based compensation expense (337) (398) Interest expense, net (30,447) (23,009) Income tax expense (40) 73 Net loss $ (34,805) $ (41,341) The following table summarizes the total assets by operating segment as of March 31, 2021 and December 31, 2020 and total capital expenditures for the three months ended March 31, 2021 and the year ended December 31, 2020 (in thousands): March 31, 2021 Production Midstream Corporate (a) Total Other financial information Total assets $ 16,852 $ 327,645 $ 2,558 $ 347,055 Capital expenditures (b) $ — $ — $ — $ — December 31, 2020 Production Midstream Corporate (a) Total Other financial information Total assets $ 19,242 $ 331,926 $ 2,260 $ 353,428 Capital expenditures (b) $ (5) $ 1,943 $ — $ 1,938 (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	3 Months Ended
	Mar. 31, 2021
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 $87.7 million. As of March 31, 2021, the Partnership had invested approximately $124.2 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 March 31, 2021 and December 31, 2020 (in thousands): March 31, December 31, 2021 2020 Acquisitions, earnout and capital investments $ 128,251 $ 128,251 Earnings in equity investments 31,054 30,455 Distributions received (71,635) (69,071) Maximum exposure to loss $ 87,670 $ 89,635

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2021
Subsequent Events
Subsequent Events	18. SUBSEQUENT EVENTS Palmetto Divestiture On April 30, 2021, but effective March 1, 2021 (the “Palmetto Effective Time”), SEP Holdings IV, LLC (“SEP IV”), a wholly-owned subsidiary of the Partnership entered into a purchase agreement (the “Palmetto PSA”) with Westhoff Palmetto LP (“Palmetto Buyer”), pursuant to which SEP IV sold to Palmetto Buyer specified wellbores and other associated assets located in Gonzales and Dewitt Counties, Texas (the “Palmetto Assets”) for a base purchase price of approximately $11.5 million, which remains subject to customary post-closing adjustments (the “Palmetto Divestiture”). Pursuant to the Palmetto PSA, other than a limited amount of retained obligations, Palmetto Buyer has agreed to assume all obligations relating to the Palmetto Assets that arose on or after the Palmetto Effective Time. The Palmetto PSA contains customary representations and warranties by SEP IV and Palmetto Buyer, and SEP IV and Palmetto Buyer have agreed to customary indemnities relating to breaches of representations, warranties and covenants and the payment of assumed and excluded obligations. The transaction contemplated by the Palmetto PSA closed simultaneously with the execution of the Palmetto PSA. Maverick Divestiture On April 30, 2021, but effective March 1, 2021 (the “Maverick Effective Time”), SEP IV entered into a purchase agreement (the “Maverick PSA”) with Bayshore Energy TX LLC (“Maverick Buyer”), pursuant to which SEP IV sold to Maverick Buyer specified wellbores and other associated assets located in Zavala County, Texas (the “Maverick 1 Assets”) for a base purchase price of approximately $2.8 million, which remains subject to customary post-closing adjustments (the “Maverick 1 Divestiture”). Pursuant to the Maverick PSA, other than a limited amount of retained obligations, Maverick Buyer has agreed to assume all obligations relating to the Maverick 1 Assets that arose on or after the Maverick Effective Time. The Maverick PSA contains customary representations and warranties by SEP IV and Maverick Buyer, and SEP IV and Maverick Buyer have agreed to customary indemnities relating to breaches of representations, warranties and covenants and the payment of assumed and excluded obligations. The Maverick 1 Divestiture closed simultaneously with the execution of the Maverick PSA. Also on April 30, 2021, SEP IV entered into a letter agreement with Maverick Buyer pursuant to which SEP IV has agreed to sell additional other specified wellbores and other associated assets located in Zavala and Dimmit Counties, Texas (the “Maverick 2 Assets”) for a base purchase price of approximately $1.4 million, which will also be subject to customary post-closing adjustments (the “Maverick 2 Divestiture”). The closing of the Maverick 2 Divestiture is conditioned upon SEP IV obtaining certain consents and complying with other preferential rights related to the Maverick 2 Assets. Once the Partnership has satisfied such conditions, SEP IV and Maverick Buyer will enter in a purchase agreement with respect to the Maverick 2 Assets. The Maverick 2 Divestiture is expected to close in the second quarter of 2021. Stonepeak Letter Agreement Election On April 30, 2021, the Partnership received written notice of Stonepeak’s election to receive distributions on the Class C Preferred Units for the quarter ended March 31, 2021, in common units. In accordance with the Stonepeak Letter Agreement, the Partnership will issue 13,763,249 common units to Stonepeak on May 20, 2021. NYSE American Update On April 29, 2021, the Partnership received notice (the “2021 Notice”) from NYSE American LLC (“NYSE American”) that the Partnership was not in compliance with the continued listing standards set forth in Section 1003(a)(ii) of the NYSE American Company Guide (the “Company Guide”). Section 1003(a)(ii) applies if a listed company has stockholders’ equity of less than U.S. $4.0 million and has reported losses from continuing operations and/or net losses in three of its four most recent fiscal years. The Partnership can regain compliance under Section 1003(a)(ii) of the Company Guide, as well as under Section 1003(a)(i), as previously disclosed, under the compliance plan approved by the NYSE American on June 25, 2020, which granted the Partnership a plan period through October 3, 2021. The Partnership is not required to submit an additional plan to NYSE American with respect to Section 1003(a)(ii). Receipt of the 2021 Notice does not affect the Partnership’s business, operations, financial or liquidity condition, or reporting requirements with the SEC. Gas Lift Agreement On April 21, 2021, but effective January 1, 2021, Catarina Midstream, LLC, a wholly-owned subsidiary of the Partnership, entered into a Gas Lift Agreement (the “Gas Lift Agreement”) with SN Catarina, LLC, a subsidiary of Mesquite. Pursuant to the Gas Lift Agreement, (i) Catarina Midstream LLC will provide certain gas lift services ancillary to Mesquite’s oil and gas operations on the Piloncillo Ranch in South Texas, and (ii) Mesquite will pay a per-Mcf gas lift fee based on the volume of Catrina Midstream, LLC’s compressed gas delivered to Mesquite in connection with the provision of such gas lift services. The initial term of the Gas Lift Agreement is one year and it will continue on a year-to-year basis thereafter unless terminated by either party at least 60 days prior to the expiration of the initial term or any successive one-year term. Under the terms of the Gas Lift Agreement, each of the parties provided general representations and warranties and indemnification to the other party. ATM Program On April 20, 2021 the Partnership entered into an ATM Sales Agreement (the “Sales Agreement”) with Virtu Americas LLC (“Virtu”). Pursuant to the to the terms of the Sales Agreement, the Partnership may sell from time to time through Virtu, as the Partnership’s sales agent or principal, common units having an aggregate offering price of up to $7,000,000 (the “ATM Units”). Sales of the ATM Units can be made by any method permitted that is deemed an “at the market offering” as defined in Rule 415 under the Securities Act of 1933. The Partnership will use the net proceeds from any sales pursuant to the Sales Agreement, after deducting offering expenses and Virtu’s commissions, for general partnership purposes, which may include repaying or refinancing a portion of the Partnership’s outstanding indebtedness and funding capital expenditures or working capital. Amended and Restated Executive Services Agreement for Realignment On April 15, 2021, the Partnership and our general partner entered into that certain Amended and Restated Executive Services Agreement for Realignment (the “Amended Agreement”) with Gerald F. Willinger, a current member of the Board, and the Chief Executive Officer of our general partner. The Amended Agreement amends and restates that certain Executive Services Agreement, dated August 2, 2019, by and between Mr. Willinger, our general partner and the Partnership. The Amended Agreement is entered into in connection with the Partnership’s go-forward strategy to acquire, develop and own infrastructure critical to the transition of energy supply to lower carbon sources. Pursuant to the terms of the Amended Agreement, for a period from April 15, 2021 through December 31, 2021, Mr. Willinger will continue to serve in his role as Chief Executive Officer of the General Partner and will cooperate with the Board in connection with the Board’s realignment and transition of his roles and responsibilities to other members of the management team for our general partner and the Partnership. The Amended Agreement includes a customary general release of claims and certain covenants and agreements from Mr. Willinger related to confidential information, cooperation following termination or expiration of the Amended Agreement, non-solicitation of customers and non-competition.

Basis Of Presentation And Sum_2

Basis Of Presentation And Summary Of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2021
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”), the Carnero JV (as defined in Note 10 “Investments”) and Seco Pipeline (as defined in Note 4 “Fair Value Measurements”). 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, 2020, which was filed with the SEC on March 16, 2021.
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. 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.
Liquidity and Going Concern	Liquidity and Going Concern The Partnership’s inability to generate sufficient liquidity to meet future debt obligations raises substantial doubt regarding our ability to continue as a going concern. The Credit Agreement matures September 30, 2021 and our ability to continue as a going concern is contingent upon our ability to either (i) refinance or extend the maturity of the Credit Agreement, or (ii) obtain adequate new debt or equity financing to repay the Credit Agreement in full at maturity. We intend to refinance or extend the maturity of the Credit Agreement prior to its maturity date. However, we may not be able to refinance or extend the maturity of the Credit Agreement or, if we are able to refinance or extend the maturity, we may not be able to do so with borrowing and debt issue costs, terms, covenants, restrictions, commitment amount or a borrowing base favorable to us. The consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The consolidated financial statements do not include any adjustments that might result from the outcome of substantial doubt as to the Partnership’s ability to continue as a going concern. If the Partnership cannot continue as a going concern, adjustments to the carrying values and classification of its assets and liabilities and the reported amounts of income and expenses could be required and could be material.
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)	3 Months Ended
	Mar. 31, 2021
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 March 31, 2021 (in thousands): Fair Value Measurements at March 31, 2021 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Other liabilities Warrant $ — $ (6,210) $ — $ (6,210) Total $ — $ (6,210) $ — $ (6,210) 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, 2020 (in thousands): Fair Value Measurements at December 31, 2020 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Other liabilities Warrant — (1,418) — (1,418) Total $ — $ (1,418) $ — $ (1,418)
Schedule of non-recurring fair value measurements	The following table summarizes the non-recurring fair value measurements of our production assets as of December 31, 2020 (in thousands): Fair Value Measurements at December 31, 2020 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Impairment (a) $ — $ — $ 12,884 Total net assets $ — $ — $ 12,884 During the year ended December 31, 2020, we recorded a non-cash impairment charge of $23.4 million to impair our producing oil and natural gas properties and $0.9 million to impair the Seco Pipeline. 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.

Derivative And Financial Inst_2

Derivative And Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2021
Derivative And Financial Instruments
Schedule Of Effect Of Derivative Instruments On Consolidated Statements Of Operations	Year Ended December 31, 2020 Beginning fair value of commodity derivatives $ (759) Net gains (losses) on crude oil derivatives 3,814 Net gains on natural gas derivatives 87 Net settlements received on derivative contracts: Oil (2,829) Natural gas (313) Ending fair value of commodity derivatives $ — The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands): Location of Gain (Loss) Three Months Ended March 31, Derivative Type in Income 2020 Commodity – Mark-to-Market Oil sales $ 4,826 Commodity – Mark-to-Market Natural gas sales 122 $ 4,948

Oil And Natural Gas Propertie_2

Oil And Natural Gas Properties And Related Equipment (Tables)	3 Months Ended
	Mar. 31, 2021
Oil And Natural Gas Properties And Related Equipment.
Schedule of gathering and transportation assets	Gathering and transportation assets consisted of the following (in thousands): March 31, December 31, 2021 2020 Gathering and transportation assets Midstream assets $ 187,977 $ 187,977 Less: Accumulated depreciation, amortization and impairment (84,491) (82,710) Total gathering and transportation assets, net $ 103,486 $ 105,267
Schedule of oil and natural gas properties	March 31, December 31, 2021 2020 Gathering and transportation assets Midstream assets $ 187,977 $ 187,977 Less: Accumulated depreciation, amortization and impairment (84,491) (82,710) Total gathering and transportation assets, net $ 103,486 $ 105,267 Oil and natural gas properties and related equipment consisted of the following (in thousands): March 31, December 31, 2021 2020 Oil and natural gas properties and related equipment Proved property $ 112,471 $ 112,471 Less: Accumulated depreciation, depletion, amortization and impairments (95,158) (94,843) Total oil and natural gas properties and equipment, net $ 17,313 $ 17,628
Schedule of depreciation, depletion, and amortization	Depreciation, depletion and amortization consisted of the following (in thousands): Three Months Ended March 31, 2021 2020 Depreciation, depletion and amortization of oil and natural gas-related assets $ 317 $ 772 Depreciation and amortization of gathering and transportation related assets 1,781 1,779 Amortization of intangible assets 3,363 3,364 Total depreciation, depletion and amortization $ 5,461 $ 5,915

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	3 Months Ended
	Mar. 31, 2021
Asset Retirement Obligation
Reconciliation of changes in asset retirement obligation	The following table is a reconciliation of changes in ARO for the three months ended March 31, 2021 and the year ended December 31, 2020 (in thousands): Three Months Ended Year Ended March 31, 2021 December 31, 2020 Asset retirement obligation, beginning balance $ 7,465 $ 6,898 Accretion expense 148 567 Asset retirement obligation, ending balance $ 7,613 $ 7,465

Intangible Assets (Tables)

Intangible Assets (Tables)	3 Months Ended
	Mar. 31, 2021
Intangible Assets
Schedule of Intangible assets	The following table is a reconciliation of changes in intangible assets (in thousands): March 31, December 31, 2021 2020 Beginning balance $ 131,786 $ 145,246 Amortization (3,363) (13,460) Ending balance $ 128,423 $ 131,786

Investments (Tables)

Investments (Tables)	3 Months Ended
	Mar. 31, 2021
Investments
Summarized financial information of unconsolidated entities	Summarized financial information of unconsolidated entities is as follows (in thousands): Three Months Ended March 31, 2021 2020 Sales $ 22,829 $ 14,252 Total expenses 19,578 14,606 Net income $ 3,251 $ (354)

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2021
Unit-Based Compensation
Schedule of units activity	Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2020 683,171 $ 2.68 Granted 1,651,785 1.12 Returned/Cancelled (140,647) 2.37 Outstanding at March 31, 2021 2,194,309 $

Distributions To Unitholders (T

Distributions To Unitholders (Tables)	3 Months Ended
	Mar. 31, 2021
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)	3 Months Ended
	Mar. 31, 2021
Partners' Capital
Schedule of Class C preferred units	The Class C Preferred Units are accounted for as a liability on our condensed consolidated balance sheet consisting of the following (in thousands): March 31, December 31, 2021 2020 Class C Preferred Units, beginning balance $ 345,205 $ 281,688 Accretion of discount 11,650 38,938 Distribution accrual — 24,579 Class C Preferred Units, ending balance $ 356,855 $ 345,205

Reporting Segments (Tables)

Reporting Segments (Tables)	3 Months Ended
	Mar. 31, 2021
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 March 31, 2021 2020 Production Midstream Production Midstream Segment revenues Natural gas sales $ 75 $ — $ 234 $ — Oil sales 2,306 — 7,187 — Natural gas liquid sales 135 — 31 — Gathering and transportation sales — — — 785 Gathering and transportation lease revenues — 9,294 — 12,606 Total segment revenues 2,516 9,294 7,452 13,391 Segment operating costs Lease operating expenses 1,483 357 1,858 51 Transportation operating expenses — 1,903 — 2,558 Production taxes 105 — 106 — Depreciation, depletion and amortization 317 5,144 772 5,143 Asset impairments — — 23,247 — Accretion expense 55 93 52 86 Total segment operating costs 1,960 7,497 26,035 7,838 Segment other income Earnings from equity investments — 599 — (1,202) Total segment other income — 599 — (1,202) Segment operating income $ 556 $ 2,396 $ (18,583) $ 4,351
Schedule of reconciliation of segment operating income to net loss	Three Months Ended March 31, 2021 2020 Reconciliation of segment operating income (loss) to net loss Total midstream operating income $ 2,396 $ 4,351 Total production operating income (loss) 556 (18,583) Total segment operating income (loss) 2,952 (14,232) General and administrative expenses (6,933) (3,775) Unit-based compensation expense (337) (398) Interest expense, net (30,447) (23,009) Income tax expense (40) 73 Net loss $ (34,805) $ (41,341)
Summary of assets and capital expenditures by operating segment	Three Months Ended March 31, 2021 2020 Reconciliation of segment operating income (loss) to net loss Total midstream operating income $ 2,396 $ 4,351 Total production operating income (loss) 556 (18,583) Total segment operating income (loss) 2,952 (14,232) General and administrative expenses (6,933) (3,775) Unit-based compensation expense (337) (398) Interest expense, net (30,447) (23,009) Income tax expense (40) 73 Net loss $ (34,805) $ (41,341) The following table summarizes the total assets by operating segment as of March 31, 2021 and December 31, 2020 and total capital expenditures for the three months ended March 31, 2021 and the year ended December 31, 2020 (in thousands): March 31, 2021 Production Midstream Corporate (a) Total Other financial information Total assets $ 16,852 $ 327,645 $ 2,558 $ 347,055 Capital expenditures (b) $ — $ — $ — $ — December 31, 2020 Production Midstream Corporate (a) Total Other financial information Total assets $ 19,242 $ 331,926 $ 2,260 $ 353,428 Capital expenditures (b) $ (5) $ 1,943 $ — $ 1,938 (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)	3 Months Ended
	Mar. 31, 2021
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 March 31, 2021 and December 31, 2020 (in thousands): March 31, December 31, 2021 2020 Acquisitions, earnout and capital investments $ 128,251 $ 128,251 Earnings in equity investments 31,054 30,455 Distributions received (71,635) (69,071) Maximum exposure to loss $ 87,670 $ 89,635

Basis Of Presentation And Sum_3

Basis Of Presentation And Summary Of Significant Accounting Policies (Details)	3 Months Ended
	Mar. 31, 2021segment
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
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Revenue Recognition
Revenues	$ 11,810	$ 20,843
Payment term (in days)	30 days
Receivables	$ 1,900		$ 1,900

Fair Value Measurements (Recurr

Fair Value Measurements (Recurring) (Details) - Recurring - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Other liabilities: Warrant	$ (6,210)	$ (1,418)
Total	(6,210)	(1,418)
Fair Value, Inputs, Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Other liabilities: Warrant	(6,210)	(1,418)
Total	$ (6,210)	$ (1,418)

Fair Value Measurements (Non-Re

Fair Value Measurements (Non-Recurring) (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2021miMMcf	Dec. 31, 2020USD ($)
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]
Asset impairments		$ 23,400
Seco Pipeline, LLC
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Number of miles of natural gas pipeline | mi	30
Daily pipeline capacity (MMcf/d) | MMcf	400
Seco Pipeline, LLC | Nonrecurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Asset impairments		900
Fair Value, Inputs, Level 3 | Nonrecurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment		12,884
Fair value		12,884
Fair Value, Inputs, Level 3 | Seco Pipeline, LLC | Nonrecurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair value		0
Asset impairments		$ 900

Derivative And Financial Inst_3

Derivative And Financial Instruments (Changes In Fair Value) (Details) - Commodity Contract - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2020
Derivative Instruments Gain Loss [Line Items]
Beginning fair value of commodity derivatives	$ (759)	$ (759)
Net gain (loss) on derivatives	4,948
Oil reserves
Derivative Instruments Gain Loss [Line Items]
Net gain (loss) on derivatives	4,826	3,814
Net settlements received on derivative contracts		(2,829)
Natural gas
Derivative Instruments Gain Loss [Line Items]
Net gain (loss) on derivatives	$ 122	87
Net settlements received on derivative contracts		$ (313)

Derivative And Financial Inst_4

Derivative And Financial Instruments (Effect On Statement Of Operations) (Details) - Commodity Contract - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2020
Embedded Derivative [Line Items]
Net gain (loss) on derivatives	$ 4,948
Oil reserves
Embedded Derivative [Line Items]
Net gain (loss) on derivatives	4,826	$ 3,814
Natural gas
Embedded Derivative [Line Items]
Net gain (loss) on derivatives	$ 122	$ 87

Debt (Details)

Debt (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2021USD ($)	Mar. 31, 2020USD ($)	Dec. 31, 2020USD ($)	Nov. 05, 2020USD ($)	Nov. 22, 2019USD ($)
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 15,000			$ 17,500
Credit agreement available	5,500
Letters of credit outstanding	0
Credit agreement, outstanding	104,500
Amortization of debt issuance costs	209	$ 181
Unamortized debt issue costs	600		$ 800
Credit Agreement
Line of Credit Facility [Line Items]
Maximum borrowing capacity	113,700		$ 155,000		$ 235,500
Quarterly principal and other mandatory prepayments	$ 10,000
Commitment fee on unutilized borrowing base	0.50%
Credit agreement, outstanding	$ 95,000
Current assets to current liabilities ratio	1
Debt to Adjusted EBITDA ratio	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	15,000				$ 17,500
Credit agreement, outstanding	9,500
Letter of Credit
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 2,500
Minimum | Credit Agreement
Line of Credit Facility [Line Items]
Ownership percentage by subsidiary	50
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

Oil And Natural Gas Propertie_3

Oil And Natural Gas Properties And Related Equipment (Gathering and Transportation Assets) (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Midstream assets	$ 187,977	$ 187,977
Less: Accumulated depreciation, amortization and impairment	(95,158)	(94,843)
Midstream
Property, Plant and Equipment [Line Items]
Midstream assets	187,977	187,977
Less: Accumulated depreciation, amortization and impairment	(84,491)	(82,710)
Total gathering and transportation assets, net	$ 103,486	$ 105,267

Oil And Natural Gas Propertie_4

Oil And Natural Gas Properties And Related Equipment (Properties) (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Oil And Natural Gas Properties And Related Equipment.
Proved property	$ 112,471	$ 112,471
Less: Accumulated depreciation, depletion, amortization and impairments	(95,158)	(94,843)
Total oil and natural gas properties and equipment, net	$ 17,313	$ 17,628

Oil And Natural Gas Propertie_5

Oil And Natural Gas Properties And Related Equipment (DDA and Impairments) (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Amortization of intangible assets	$ 3,363	$ 3,364
Depreciation, depletion and amortization	$ 2,098	2,551
Asset impairments		23,247
Gathering Facilities | Maximum
Property, Plant and Equipment [Line Items]
Useful lives	36 years
Transportation assets | Maximum
Property, Plant and Equipment [Line Items]
Useful lives	40 years
Oil and Natural Gas-Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	$ 317	772
Gathering and Transportation Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	$ 1,781	1,779
Gathering and Transportation Related Assets | Minimum
Property, Plant and Equipment [Line Items]
Useful lives	3 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	$ 5,461	$ 5,915
Seco Pipeline, LLC
Property, Plant and Equipment [Line Items]
Non-cash impairment charges			$ 23,400

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Asset Retirement Obligation
Asset retirement obligation, beginning balance	$ 7,465	$ 6,898	$ 6,898
Accretion expense	148	$ 138	567
Asset retirement obligation, ending balance	7,613		7,465
Legally restricted assets	$ 0		$ 0

Intangible Assets (Details)

Intangible Assets (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 3,363	$ 3,364
Beginning balance	131,786	145,246	$ 145,246
Amortization	(3,363)	$ 3,400	(13,460)
Ending balance	$ 128,423		$ 131,786
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
	Nov. 30, 2016USD ($)	Jul. 31, 2016USD ($)	Mar. 31, 2021USD ($)	Mar. 31, 2020USD ($)	May 31, 2018a
Schedule of Equity Method Investments [Line Items]
Earnings (loss) from equity investments			$ 599	$ (1,202)
Amortization of intangible assets			3,363	3,364
Distributions received			2,564	$ 1,615
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	124,200
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			124,200
Earnings (loss) from equity investments			(900)
Distributions received			2,600
Carnero G&P, Joint Venture | Customer Relationships
Schedule of Equity Method Investments [Line Items]
Amortization of intangible assets			$ 300
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	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Investments
Sales	$ 22,829	$ 14,252
Total expenses	19,578	14,606
Net income	$ 3,251	$ (354)

Commitments And Contingencies (

Commitments And Contingencies (Details)	3 Months Ended
	Mar. 31, 2021USD ($)
Carnero Gathering, Joint Venture
Variable Interest Entity [Line Items]
Earnout derivative liability	$ 0
Mesquite Energy, Inc.
Variable Interest Entity [Line Items]
Earnout payments	$ 0

Unit-Based Compensation (Detail

Unit-Based Compensation (Details) - LTIP - $ / shares	1 Months Ended		3 Months Ended
	Apr. 30, 2019	Mar. 31, 2019	Mar. 31, 2021
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units available for issuance			1,577,847
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding			683,171
Number of Restricted Units, Granted			1,651,785
Number of Restricted Units, Returned/Cancelled			(140,647)
Number of Restricted Units, Outstanding			2,194,309
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding			$ 2.68
Weighted Averaged Grant Date Fair Value Per Unit, Granted			1.12
Weighted Averaged Grant Date Fair Value Per Unit, Returned/Cancelled			2.37
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding			$ 1.53
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	May 20, 2021	Feb. 25, 2021	Feb. 01, 2021	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019
Forecast
Units distribution (in units)	13,763,249
Common units
Units distribution (in units)		12,445,491	22,274,869
Common units | Subsequent event
Units distribution (in units)	13,763,249
Class C preferred units
LLC Units distributed				1,105,286	1,071,793	1,039,314	1,007,820	939,327

Partners' Capital (Details)

Partners' Capital (Details) - USD ($)	3 Months Ended
	Mar. 31, 2021	Dec. 31, 2020
Limited Partners' Capital Account [Line Items]
Common units, outstanding	56,185,378	19,953,880
Units, issued	56,185,378	19,953,880
Class C preferred units
Limited Partners' Capital Account [Line Items]
Class B preferred units, outstanding	36,474,436
Class C preferred units | Settlement Agreement with Stonepeak Catarina Holdings LLC
Limited Partners' Capital Account [Line Items]
Units to be issued under agreement	$ 15,294,741
Common units
Limited Partners' Capital Account [Line Items]
Common units, outstanding	56,185,378
Unvested restricted common units | LTIP
Limited Partners' Capital Account [Line Items]
Common units, outstanding	2,194,309

Partners' Capital (Preferred Un

Partners' Capital (Preferred Units) (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Class C Preferred Units, beginning balance	$ 345,205	$ 281,688	$ 281,688
Accretion of discount	11,650		38,938
Distribution accrual			24,579
Class C Preferred Units, ending balance	$ 356,855		$ 345,205
Class C preferred units
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		12 Months Ended
	Mar. 31, 2021	Mar. 31, 2020	Dec. 31, 2020
Segment operating revenues:
Gathering and transportation lease revenues	$ 9,294	$ 12,606
Total revenues	11,810	20,843
Segment operating costs:
Lease operating expenses	1,840	1,909
Transportation operating expenses	1,903	2,558
Production taxes	105	106
Depreciation, depletion and amortization	5,461	5,915
Asset impairments		23,247
Accretion expense	148	138	$ 567
Total operating expenses	16,727	38,046
Segment other income
Earnings (loss) from equity investments	599	(1,202)
Segment operating income (loss)	2,952	(14,232)
Midstream
Segment operating revenues:
Gathering and transportation lease revenues	9,294	12,606
Total revenues	9,294	13,391
Segment operating costs:
Lease operating expenses	1,903	2,558
Transportation operating expenses	357	51
Depreciation, depletion and amortization	5,144	5,143
Accretion expense	93	86
Total operating expenses	7,497	7,838
Segment other income
Earnings (loss) from equity investments	599	(1,202)
Total segment other income	599	(1,202)
Segment operating income (loss)	2,396	4,351
Production
Segment operating revenues:
Total revenues	2,516	7,452
Segment operating costs:
Transportation operating expenses	1,483	1,858
Production taxes	105	106
Depreciation, depletion and amortization	317	772
Asset impairments		23,247
Accretion expense	55	52
Total operating expenses	1,960	26,035
Segment other income
Segment operating income (loss)	556	(18,583)
Natural gas sales
Segment operating revenues:
Revenues	75	234
Natural gas sales | Production
Segment operating revenues:
Revenues	75	234
Oil sales
Segment operating revenues:
Revenues	2,306	7,187
Oil sales | Production
Segment operating revenues:
Revenues	2,306	7,187
Natural gas liquid sales
Segment operating revenues:
Revenues	135	31
Natural gas liquid sales | Production
Segment operating revenues:
Revenues	$ 135	31
Gathering and transportation sales
Segment operating revenues:
Revenues		785
Gathering and transportation sales | Midstream
Segment operating revenues:
Revenues		$ 785

Reporting Segments - Reconcilia

Reporting Segments - Reconciliation of Segment Operating Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Reconciliation of segment operating income (loss) to net loss
Segment operating income (loss)	$ 2,952	$ (14,232)
General and administrative expenses	(6,933)	(3,775)
Unit-based compensation expense	(337)	(398)
Interest expense, net	(30,447)	(23,009)
Income tax expense	(40)	73
Net loss	(34,805)	(41,341)
Midstream
Reconciliation of segment operating income (loss) to net loss
Segment operating income (loss)	2,396	4,351
Production
Reconciliation of segment operating income (loss) to net loss
Segment operating income (loss)	$ 556	$ (18,583)

Reporting Segments (Assets by S

Reporting Segments (Assets by Segment) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Mar. 31, 2021
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 353,428	$ 347,055
Capital expenditures	1,938
Production
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	19,242	16,852
Capital expenditures	(5)
Midstream
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	331,926	327,645
Capital expenditures	1,943
Corporate
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 2,260	$ 2,558

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	Jul. 31, 2016	Mar. 31, 2021	Dec. 31, 2020
Variable Interest Entity [Line Items]
Acquisitions, earnout and capital investments		$ 128,251	$ 128,251
Earnings in equity investments		31,054	30,455
Distributions received		(71,635)	(69,071)
Maximum exposure to loss		87,670	$ 89,635
Carnero Gathering, Joint Venture
Variable Interest Entity [Line Items]
Payments to acquire interest in joint venture	$ 37,000	124,200
Debt incurred		$ 0

Subsequents Events (Details)

Subsequents Events (Details) - USD ($)	May 20, 2021	Apr. 30, 2021	Apr. 21, 2021	Apr. 20, 2021	Feb. 25, 2021	Feb. 01, 2021
Common units
Subsequent Event [Line Items]
Units distribution (in units)					12,445,491	22,274,869
Forecast
Subsequent Event [Line Items]
Units distribution (in units)	13,763,249
Subsequent event | ATM Sales Agreement
Subsequent Event [Line Items]
Aggregate offering price				$ 7,000,000
Subsequent event | Gas Lift Agreement
Subsequent Event [Line Items]
Agreement Term			1 year
Agreement notice of termination period			60 days
Agreement renewal term			1 year
Subsequent event | Common units
Subsequent Event [Line Items]
Units distribution (in units)	13,763,249
Subsequent event | Divestiture of (The "Palmetto Assets")
Subsequent Event [Line Items]
Proceeds from divestiture		$ 11,500,000
Subsequent event | Divestiture of (The "Maverick 1 Assets")
Subsequent Event [Line Items]
Proceeds from divestiture		2,800,000
Subsequent event | Divestiture of (The "Maverick 2 Assets")
Subsequent Event [Line Items]
Proceeds from divestiture		$ 1,400,000