Evolve Transition Infrastructure (SNMP) 10-K 16 Mar 21 2020 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2020	Mar. 15, 2021	Jun. 30, 2020
Document And Entity Information
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2020
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
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
ICFR Auditor Attestation Flag	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		54,533,593
Entity Public Float			$ 4,070,736
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Voluntary Filers	No

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenues
Gathering and transportation lease revenues	$ 44,671	$ 59,090
Total revenues	56,993	76,649
Operating expenses
Lease operating expenses	6,224	7,378
Transportation operating expenses	9,314	11,553
Production taxes	311	621
General and administrative expenses	18,296	17,610
Unit-based compensation expense	2,602	1,351
Depreciation, depletion and amortization	22,873	25,333
Asset impairments	24,222	32,119
Accretion expense	567	526
Total operating expenses	84,409	96,491
Other (income) expense
Interest expense, net	95,871	39,789
Earnings from equity investments	(4,479)	(2,831)
Other income	(71)	(5,860)
Total other expenses	91,321	31,098
Total expenses	175,730	127,589
Loss before income taxes	(118,737)	(50,940)
Income tax expense	24	202
Net loss	(118,761)	(51,142)
Preferred unit paid-in-kind distributions		(14,409)
Preferred unit distributions		(8,838)
Preferred unit amortization		(1,708)
Deemed distribution		103,773
Net income (loss) attributable to common unitholders - Basic	(118,761)	27,676
Mark-to-market on warrant		(3,244)
Net income (loss) attributable to common unitholders - Diluted	$ (118,761)	$ 24,432
Net income (loss) per unit
Common units - Basic (in dollars per share)	$ (5.94)	$ 1.46
Common units - Diluted (in dollars per share)	$ (5.94)	$ 1.23
Common units - Basic	19,978,633	18,939,145
Common units - Diluted	19,978,633	19,810,679
Natural gas sales
Revenues
Revenues	$ 427	$ 683
Oil sales
Revenues
Revenues	10,856	9,512
Natural gas liquid sales
Revenues
Revenues	254	539
Gathering and transportation sales
Revenues
Revenues	$ 785	$ 6,825

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current assets
Cash and cash equivalents	$ 1,718	$ 5,099
Accounts receivable	6,670	133
Accounts receivable - related entities		6,719
Prepaid expenses	595	1,193
Fair value of commodity derivative instruments		226
Total current assets	8,983	13,370
Oil and natural gas properties and related equipment
Oil and natural gas properties, equipment and facilities (successful efforts method)	112,471	112,476
Gathering and transportation assets	187,977	186,941
Less: accumulated depreciation, depletion, amortization and impairment	(177,553)	(144,189)
Oil and natural gas properties and equipment, net	122,895	155,228
Other assets
Intangible assets, net	131,786	145,246
Equity investments	89,635	100,311
Other non-current assets	129	285
Total assets	353,428	414,440
Current liabilities
Accounts payable and accrued liabilities	4,420	5,347
Accounts payable and accrued liabilities - related entities	25,737	631
Royalties payable	359	359
Short-term debt, net of debt issuance costs	110,233	39,374
Class C preferred units	345,205
Fair value of commodity derivative instruments		985
Total current liabilities	485,954	46,696
Other liabilities
Long term accrued liabilities - related entities	12,137	4,892
Asset retirement obligation	7,465	6,898
Long-term debt, net of debt issuance costs		109,437
Class C preferred units		281,688
Other liabilities	1,416	629
Total other liabilities	21,018	403,544
Total liabilities	506,972	450,240
Commitments and contingencies (See Note 12)
Partners' deficit
Common units, 19,953,880 and 20,087,462 units issued and outstanding as of December 31, 2020 and 2019, respectively	(153,544)	(35,800)
Total partners' deficit	(153,544)	(35,800)
Total liabilities and partners' capital	$ 353,428	$ 414,440

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - shares	Dec. 31, 2020	Dec. 31, 2019
Consolidated Balance Sheets
Units, issued	19,953,880	20,087,462
Units, outstanding	19,953,880	20,087,462

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Cash flows from operating activities:
Net loss	$ (118,761)	$ (51,142)
Adjustments to reconcile net loss to cash provided by operating activities:
Depreciation, depletion and amortization	9,413	11,873
Amortization of debt issuance costs	767	1,266
Accretion of Class C discount	38,938	13,129
Class C distribution accrual	50,317	19,309
Asset impairments	24,222	32,119
Accretion expense	567	526
Distributions from equity investments	15,266	17,227
Equity earnings in affiliate	(4,479)	(2,831)
Mark-to-market on Warrant	787	(3,244)
Net (gain) loss on commodity derivative contracts	(3,901)	3,772
Net cash settlements received on commodity derivative contracts	3,054	1,101
Unit-based compensation	2,602	1,351
Gain on earnout derivative		(5,856)
Amortization of intangible assets	13,460	13,460
Changes in Operating Assets and Liabilities:
Accounts receivable	(6,499)	(6)
Accounts receivable - related entities	6,719	(23)
Prepaid expenses	598	(262)
Other assets	(115)	83
Accounts payable and accrued liabilities	(27,363)	6,378
Accounts payable and accrued liabilities- related entities	32,351	(122)
Other long-term liabilities		(123)
Net cash provided by operating activities	37,943	57,985
Cash flows from investing activities:
Development of oil and natural gas properties	5
Development of oil and natural gas properties		(131)
Construction of gathering and transportation assets	(1,832)	(1,063)
Contributions to equity affiliates	(111)	(242)
Net cash used in investing activities	(1,938)	(1,436)
Cash flows from financing activities:
Payments for Class C Preferred Unit Exchange		(238)
Proceeds from issuance of debt	13,000	4,000
Repayment of debt	(52,000)	(34,000)
Distributions to common unitholders		(5,216)
Class B preferred unit cash distributions		(17,675)
Units tendered by SOG employees for tax withholdings	(41)	(218)
Debt issuance costs	(345)	(1,037)
Net cash used in financing activities	(39,386)	(54,384)
Net decrease in cash and cash equivalents	(3,381)	2,165
Cash and cash equivalents, beginning of period	5,099	2,934
Cash and cash equivalents, end of period	1,718	5,099
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	796	528
Cash paid during the period for income taxes	242	138
Cash paid during the period for interest	$ 5,235	$ 9,159

Consolidated Statements of Chan

Consolidated Statements of Changes in Partners’ Capital - USD ($) $ in Thousands	Common units	Total
Adoption of accounting standards	$ (181)	$ (181)
Partner's Deficit at Dec. 31, 2018	$ (64,620)	(64,620)
Partner's Deficit (in shares) at Dec. 31, 2018	16,486,239
Preferred unit exchange	$ 103,773	103,773
Unit-based compensation programs	$ 1,531	1,531
Unit-based compensation programs (in shares)	1,109,880
Units tendered by SOG employees for tax withholding	$ (218)	(218)
Units tendered by SOG employees for tax withholding (in shares)	(85,417)
Common units issued for asset management fee	$ 5,228	5,228
Common units issued for asset management fee (in shares)	2,576,760
Cash distributions to common unit holders	$ (5,216)	(5,216)
Distributions - Class B Preferred Units	(24,955)	(24,955)
Net loss	(51,142)	(51,142)
Partner's Deficit at Dec. 31, 2019	$ (35,800)	(35,800)
Partner's Deficit (in shares) at Dec. 31, 2019	20,087,462
Unit-based compensation programs	$ 1,058	1,058
Unit-based compensation programs (in shares)	(24,896)
Units tendered by SOG employees for tax withholding	$ (41)	(41)
Units tendered by SOG employees for tax withholding (in shares)	(108,686)
Net loss	$ (118,761)	(118,761)
Partner's Deficit at Dec. 31, 2020	$ (153,544)	$ (153,544)
Partner's Deficit (in shares) at Dec. 31, 2020	19,953,880

Organization And Business

Organization And Business	12 Months Ended
	Dec. 31, 2020
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	12 Months Ended
	Dec. 31, 2020
Basis Of Presentation And Summary Of Significant Accounting Policies
Basis of Presentation and Significant Accounting Policies	2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation Accounting policies used by us conform to accounting principles generally accepted in the United States of America (“GAAP). The accompanying financial statements include the accounts of us and our wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. Our business consists of two reportable segments: Production and Midstream. Midstream includes Western Catarina Midstream, the Carnero JV and Seco Pipeline. Production consists of our oil and natural gas properties in Texas and Louisiana. Our management evaluates performance based on these two business segments. Recent Accounting Pronouncements From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our consolidated financial statements upon adoption. In January 2020, the FASB issued Accounting Standards Update (“ASU”) 2020-01 “Investments – Equity Securities (Topic 321), Investments – Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815),” which clarifies the interaction among the accounting standards for equity securities, equity method investments and certain derivatives. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2020. We are currently in the process of evaluating the impact of adoption of this guidance on our condensed consolidated financial statements. In August 2018, the FASB issued ASU 2018-13 “Fair Value Measurement (ASC 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements,” which modifies the disclosure requirements on fair value measurements. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2019. The adoption of this standard did not have a material impact on our 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 consolidated financial statements. 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 consolidated financial statements are prepared in conformity with GAAP, which requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and the underlying assumptions affect the amounts of assets and liabilities reported, disclosures about contingent assets and liabilities and reported amounts of revenues and expenses. The estimates that are particularly significant to our financial statements include our ability to continue as a going concern; our reserves of natural gas, NGLs and oil; future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of derivatives; and fair values of assets and liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best judgment using the data available. Management evaluates its estimates and assumptions on an on-going basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from the estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods. Revenue Recognition Midstream We account for revenue from contracts with customers in accordance with ASC 606 and ASC 842 for our midstream segment. The Seco Pipeline Transportation Agreement is our only contract that we account for using ASC 606. Under the Seco Pipeline Transportation Agreement, we agreed to provide transportation services of certain quantities of natural gas from the receipt point to the delivery point. Each MMBtu of natural gas transported is distinct and the transportation services performed on each distinct molecule of product is substantially the same in nature. As such, we applied the series guidance and treat these services as a single performance obligation satisfied over time using volumes delivered as the measure of progress. Additionally, Seco Pipeline Transportation Agreement contains variable consideration in the form of volume variability. As the distinct goods or services (rather than the series) are considered for the purpose of allocating variable consideration, we have taken the optional exception under ASC 606. Under this exception, revenue is alternatively recognized in the period that control is transferred to the customer and the respective variable component of the total transaction price is resolved. In October 2015, we acquired (the “Catarina Transaction”) a gathering system from Mesquite (“Western Catarina Midstream”), which is located on the western portion of Mesquite’s acreage position in Dimmit, La Salle and Webb counties in Texas. In conjunction with the Catarina Transaction, we entered into a 15-year firm gas gathering and processing agreement with Mesquite, pursuant to which Mesquite agreed to tender all of its crude oil, natural gas and other hydrocarbon-based product volumes on approximately 35,000 dedicated acres for processing and transportation through Western Catarina Midstream, with the potential to tender additional volumes outside of the dedicated acreage (the “Gathering Agreement”). The Gathering Agreement was classified as an operating lease at inception and is accounted for under ASC 842, as Mesquite controls the physical use of the property under the lease. Revenues relating to the Gathering Agreement is recognized in the period service is provided. Under this arrangement, the Partnership receives a fee or fees for services provided. The revenue the Partnership recognizes from gathering and transportation services is generally directly related to the volume of oil and natural gas that flows through its systems. Production Our oil, natural gas, and NGL revenue is marketed and sold on our behalf by the respective asset operators. We are not party to the contracts with the third-party customers. However, we are party to joint operating agreements, which we account for under ASC 808, and revenues and expenses for these arrangements is recognized based on the information provided to us by the operators. We additionally recognize and present changes in the fair value of our commodity derivative instruments within natural gas sales and oil sales in the consolidated statements of operations, which is accounted for under ASC 815, “Derivatives and Hedging”. Accounts Receivable, Net Our accounts receivable are primarily from our contractual agreements with Mesquite and its subsidiaries, operators of our oil and natural gas properties and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted. Our allowance for doubtful accounts was $0.4 million as of December 31, 2020 and 2019. Concentration of Credit Risk and Accounts Receivable Financial instruments that potentially subject us to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and derivative financial instruments. We place our cash with high credit quality financial institutions. We place our derivative financial instruments with financial institutions that participate in our Credit Agreement and maintain an investment grade credit rating. Substantially all of our accounts receivable are due from operators of our oil and natural gas properties. These sales are generally unsecured and, in some cases, may carry a parent guarantee. We routinely assess the financial strength of our customers. Bad debt expense is recognized on an account-by-account review and when recovery is not probable. We have no off-balance-sheet credit exposure related to our operations or customers. Mesquite accounted for 80% and 86% of total revenue for the years ended December 31, 2020 and 2019, respectively. We are highly dependent upon Mesquite as our most significant customer, and we expect to derive a substantial portion of our revenue from Mesquite in the foreseeable future. Accordingly, we are indirectly subject to the business risks of Mesquite. Income Taxes The Partnership and each of its wholly-owned subsidiary LLCs are treated as a partnership for federal and state income tax purposes. All of our taxable income or loss, which may differ considerably from net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our members. As such, no federal income tax for these entities has been provided for in the accompanying financial statements. Earnings per Unit Net income (loss) per common unit for the period is based on any distributions that are made to the unitholders (common units) plus an allocation of undistributed net income (loss) based on provisions of the Amended Partnership Agreement, divided by the weighted average number of common units outstanding. The two-class method dictates that net income (loss) for a period be reduced by the amount of distributions and that any residual amount representing undistributed net income (loss) be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income (loss) as if all of the income for the period had been distributed in accordance with the Amended Partnership Agreement. Unit-based awards granted but unvested are eligible to receive distributions. The underlying unvested restricted unit awards are considered participating securities for purposes of determining net income (loss) per unit. Undistributed income is allocated to participating securities based on the proportional relationship of the weighted average number of common units and unit-based awards outstanding. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units based on provisions of the Amended Partnership Agreement. Undistributed losses are not allocated to unvested restricted unit awards as they do not participate in net losses. Distributions declared and paid in the period are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings. Asset Retirement Obligations Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, asset life, inflation and the credit-adjusted risk-free rate. The inputs are calculated based on historical data as well as current estimates. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset and is included in accretion expense in the our consolidated statements of operations. To estimate the fair value of an asset retirement obligation, the Partnership employs a present value technique, which reflects certain assumptions, including its credit‑adjusted risk‑free interest rate, inflation rate, the estimated settlement date of the liability and the estimated current cost to settle the liability. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability. Oil and Natural Gas Properties We follow the successful efforts method of accounting for our oil and natural gas production activities. Under this method of accounting, costs relating to leasehold acquisition, property acquisition and the development of proved areas are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred. Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (including wells and related equipment and facilities) are amortized on the basis of proved developed reserves. As more fully described in Note 7 “Oil and Natural Gas Properties and Related Equipment” to our consolidated financial statements, proved reserves estimates are subject to future revisions when additional information becomes available. All other properties, including the gathering and transportation assets, are stated at historical acquisition cost, net of any impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, up to 36 years for gathering facilities, and up to 40 years for transportation assets. Estimated asset retirement costs are recognized when the asset is acquired or placed in service, and are amortized over proved reserves using the units-of-production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates. Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. Cash flow estimates for impairment testing are based on third party reserve reports and exclude derivative instruments. Refer to Note 7 “Oil and Natural Gas Properties and Related Equipment” to our consolidated financial statements for additional information. Reserves of Natural Gas, NGLs and Oil Our estimate of proved reserves is based on the quantities of natural gas, NGLs and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Management estimates the proved reserves attributable to our ownership based on various factors, including consideration of the reserve report prepared by Ryder Scott, an independent oil and natural gas consulting firm. On an annual basis, our proved reserve estimates and the reserve report prepared by Ryder Scott are reviewed by the Audit Committee and the Board. Our financial statements for 2020 and 2019 were prepared using Ryder Scott’s estimates of our proved reserves. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the actual quantities of oil and natural gas eventually recovered. Unit-Based Compensation The Partnership records unit-based compensation expense for awards granted in accordance with the provisions of Accounting Standards Codification (“ASC”) Topic 718, “Compensation—Stock Compensation.” Unit-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method. Investments We follow the equity method of accounting when we do not exercise control over the investee, but we can exercise significant influence over the operating and financial policies of the investee. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. We evaluate our equity investments for impairment when evidence indicates the carrying amount of our investment is no longer recoverable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. When the estimated fair value of an equity investment is less than its carrying value and the loss in value is determined to be other than temporary, we recognize the excess of the carrying value over the estimated fair value as an impairment loss within earnings from equity investments in our consolidated statements of operations. Earnout Derivative 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 is accounted for under ASC 815, and we measure its fair value through the use of a Monte Carlo simulation model which utilized observable inputs such as the earnout price and volume commitment, as well as unobservable inputs related to the weighted probabilities of various throughput scenarios.

Revenue Recognition

Revenue Recognition	12 Months Ended
	Dec. 31, 2020
Revenue Recognition
Revenue Recognition	3. REVENUE RECOGNITION Revenue from Contracts with Customers We account for revenue from contracts with customers in accordance with ASC 606. The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied. Disaggregation of Revenue We recognized revenue of $57.0 million and $76.6 million for the years ended December 31, 2020 and 2019, respectively. We disaggregate revenue based on type of revenue and product type. In selecting the disaggregation categories, we considered a number of factors, including disclosures presented outside the financial statements, such as in our earnings release and investor presentations, information reviewed internally for evaluating performance, and other factors used by the Partnership or the users of its financial statements to evaluate performance or allocate resources. We have concluded that disaggregating revenue by type of revenue and product type appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. Midstream Segment The Seco Pipeline Transportation Agreement is the only contract that we account for under ASC 606. The Gathering Agreement is classified as an operating lease and is accounted for under ASC 842, “Leases”, and is reported as gathering and transportation lease revenue in our consolidated statements of operations. We account for income from our unconsolidated equity method investments as earnings from equity investments in our consolidated statements of operations. Earnings from these equity method investments are further discussed in Note 11 “Investments.” Production Segment Our oil, natural gas, and NGL revenue is marketed and sold on our behalf by the respective asset operators. We are not party to the contracts with the third-party customers. However, we are party to joint operating agreements, which we account for under ASC 808 and revenues for these arrangements is recognized based on the information provided to us by the operators. We additionally recognize and present changes in the fair value of our commodity derivative instruments within natural gas sales and oil sales in the consolidated statements of operations, which is accounted for under ASC 815, “Derivatives and Hedging”. Performance Obligations Under the Seco Pipeline Transportation Agreement, we agreed to provide transportation services of certain quantities of natural gas from the receipt point to the delivery point. Each MMBtu of natural gas transported is distinct and the transportation services performed on each distinct molecule of product is substantially the same in nature. We applied the series guidance and treat these services as a single performance obligation satisfied over time using volumes delivered as the measure of progress. The Seco Pipeline Transportation Agreement requires payment within 30 days following the calendar month of delivery. The Seco Pipeline Transportation Agreement contains variable consideration in the form of volume variability. As the distinct goods or services (rather than the series) are considered for the purpose of allocating variable consideration, we have taken the optional exception under ASC 606 which is available only for wholly unsatisfied performance obligations for which the criteria in ASC 606 have been met. Under this exception, neither estimation of variable consideration nor disclosure of the transaction price allocated to the remaining performance obligations is required. Revenue is alternatively recognized in the period that control is transferred to the customer and the respective variable component of the total transaction price is resolved. For forms of variable consideration that are not associated with a specific volume (such as late payment fees) and thus do not meet allocation exception, estimation is required. These fees, however, are immaterial to our consolidated financial statements and have a low probability of occurrence. As significant reversals of revenue due to this variability are not probable, no estimation is required. Contract Balances Under our sales contracts, we invoice customers after our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities under ASC 606. At December 31, 2020, and 2019 our accounts receivable from contracts with customers were $1.9 million and $1.1 million, respectively, and are presented within accounts receivable – related entities on the consolidated balance sheets.

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2020
Fair Value Measurements
Fair Value Measurements	4. FAIR VALUE MEASUREMENTS Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories: Level 1 : Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the term of the instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 3 : Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Management's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of 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) The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2019 (in thousands): Fair Value Measurements at December 31, 2019 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative liabilities $ — $ (759) $ — $ (759) Other liabilities Warrant — (629) — (629) Total $ — $ (1,388) $ — $ (1,388) As of December 31, 2020 and 2019, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets and current liabilities approximated their carrying value due to their short-term nature. Fair Value on a Non-Recurring Basis The Partnership follows the provisions of Topic 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy. We periodically review oil and natural gas properties and related equipment for impairment when facts and circumstances indicate that their carrying values may not be recoverable. A reconciliation of the beginning and ending balances of the Partnership’s asset retirement obligations is presented in Note 9 “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 non-cash impairment charges 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. We had no non-recurring fair value measurements of our production assets as of December 31, 2019. The fair values of oil and natural gas properties and related equipment were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties and related equipment include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; (v) estimated throughput; and (vi) a market-based weighted average cost of capital rate of 15%. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. A reconciliation of the beginning and ending balances of the Partnership’s asset retirement obligations is presented in Note 9 ‘‘Asset Retirement Obligation.’’ Class C Preferred Units – As part of the Exchange (defined in Note 16 “Partners’ Capital”), Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units and the Warrant in a privately negotiated transaction. The Class C Preferred Units were measured using valuation techniques that convert a future obligation to a single discounted amount. We have therefore classified the fair value measurements of the Class C Preferred units as Level 2 and are presented within “Class C Preferred Units” on the Consolidated Balance Sheets. Seco Pipeline – During the years ended December 31, 2020 and 2019, we recorded non-cash impairment charges of $0.9 million and $32.1 million, respectively, to impair the Seco Pipeline. The carrying value of the Seco Pipeline was reduced to a fair value of zero, estimated based on an inputs characteristic of a Level 3 fair value measurement. The fair value of the Seco Pipeline was measured using probabilistic valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of the Seco Pipeline include estimates of: (i) future operating and development costs; (ii) estimated future cash flows; and (iii) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Fair Value of Financial Instruments The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below. We prioritize the use of the highest level inputs available in determining fair value such that fair value measurements are determined using the highest and best use as determined by market participants and the assumptions that they would use in determining fair value. Credit Agreement – We believe that the carrying value of our Credit Agreement (defined in Note 6 “Debt”) approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar terms. The debt is classified as a Level 2 input in the fair value hierarchy and represents the amount at which the instrument could be valued in an exchange during a current transaction between willing parties. The Credit Agreement is discussed further in Note 6 “Debt.” Derivative Instruments – The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value measurements of our derivative instruments classified as Level 2 inputs. Our commodity derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of oil and natural gas prices and an appropriate discount rate. Our interest rate derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of the LIBOR interest rates and an appropriate discount rate. We did not have any interest rate or commodity derivatives as of December 31, 2020. Warrant – As part of the Exchange, the Partnership issued to Stonepeak the Warrant which entitles the holder to receive junior securities representing ten percent of junior securities deemed outstanding when exercised. The Warrant expires on the later of August 2, 2026 or 30 days following the full redemption of the Class C Preferred Units. There is no strike price associated with the exercise of the Warrant. The Warrant is valued using ten percent of the junior securities deemed outstanding and the common unit price as of the balance sheet date. We have therefore classified the fair value measurements of the Warrant as Level 2 and is presented within other liabilities on the consolidated balance sheets. Earnout Derivative – 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. There was no change in fair value of the earnout derivative during the years ended December 31, 2020 and 2019.

Derivative And Financial Instru

Derivative And Financial Instruments	12 Months Ended
	Dec. 31, 2020
Derivative And Financial Instruments
Derivative And Financial Instruments	5. DERIVATIVE AND FINANCIAL INSTRUMENTS To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that fix or modify the future prices to be realized. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It is never our intention to enter into derivative contracts for speculative trading purposes. Under Topic 815, “Derivatives and Hedging”, all derivative instruments are recorded on the consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We will net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met. We have not elected to designate any of our current derivative contracts as hedges; however, changes in the fair value of all of our derivative instruments are recognized in earnings and included in natural gas sales and oil sales in the consolidated statements of operations. As of December 31, 2020, all of our commodity derivative contracts have matured. The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the years ended December 31, 2020 and 2019 (in thousands): Years Ended December 31, 2020 2019 Beginning fair value of commodity derivatives $ (759) $ 3,914 Net gains (losses) on crude oil derivatives 3,814 (4,031) Net gains on natural gas derivatives 87 259 Net settlements received on derivative contracts: Oil (2,829) (807) Natural gas (313) (94) Ending fair value of commodity derivatives $ — $ (759) The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands): Location of Gain (Loss) Years Ended December 31, Derivative Type in Income 2020 2019 Commodity – Mark-to-Market Oil sales $ 3,814 $ (4,031) Commodity – Mark-to-Market Natural gas sales 87 259 $ 3,901 $ (3,772) Earnout Derivative Refer to Note 4 “Fair Value Measurements”.

Debt

Debt	12 Months Ended
	Dec. 31, 2020
Debt
Debt	6. DEBT Credit Agreement We have entered into a credit facility with Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto (as amended by the Tenth Amendment to Third Amended and Restated Credit Agreement (the “Credit Agreement”). The Credit Agreement provides a quarterly amortizing term loan of $155.0 million (the “Term Loan”) and a maximum revolving credit amount of $17.5 million, which is 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, including a further limitation on such amount to $15.0 million through May 14, 2021; (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 December 31, 2020, the borrowing base under the Credit Agreement was $129.1 million and we had $111.0 million of debt outstanding, consisting of $105.0 million under the Term Loan and $6.0 million under the Revolving Loan. We are required to make mandatory amortizing payments of outstanding principal on the Term Loan of $10 million per fiscal quarter. The maximum revolving credit amount is $15.0 million leaving us with $9.0 million in unused borrowing capacity. There were no letters of credit outstanding under our Credit Agreement as of December 31, 2020. At our election, interest for borrowings under the Credit Agreement are determined by reference to (i) the LIBOR plus an applicable margin between 2.50% and 3.00% per annum based on net debt to EBITDA or (ii) a domestic bank rate (“ABR”) plus an applicable margin between 1.50% and 2.00% per annum based on net debt to EBITDA plus (iii) a commitment fee of 0.500% per annum based on the unutilized maximum revolving credit. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans are generally payable at the applicable maturity date. The Credit Agreement contains various covenants that limit, among other things, our ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets, make certain loans, acquisitions, capital expenditures and investments, and pay distributions to unitholders. In addition, we are required to maintain the following financial covenants: · current assets to current liabilities of at least 1.0 to 1.0 at all times; and · senior secured net debt to consolidated adjusted EBITDA for the last twelve months, as of the last day of any fiscal quarter, of not greater than 3.5 to 1.0. The Credit Agreement also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, loan documents not being valid and a change in control. A change in control is generally defined as the occurrence of one of the following events: (i) our existing general partner ceases to be our sole general partner or (ii) certain specified persons shall cease to own more than 50% of the equity interests of our general partner or shall cease to control our general partner. If an event of default occurs, the lenders will be able to accelerate the maturity of the Credit Agreement and exercise other rights and remedies. At December 31, 2020, we were in compliance with the financial covenants contained in the Credit Agreement. We monitor compliance on an ongoing basis. If we are unable to remain in compliance with the financial covenants contained in our Credit Agreement or maintain the required ratios discussed above, the lenders could call an event of default and accelerate the outstanding debt under the terms of the Credit Agreement, such that our outstanding debt could become then due and payable. We may request waivers of compliance from the violated financial covenants from the lenders, but there is no assurance that such waivers would be granted. Debt Issuance Costs As of December 31, 2020 and 2019, our unamortized debt issuance costs were approximately $0.8 million and $1.2 million, respectively. These costs are amortized to interest expense in our consolidated statements of operations over the life of our Credit Agreement. Amortization of debt issuance costs recorded during the years ended December 31, 2020 and 2019 were approximately $0.8 million and $1.3 million, respectively.

Oil And Natural Gas Properties

Oil And Natural Gas Properties And Related Equipment	12 Months Ended
	Dec. 31, 2020
Oil And Natural Gas Properties And Related Equipment.
Oil And Natural Gas Properties And Related Equipment	7. OIL AND NATURAL GAS PROPERTIES AND RELATED EQUIPMENT Gathering and transportation assets consist of the following (in thousands): December 31, 2020 2019 Gathering and transportation assets Midstream assets $ 187,977 $ 186,941 Less: Accumulated depreciation, amortization and impairment (82,710) (74,648) Total gathering and transportation assets, net $ 105,267 $ 112,293 Oil and natural gas properties consist of the following (in thousands): December 31, 2020 2019 Oil and natural gas properties and related equipment Proved property $ 112,471 $ 112,476 Less: Accumulated depreciation, depletion, amortization and impairments (94,843) (69,541) Total oil and natural gas properties and equipment, net $ 17,628 $ 42,935 Oil and Natural Gas Properties. We follow the successful efforts method of accounting for our oil and natural gas production activities. Under this method of accounting, costs relating to leasehold acquisition, property acquisition and the development of proved areas are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Proved Reserves. Accounting rules require that we price our oil and natural gas proved reserves at the preceding twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Such SEC-required prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Our proved reserve estimates exclude the effect of any derivatives we have in place. Our estimate of proved reserves is based on the quantities of natural gas, NGLs, and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Proved reserves are calculated based on various factors, including consideration of an independent reserve engineers’ report on proved reserves and an economic evaluation of all of our properties on a well-by-well basis. The process used to complete the estimates of proved reserves at December 31, 2020 and 2019 is described in detail in Note 19 “Supplemental Information on Oil and Natural Gas Producing Activities.” Reserves and their relation to estimated future net cash flows impact depletion and impairment calculations. As a result, adjustments to depletion and impairments are made concurrently with changes to reserve estimates. The accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. Proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered. Depreciation, Depletion and Amortization. Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold and proved property acquisition costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (including wells and related equipment and facilities) are amortized on the basis of proved developed reserves. All other properties, including the gathering and transportation assets, are stated at historical acquisition cost, net of any impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, up to 36 years for gathering facilities, and up to 40 years for transportation assets. Impairment of Oil and Natural Gas Properties and Other Non-Current Assets. Oil and natural gas properties are reviewed for impairment on a field-by-field basis when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. The cash flow estimates are based upon third-party reserve reports using future expected oil and natural gas prices adjusted for basis differentials. Other 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. During the year ended December 31, 2020, we recorded non-cash impairment charges of $23.4 million to impair our producing oil and natural gas properties. We did not impair our producing oil and natural gas properties during the year ended December 31, 2019. Depreciation, depletion and amortization consisted of the following (in thousands): Years Ended December 31, 2020 2019 Depreciation, depletion and amortization of oil and natural gas-related assets $ 2,218 $ 3,942 Depreciation and amortization of gathering and transportation related assets 7,195 7,931 Amortization of intangible assets 13,460 13,460 Total Depreciation, depletion and amortization $ 22,873 $ 25,333 The recoverability of gathering and transportation assets is evaluated when facts or circumstances indicate that their carrying value may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, we recognize an impairment equal to the excess of net book value over fair value. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our gathering and transportation assets and the recognition of additional impairments. Upon disposition or retirement of gathering and transportation assets, any gain or loss is recorded to operations. For the year ended December 31, 2020, we recorded an impairment charge on the Seco Pipeline of $0.9 million. On January 13, 2020, we received a written notice from Mesquite terminating the Seco Pipeline Transportation Agreement effective February 12, 2020. For the year ended December 31, 2019, we recorded a non-cash charge of $32.1 million, to impair the Seco Pipeline. Asset Retirement Obligation. As described in Note 9 “Asset Retirement Obligation,” estimated asset retirement costs are recognized when the asset is acquired or placed in service. Costs associated with oil and natural gas properties are amortized over proved developed reserves using the units-of-production method. Costs associated with gathering and transportation assets are depreciated using the straight-line method over the useful lives of the asset. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.

Provision For Income Taxes

Provision For Income Taxes	12 Months Ended
	Dec. 31, 2020
Provision For Income Taxes
Provision For Income Taxes	8 . PROVISION FOR INCOME TAXES Publicly traded partnerships like ours are treated as corporations unless they have 90% or more in qualifying income (as that term is defined in the Internal Revenue Code). We satisfied this requirement in each of the years ended December 31, 2020 and 2019 and, as a result, are not subject to federal income tax. However, our partners are individually responsible for paying federal income taxes on their share of our taxable income. Net earnings for financial reporting purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and financial reporting basis of certain assets and liabilities and other factors. We do not have access to information regarding each partner's individual tax basis in our limited partner interests. Provision for income taxes reflects franchise tax obligations in the state of Texas (the “ Texas Margin Tax ” ). Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes. Our federal and state income tax provision (benefit) is summarized below: Years Ended December 31, 2020 2019 Current: Federal $ — $ — State 128 328 Total current 128 328 Deferred: Federal — — State (104) (126) Total deferred (104) (126) Total provision for income taxes $ 24 $ 202 A reconciliation of the provision for (benefit from) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income (loss) before income taxes is as follows (in thousands): Years Ended December 31, 2020 2019 Pre-tax net book loss $ (118,737) $ (50,940) Texas Margin Tax (a) 36 126 Return to accrual (12) 76 Provision for income taxes $ 24 $ 202 Effective income tax rate (0.02)% (0.40)% (a) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses. The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated (in thousands): December 31, 2020 2019 Deferred tax assets (liabilities): Derivative assets $ (29) $ (23) Depreciable, depletable property, plant and equipment 129 21 Other 4 2 Deferred tax assets (liabilities): 104 — Valuation allowance — — Total deferred tax assets (liabilities) $ 104 $ — The Partnership assessed the available positive and negative evidence to determine that a valuation allowance was not required for a portion of its deferred tax assets because it is more likely than not that the deferred tax assets will be realized. As of December 31, 2020 and 2019, the Partnership had no material uncertain tax positions. The Partnership files income tax returns in the U.S. and various state jurisdictions. The Partnership is no longer subject to examination by federal income tax authorities prior to 2017. State statutes vary by jurisdiction.

Asset Retirement Obligation

Asset Retirement Obligation	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation
Asset Retirement Obligation	9. ASSET RETIREMENT OBLIGATION We recognize the fair value of a liability for an ARO in the period in which it is incurred if a reasonable estimate of fair value can be made. Each period, we accrete the ARO to its then present value. The associated asset retirement cost (“ARC”) is capitalized as part of the carrying amount of our oil and natural gas properties, equipment and facilities or gathering and transportation assets. Subsequently, the ARC is depreciated using the units-of-production method for production assets and the straight-line method for midstream assets. The AROs recorded by us relate to the plugging and abandonment of oil and natural gas wells and decommissioning of oil and natural gas gathering and other facilities. Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions result in adjustments to the recorded fair value of the existing ARO, a corresponding adjustment is made to the ARC capitalized as part of the oil and natural gas properties, equipment and facilities or gathering and transportation assets. The following table is a reconciliation of the ARO (in thousands): December 31, 2020 2019 Asset retirement obligation, beginning balance $ 6,898 $ 6,200 Liabilities added from escalating working interests — 172 Accretion expense 567 526 Asset retirement obligation, ending balance $ 7,465 $ 6,898 Additional AROs increase the liability associated with new oil and natural gas wells and other facilities as these obligations are incurred. Abandonments of oil and natural gas wells and other facilities reduce the liability for AROs. In 2020 and 2019, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing AROs.

Intangible Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2020
Intangible Assets
Intangible Assets	10. INTANGIBLE ASSETS Intangible assets are comprised of customer and marketing contracts. The intangible assets balance as of December 31, 2020 is related to the Gathering Agreement with Mesquite that was entered into as part of the Western Catarina Midstream transaction. Pursuant to the 15-year agreement, Mesquite tenders all of its crude oil, natural gas and other hydrocarbon-based product volumes on 35,000 dedicated acres in the Western Catarina of the Eagle Ford Shale in Texas for processing and transportation through Western Catarina Midstream, with a right to tender additional volumes outside of the dedicated acreage. These intangible assets are being amortized using the straight-line method over the 15 year life of the agreement. Amortization expense for the years ended December 31, 2020 and 2019 was $13. 5 million, respectively. These costs are amortized to depreciation, depletion, and amortization expense in our consolidated statement of operations. Intangible assets as of December 31, 2020 and 2019 are detailed below (in thousands): December 31, 2020 2019 Beginning balance $ 145,246 $ 158,706 Amortization (13,460) (13,460) Ending balance $ 131,786 $ 145,246

Investments

Investments	12 Months Ended
	Dec. 31, 2020
Investments
Investments	11. 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 earnings from equity investments in our 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 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 working interest partners, establishes commercial terms for the gathering of gas on the Carnero Gathering Line and processing at the Raptor Gas Processing Facility and Silver Oak II. Prior to execution of the agreement, Comanche volumes were gathered and processed on an interruptible basis, with the processing capabilities of the Carnero JV limited by the capacity of the Raptor Gas Processing Facility. As a result of the Carnero JV Transaction we now record our share of earnings and losses from the Carnero JV using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting. The HLBV is a balance-sheet approach that calculates the amount we would have received if the Carnero JV were liquidated at book value at the end of each measurement period. The change in our allocated amount during the period is recognized in our consolidated statements of operations. In the event of liquidation of the Carnero JV, available proceeds are first distributed to any priority return and unpaid capital associated with Silver Oak II, and then to members in accordance with their capital accounts. As of December 31, 2020, 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 our consolidated balance sheets. For the year ended December 31, 2020, the Partnership recorded earnings of approximately $5.7 million in equity investments from the Carnero JV, which was offset by approximately $1.2 million related to the amortization of the contractual customer intangible asset. We have included these equity method earnings in the earnings from equity investments line within the consolidated statements of operations. Cash distributions of approximately $15.3 million were received during the year ended December 31, 2020. Summarized financial information of unconsolidated entities is as follows (in thousands): Years Ended December 31, 2020 2019 Sales $ 80,228 $ 159,508 Total expenses 63,121 145,837 Net income $ 17,107 $ 13,671

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2020
Commitments And Contingencies
Commitments And Contingencies	12. COMMITMENTS AND CONTINGENCIES 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 December 31, 2020 and 2019. For the year ended December 31, 2020, natural gas received did not exceed the threshold. For the year ended December 31, 2019 payments totaling approximately $32.0 thousand were made.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2020
Related Party Transactions
Related Party Transactions	13. RELATED PARTY TRANSACTIONS Relationship with Stonepeak Since October 14, 2015, Stonepeak Catarina has owned all of our issued and outstanding preferred units. As of March 16, 2021, Stonepeak owned (i) 39,623,443 common units, representing approximately 72.7% of our outstanding common units, (ii) all of our issued and outstanding Class C Preferred Units, (iii) the Warrant that entitled Stonepeak Catarina to receive junior securities of the Partnership (including common units) representing 10% of all junior securities deemed outstanding when exercised, (iv) the non-economic general partner interest in the Partnership and (v) all of our incentive distribution rights. Stonepeak also owns 100% of the issued and outstanding equity interests in SP Holdings, which is the sole member of our general partner. SP Holdings has the right to appoint all of the members of the Board of directors other than two directors which Stonepeak Catarina is entitled to designate pursuant to that certain Amended and Restated Board Representation and Standstill Agreement, dated as of August 2, 2019. Stonepeak controls us and our general partner and has the ability to appoint all of the members of the Board and is considered a related party of the Partnership. Currently, four of our directors, Jack Howell, Luke Taylor, Michael Bricker and John T. Steen III are representatives of Stonepeak as either employees or operating partners of Stonepeak. Messrs. Howell, Taylor, Bricker and Steen do not receive separate compensation for their service on the Board, but they are entitled to indemnification related to their service as directors pursuant to the terms of our partnership agreement. Mr. Meisel receives certain compensation for his service on the Board. “See Part III, Item 11. Executive Compensation—Compensation of Directors.” Relationship with Mesquite Prior to emergence from the Mesquite Chapter 11 Case, Mesquite was considered a related party of the Partnership because (i) Antonio R. Sanchez, III, who served as the Chairman of the Board at such time, also served as the Chief Executive Officer of Mesquite, (ii) Patricio D. Sanchez, who served as a member of the Board and as our President and Chief Operating Officer at such time, also served as a senior vice president and Chief Operating Officer of Mesquite, and (iii) Mesquite and certain other members of the Sanchez family directly or indirectly owned approximately 24.3% of the issued and outstanding common units of the Partnership at such time. As of June 30, 2020, Mesquite is not considered a related party of the Partnership. Prior to the date of this Form 10-K, Antonio R. Sanchez, III resigned from his position as a member of the Board and the Chairman of the Board and Patricio D. Sanchez resigned from his position as a member of the Board and as our President and Chief Operating Officer. Relationship with SP Holdings We are controlled by our general partner, Evolve Transition Infrastructure GP LLC. The sole member of our general partner is SP Holdings which has no officers. The sole member of SP Holdings is Stonepeak Catarina and the managing member of SP Holdings is Stonepeak Catarina Upper Holdings, LLC, an affiliate of Stonepeak Catarina. Shared Services Agreement We have entered into the Shared Services Agreement with SP Holdings. In connection with providing the services under the Shared Services Agreement, SP Holdings receives compensation consisting of: (i) a quarterly fee equal to 0.375% of the value of our properties other than our assets located in the Mid-Continent region, (ii) reimbursement for all allocated overhead costs as well as any direct third-party costs incurred and (iii) for each asset acquisition, asset disposition and financing, a fee not to exceed 2% of the value of such transaction. Prior to August 2, 2019 each of these fees, not including the reimbursement of costs, was paid in cash unless SP Holdings elected for such fee to be paid in our equity. However, on August 2, 2019, we and SP Holdings entered into a letter agreement providing that until such time as we redeem all of our issued and outstanding Class C Preferred Units, SP Holdings will elect to receive its fees, not including reimbursement of costs, in common units rather than cash. In addition, on November 8, 2019, we and SP Holdings entered into an additional letter agreement 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 (the “Tolling Period”), SP Holdings would agree to delay receipt of its fees, not including reimbursement of costs. During the Tolling Period, we are required to keep an accurate ledger of the dollar amount of the fee applicable to each quarter within the Tolling Period and the daily closing price of our common units on the NYSE. Following the end of the Tolling Period we will provide a notice to SP Holdings including such ledgers and pay the accrued fees within thirty days of delivery of such notice. The Shared Services Agreement has a ten-year term and will be automatically renewed for an additional ten years unless we or SP Holdings provide notice of termination to the other with at least 180 days’ notice. For the fees earned during the year ended December 31, 2020, pursuant to the November 8, 2019 letter agreement, SP Holdings did not receive any fees, other than reimbursement of its costs. However, pursuant to the requirements under the November 8, 2019 letter agreement, we have determined that the fees earned during the years ended December 31, 2020 and 2019 are approximately $7.2 million and $7.3 million, respectively. The Shared Services Agreement can be terminated (i) by either party at any time by 180 days’ prior written notice to the other party, (ii) by SP Holdings if there is an uncured material breach thereunder by the Partnership, or (iii) by the Partnership, subject to Board approval, if (1) there is an uncured material breach thereunder by SP Holdings or (2) there is a change in control of SP Holdings. Pursuant to the Standstill Agreement, the Partnership must obtain Stonepeak Catarina’s consent to its termination of the Shared Services Agreement. The Shared Services Agreement provides that if there is a termination other than by either party at the end of the Service Agreement’s term, by the Partnership for an uncured breach by SP Holdings, or by the Partnership upon a change of control of SP Holdings, then the Partnership will owe a termination payment to SP Holdings in an amount equal to $5,000,000 plus 5% of the transaction value of all asset acquisitions theretofore consummated. We estimate that this amount was in excess of $35.0 million as of December 31, 2020. Such termination fee may be payable in cash or common units. If the Partnership terminates upon 180 days’ prior notice then the Partnership must also pay to SP Holdings all costs and expenses of SP Holdings that result from such termination. To date, no notice of termination of the Shared Services Agreement has been delivered by SP Holdings, and the Partnership is continuing to discuss the Shared Services Agreement with SP Holdings. Related Party Transactions 2019 Class C Preferred Unit Issuance and Warrant On August 2, 2019, Stonepeak Catarina exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units and a warrant exercisable for junior securities (the “Warrant”) in a privately negotiated transaction (the “Exchange”). In connection with the Exchange, the Partnership entered into (i) the Third Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended Partnership Agreement) to set forth the terms of the Class C Preferred Units, (ii) the Amended and Restated Registration Rights Agreement with Stonepeak relating to the registered resale of common units issuable upon the exercise of the Warrant, and (iii) the Amended and Restated Board Representation and Standstill Agreement with Stonepeak. In addition, on August 2, 2019, the Partnership’s general partner entered into Amendment No. 3 to its Limited Liability Company Agreement to provide certain changes necessary in connection with the Exchange. On August 2, 2019, in connection with the Exchange, Stonepeak Catarina received the Warrant. The Warrant may be exercised at any time and from time to time during the period beginning on August 2, 2019 and ending on the later of the seventh anniversary of such date and the date thirty days after the date on which all of the Class C Preferred Units have been redeemed for a number of Junior Securities (as such term is defined in the Warrant) equal to 10% of each applicable class of Junior Securities deemed outstanding as of the exercise date. No exercise price will be payable in connection with the exercise of the Warrant. At the time of the Exchange and Warrant, Stonepeak Catarina owned all of the Partnership’s issued and outstanding Class B Preferred Units, representing an approximately 61.7% interest in the Partnership. Jack Howell and Luke Taylor, members of the Board during the year ended December 31, 2019, were also employees of Stonepeak at the time of the Exchange. 2020 Settlement Agreement On June 6, 2020 the Partnership, our general partner and certain of our subsidiaries entered into the Settlement Agreement with Mesquite and certain of its subsidiaries. On June 30, 2020, the Bankruptcy Court entered an order approving the Settlement Agreement and the parties to the Settlement Agreement entered into or amended certain commercial contracts, including but not limited to, (i) Amendment No. 2, (ii) the Seco Catarina Agreement, and (iii) the Seco Comanche Agreement. Each such agreement will become effective only upon satisfaction of certain closing conditions described in the Settlement Agreement. JT3 Consulting Agreement On June 30, 2020, our general partner entered into that certain Consultancy Agreement (the “JT3 Consulting Agreement”) with JT3 Advisors LLC (“JT3 Advisors”). JT3 Advisors is an entity owned by John T Steen III, who has served as the Chairman of the Board since September 2020. Pursuant to the terms of the JT3 Consulting Agreement the Partnership pays JT3 Advisors a consulting fee of $20,000 per month for the provision of services to aid the Partnership in achieving its commercial goals, including analysis and assessment of potential commercial arrangements and recommendation of selected arrangements to our management. Certain Transactions with Stonepeak On November 16, 2020, the Partnership and Stonepeak Catarina entered 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 Stonepeak Letter Agreement also provides that Stonepeak Catarina 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. The Letter Agreement Transactions were referred to the Conflicts Committee of the Board. The Conflicts Committee approved the Letter Agreement Transactions, recommended that the Board approve and authorize the execution and performance of the Letter Agreement Transactions, and verified that their approvals constituted “Special Approval” of the Letter Agreement Transactions under and pursuant to our partnership agreement. Following the approval and recommendation from the Conflicts Committee, the Board approved the Letter Agreement Transactions. An aggregate distribution of 22,274,869 common units was made to Stonepeak Catarina on February 1, 2021, following the satisfaction of certain issuance conditions. The approximate value of this transaction was $12.9 million. On January 28, 2021, Stonepeak Catarina provided us with its notice of election to receive a Common Unit PIK Distribution for the fourth quarter of 2020. The aggregate distribution of 12,445,491 common units was made to Stonepeak Catarina on February 25, 2021, following the satisfaction of certain issuance conditions. The approximate value of this transaction was $12.9 million. As a result of the foregoing transactions, as of March 16, 2021, Stonepeak owned (i) 39,623,443 common units, representing approximately 72.7% of our outstanding common units, (ii) all of our issued and outstanding Class C Preferred Units, (iii) the Warrant that entitled Stonepeak Catarina to receive junior securities of the Partnership (including common units) representing 10% of all junior securities deemed outstanding when exercised, (iv) the non-economic general partner interest in the Partnership and (v) all of our incentive distribution rights.. Pursuant to Section 15.1 of our partnership agreement, if at any time Stonepeak holds more than 80% of our outstanding common units and completes the Stonepeak LCR Transfer, Stonepeak will be able to cause our general partner or a controlled affiliate of our general partner to exercise the limited call right. Stonepeak would effect any such exercise by first completing the Stonepeak LCR Transfer and then causing our general partner to exercise its limited call right at a price equal to the greater of (1) the average of the daily closing price of our common units over the 20 trading days preceding the date three days before notice of exercise of the limited call right is first mailed and (2) the highest per-unit price paid by our general partner or any of its controlled affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, common unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Common unitholders may also incur tax liability upon a sale of their units. Our general partner is not obligated to obtain a fairness opinion regarding the value of common units to be repurchased upon exercise of the limited call right. Furthermore, there is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units, including common units issued pursuant to the Stonepeak Letter Agreement or as a result of the termination or renegotiation of the Shared Services Agreement, and then exercising its limited call right. If our general partner exercises its limited call right, the effect would be to take the Partnership private and, if the common units are subsequently deregistered, the Partnership will no longer be subject to the reporting requirements of the Securities Exchange Act of 1934, as amended. As of March 16, 2021, the General Partner and its controlled affiliates do not own any Common Units.

Unit-Based Compensation

Unit-Based Compensation	12 Months Ended
	Dec. 31, 2020
Unit-Based Compensation
Unit-Based Compensation	14. UNIT-BASED COMPENSATION The Partnership’s Long-Term Incentive Plan (the “LTIP”) allows for restricted common unit grants. Restricted common unit activity under the Plan during the period is presented in the following table: Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2018 513,694 $ 12.31 Granted 1,129,173 2.35 Vested (382,690) 8.50 Returned/Cancelled (104,710) 12.04 Outstanding at December 31, 2019 1,155,467 $ 3.86 Vested (338,840) 5.14 Returned/Cancelled (133,456) 5.61 Outstanding at December 31, 2020 683,171 $ 2.68 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 December 31, 2020, 974,393 common units remained available for future issuance to participants under the LTIP.

Distributions To Unitholders

Distributions To Unitholders	12 Months Ended
	Dec. 31, 2020
Distributions To Unitholders
Distributions To Unitholders	15. DISTRIBUTIONS TO UNITHOLDERS The table below reflects the payment of cash distributions on common units related to the periods indicated. Distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2019 $ 0.1500 May 3, 2019 May 22, 2019 May 31, 2019 Beginning with the determination of the distribution for the second-quarter 2019, the Board determined to establish a cash reserve to pay down a portion of the Partnership’s debt outstanding under the Credit Agreement. Following the establishment of the cash reserve, each quarter since the first-quarter 2019, the Board has determined that the Partnership did not have any available cash and, as a result, no cash distribution has been declared for the common units since the quarter ended March 31, 2019. As previously disclosed, our partnership agreement currently prohibits us from paying any distributions on our common units until we have redeemed all of the Class C Preferred Units. Following such redemption, the Credit Agreement may further limit our ability to pay distributions to unitholders. The table below reflects the payment of distributions on Class B Preferred Units related to the periods indicated. Cash distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2019 $ 0.28225 May 3, 2019 May 22, 2019 May 31, 2019 On August 2, 2019, Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units (the “Class C Preferred Units”). As a result the Partnership paid a distribution on the Class C Preferred Units in Class C Preferred PIK Units in lieu of a distribution on the Class B Preferred Units for the second-quarter 2019. The table below reflects the payment of distributions on Class C Preferred Units related to the periods indicated. Class C Preferred Date of Date of Date of Three months ended PIK distribution declaration record distribution June 30, 2019 939,327 August 8, 2019 August 20, 2019 August 30, 2019 September 30, 2019 1,007,820 October 30, 2019 November 29, 2019 November 20, 2019 December 31, 2019 1,039,314 February 13, 2020 February 28, 2020 February 20, 2020 March 31, 2020 1,071,793 April 29, 2020 May 20, 2020 May 29, 2020 June 30, 2020 1,105,286 July 31, 2020 August 20, 2020 August 31, 2020 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 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.

Partners' Capital

Partners' Capital	12 Months Ended
	Dec. 31, 2020
Partners' Capital
Partners' Capital	16. PARTNERS’ CAPITAL Outstanding Units As of December 31, 2020, we had no Class B Preferred Units outstanding, 36,474,436 Class C Preferred Units outstanding and 19,953,880 common units outstanding, which included 683,171 unvested restricted common units issued under the LTIP. Common Unit Issuances The Partnership did not issue any common units to SP Holdings in connection with providing services under the Shared Services Agreement during the year ended December 31, 2020. Class B Preferred Unit Offering On October 14, 2015, pursuant to the Class B Preferred Unit Purchase Agreement dated September 25, 2015, by and between the Partnership and Stonepeak Catarina Holdings LLC (“Stonepeak”), the Partnership sold and Stonepeak purchased 19,444,445 of the Partnership’s newly created Class B Preferred Units (the “Class B Preferred Units”) in a private placement transaction for an aggregate cash purchase price of $18.00 per Class B Preferred Unit, which resulted in gross proceeds to the Partnership of approximately $350.0 million. The Partnership used the net proceeds to pay a portion of the consideration for the acquisition of Western Catarina Midstream, along with the payment to Stonepeak of a fee equal to 2.25% of the consideration paid for the Class B Preferred Units. On December 6, 2016, the Partnership issued an additional 9,851,996 Class B Preferred Units to Stonepeak. On January 25, 2017, the Partnership and Stonepeak entered into a Settlement Agreement and Mutual Release (the “Stonepeak Settlement Agreement”) to settle a dispute arising from the calculation of an adjustment to the number of Class B Preferred Units issued. Pursuant to the Stonepeak Settlement Agreement, the Partnership issued 1,704,446 Class B Preferred Units to Stonepeak in a private placement transaction as partial consideration for the Settlement Agreement, with the “Class B Preferred Unit Price” being established at $11.29 per Class B Preferred Unit. The Class B Preferred Units were accounted for as mezzanine equity on our consolidated balance sheet. The following table sets forth a reconciliation of the changes in mezzanine equity (in thousands): December 31, 2019 Mezzanine equity, beginning balance $ 349,857 Amortization of discount 1,708 Distributions 23,247 Distributions paid (17,675) Class B Preferred Unit exchange (357,137) Mezzanine equity, ending balance $ — On August 2, 2019, Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units and a warrant exercisable for junior securities (the “Warrant”) in a private placement transaction (the “Exchange”). Class C Preferred Units In connection with the Exchange, the Partnership entered into (i) the Third Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended Partnership Agreement) to set forth the terms of the Class C Preferred Units, (ii) the Amended and Restated Registration Rights Agreement with Stonepeak relating to the registered resale of common units issuable upon the exercise of the Warrant, and (iii) the Amended and Restated Board Representation and Standstill Agreement with Stonepeak. Under the terms of the Amended Partnership Agreement, commencing with the quarter ended on September 30, 2019, the holders of the Class C Preferred Units will receive a quarterly distribution of 12.5% per annum payable in cash. To the extent that Available Cash (as defined in the Amended Partnership Agreement) is insufficient to pay the distribution in cash, all or a portion of the distribution may be paid in Class C Preferred PIK Units. Commencing with the quarter ending March 31, 2022, the distribution rate will increase to 14% per annum. Distributions are to be paid on or about the last day of each of February, May, August and November following the end of each quarter and are charged to interest expense in our consolidated statements of operations. The Exchange was accounted for as an extinguishment with the difference between the book value of the redeemed instrument and the fair value of the new instrument being considered a deemed contribution to common equity of approximately $103.8 million. The Class C Preferred Units are accounted for as a long-term liability on the consolidated balance sheet consisting of the following (in thousands): December 31, 2020 2019 Class C Preferred Units, beginning balance $ 281,688 $ — Private placement of Class C Preferred Units — 353,500 Discount — (104,250) Accretion of discount 38,938 13,129 Distribution accrual 24,579 19,309 Class C Preferred Units, ending balance $ 345,205 $ 281,688 Warrant On August 2, 2019, in connection with the Exchange, the Partnership issued to Stonepeak the Warrant which entitles the holder to receive junior securities representing ten percent of junior securities deemed outstanding when exercised. The Warrant expires on the later of August 2, 2026 or 30 days following the full redemption of the Class C Preferred Units. There is no strike price associated with the exercise of the Warrant. The Warrant is accounted for as a liability in accordance with ASC 480 and is presented within other liabilities on the consolidated balance sheet. Changes in the fair value of the Warrant are charged to interest expense in our consolidated statements of operations. Earnings per Unit Net income (loss) per common unit for the period is based on any distributions that are made to the unitholders (common units) plus an allocation of undistributed net income (loss), based on the provisions of the Amended Partnership Agreement, divided by the weighted average number of common units outstanding. The two-class method dictates that net income (loss) for a period be reduced by the amount of distributions and that any residual amount representing undistributed net income (loss) be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income (loss) as if all of the net income for the period had been distributed in accordance with the Amended Partnership Agreement. Unit-based awards granted but unvested are eligible to receive distributions. The underlying unvested restricted unit awards are considered participating securities for purposes of determining net income (loss) per unit. Undistributed income is allocated to participating securities based on the proportional relationship of the weighted average number of common units and unit-based awards outstanding. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units based on provisions of the Amended Partnership Agreement. Undistributed losses are not allocated to unvested restricted unit awards as they do not participate in net losses. Distributions declared and paid in the period are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings. The Partnership’s general partner does not have an economic interest in the Partnership and, therefore, does not participate in the Partnership’s net income.

Reporting Segments

Reporting Segments	12 Months Ended
	Dec. 31, 2020
Reporting Segments
Reporting Segments	17. REPORTING SEGMENTS “Midstream” and “Production” best describe the operating segments of the businesses that we separately report. The factors used to identify these reporting segments are based on the nature of the operations that are undertaken by each segment. The Midstream segment operates the gathering, processing and transportation of natural gas, NGLs and crude oil. The Production segment operates to produce crude oil and natural gas. These segments are broadly understood across the petroleum and petrochemical industries. These functions have been defined as the operating segments of the Partnership because they are the segments (1) that engage in business activities from which revenues are earned and expenses are incurred; (2) whose operating results are regularly reviewed by the Partnership’s chief operating decision maker (“CODM”) to make decisions about resources to be allocated to the segment and to assess its performance; and (3) for which discrete financial information is available. Operating segments are evaluated for their contribution to the Partnership’s consolidated results based on operating income, which is defined as segment operating revenues less expenses. The following tables present financial information for each operating segment for the periods indicated based on our operating segments (in thousands): Years Ended December 31, 2020 2019 Production Midstream Production Midstream Segment revenues Natural gas sales $ 427 $ — $ 683 $ — Oil sales 10,856 — 9,512 — Natural gas liquid sales 254 — 539 — Gathering and transportation sales — 785 — 6,825 Gathering and transportation lease revenues — 44,671 — 59,090 Total segment revenues 11,537 45,456 10,734 65,915 Segment operating costs Lease operating expenses 5,340 884 5,879 1,499 Transportation operating expenses — 9,314 — 11,553 Production taxes 311 — 621 — Depreciation, depletion and amortization 2,218 20,655 3,942 21,391 Asset impairments 23,355 867 — 32,119 Accretion expense 212 355 200 326 Total segment operating costs 31,436 32,075 10,642 66,888 Segment other income Earnings from equity investments — 4,479 — 2,831 Total segment other income — 4,479 — 2,831 Segment operating income (loss) $ (19,899) $ 17,860 $ 92 $ 1,858 Years Ended December 31, 2020 2019 Reconciliation of segment operating income (loss) to net loss Total midstream operating income $ 17,860 $ 1,858 Total production operating income (loss) (19,899) 92 Total segment operating income (loss) (2,039) 1,950 General and administrative expenses (18,296) (17,610) Unit-based compensation expense (2,602) (1,351) Interest expense, net (95,871) (39,789) Other income 71 5,860 Income tax expense (24) (202) Net loss $ (118,761) $ (51,142) The following table summarizes the total assets and capital expenditures by operating segment as of December 31, 2020 and 2019 (in thousands): 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 December 31, 2019 Production Midstream Corporate (a) Total Other financial information Total assets $ 45,550 $ 362,961 $ 5,929 $ 414,440 Capital expenditures (b) $ 130 $ 775 $ — $ 905 (a) Corporate assets not reviewed by the CODM on a segment basis consists of cash, certain prepaid expenses, office furniture and other assets. (b) Inclusive of capital contributions made to equity method investments. Revenue from Mesquite earned in our Midstream segment accounted for 80% and 86% of total revenue for the years ended December 31, 2020 and 2019, respectively. Because all remaining production properties are non-operated, there are no customers in the Production segment that exceed 10% of the Partnership’s consolidated revenue.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2020
Variable Interest Entities
Variable Interest Entities	18. 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 $89.6 million. As of December 31, 2020, 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 the balance sheet. Below is a tabular comparison of the carrying amounts of the assets and liabilities of the VIE and the Partnership’s maximum exposure to loss as of December 31, 2020 and 2019 (in thousands): December 31, 2020 2019 Acquisitions, earnout and capital investments $ 128,251 $ 128,140 Earnings in equity investments 30,455 25,976 Distributions received (69,071) (53,805) Maximum exposure to loss $ 89,635 $ 100,311

Supplemental Information On Oil

Supplemental Information On Oil And Natural Gas Producing Activities	12 Months Ended
	Dec. 31, 2020
Supplemental Information On Oil And Natural Gas Producing Activities
Supplemental Information On Oil And Natural Gas Producing Activities	19. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED) The Supplementary Information on Oil and Natural Gas Producing Activities is presented as required by the appropriate authoritative guidance . The supplemental information includes capitalized costs related to oil and natural gas producing activities; costs incurred for the acquisition of oil and natural gas producing activities, exploration and development activities and the results of operations from oil and natural gas producing activities. Supplemental information is also provided for per unit production costs; oil and natural gas production and average sales prices; the estimated quantities of proved oil and natural gas reserves; the standardized measure of discounted future net cash flows associated with proved reserves and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved reserves. Costs The following table sets forth our capitalized costs as of December 31, 2020 and 2019 (in thousands): December 31, 2020 2019 Capitalized costs at the end of the period: ⁽ᵃ⁾ Oil and natural gas properties and related equipment (successful efforts method) Proved property $ 112,471 $ 112,476 Less: Accumulated depreciation, depletion, amortization and impairments (94,843) (69,541) Oil and natural gas properties and equipment, net $ 17,628 $ 42,935 (a) Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. The following table sets forth costs incurred for oil and natural gas producing activities for the years ended December 31, 2020 and 2019 (in thousands): Years Ended December 31, 2020 2019 Costs incurred for the period: Development costs $ — $ 131 Oil and natural gas properties and equipment, net $ — $ 131 The development costs for the year ended December 31, 2019 primarily represent costs related to recompletions. We had no exploration and dry hole costs in 2020 and 2019. Results of Operations The revenues and expenses associated directly with oil and natural gas producing activities are reflected in the Consolidated Statements of Operations. All of our oil and natural gas producing activities are located in the United States. Net Proved Reserves of Natural Gas, NGLs and Oil The following table sets forth information with respect to changes in proved developed and undeveloped reserves. All of our reserves are located in the United States. Natural Gas Total Oil Natural Gas Liquids (MBoe) (MBoe) (MBoe) (MBoe) Net proved reserves December 31, 2018 3,453 2,479 454 520 Revisions of previous estimates (145) (10) (67) (68) Production (309) (228) (39) (42) December 31, 2019 2,999 2,241 348 410 Revisions of previous estimates (475) (334) (35) (106) Production (241) (191) (26) (24) December 31, 2020 2,283 1,716 287 280 Proved developed reserves: December 31, 2019 2,999 2,241 348 410 December 31, 2020 2,283 1,716 287 280 Reserves and Related Estimates Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our year end December 31, 2020 and 2019, proved reserve estimates were 2.3 MMBoe and 3.0 MMBoe, respectively. Reserve estimates for those periods were prepared by, Ryder Scott, an independent petroleum engineering firm, and are used for the applicable disclosures in our financial statements. Our 2020 estimates of total proved reserves decreased 0.7 MMBoe from 2019 due to production of 0.2 MMBoe and revisions of previous estimates of 0.5 MMBoe. For proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report were: $37.70 per Bbl for oil, $10.69 per Bbl for NGLs and $2.02 per Mcf for natural gas. Our 2019 estimates of total proved reserves decreased 0.5 MMBoe from 2018 due to production of 0.3 MMBoe and revisions of previous estimates of 0.2 MMBoe. For proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report were: $59.55 per Bbl for oil, $13.68 per Bbl for NGLs and $2.66 per Mcf for natural gas. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves, Including a Reconciliation of Changes Therein The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved oil and natural gas reserves. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. Future cash inflows are calculated by applying the SEC-required prices of oil and natural gas relating to our proved reserves to the year-end quantities of those reserves. Future cash inflows exclude the impact of our hedging program. Future development and production costs represent the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. In addition, asset retirement obligations are included within future production and development costs. There are no future income tax expenses because the Partnership is a non-taxable entity. The assumptions used to compute estimated future cash inflows do not necessarily reflect expectations of actual revenues or costs or their present values. In addition, variations from expected production rates could result directly or indirectly from factors outside of our control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production; however, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized. The following table summarizes the standardized measure of estimated discounted future cash flows from the oil and natural gas properties (in thousands): Years Ended December 31, 2020 2019 Future cash inflows $ 71,161 $ 144,628 Future production costs (50,809) (80,007) Future estimated development costs (3,614) (3,400) Future net cash flows 16,738 61,221 10% annual discount for estimated timing of cash flows (4,857) (22,871) Standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves $ 11,881 $ 38,350 The following table summarizes the principal sources of change in the standardized measure of estimated discounted future net cash flows (in thousands): Years Ended December 31, 2020 2019 Beginning of the period $ 38,350 $ 52,246 Sales and transfers of oil and natural gas, net of production costs (1,985) (8,006) Net changes in prices and production costs related to future production (27,157) (7,330) Changes in development costs (595) 35 Revisions of previous quantity estimates (2,652) (1,942) Accretion discount 3,835 5,225 Change in production rates, timing, and other 2,085 (1,878) Standardized measure of discounted future net cash flows related to proved oil and natural gas reserves $ 11,881 $ 38,350

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2020
Subsequent Events
Subsequent Events	20. SUBSEQUENT EVENTS 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 made to Stonepeak Catarina on February 25, 2021, following the satisfaction of certain issuance conditions.

Basis Of Presentation And Sum_2

Basis Of Presentation And Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2020
Basis Of Presentation And Summary Of Significant Accounting Policies
Basis of Presentation	Basis of Presentation Accounting policies used by us conform to accounting principles generally accepted in the United States of America (“GAAP). The accompanying financial statements include the accounts of us and our wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. Our business consists of two reportable segments: Production and Midstream. Midstream includes Western Catarina Midstream, the Carnero JV and Seco Pipeline. Production consists of our oil and natural gas properties in Texas and Louisiana. Our management evaluates performance based on these two business segments.
Recent Accounting Pronouncements	Recent Accounting Pronouncements From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our consolidated financial statements upon adoption. In January 2020, the FASB issued Accounting Standards Update (“ASU”) 2020-01 “Investments – Equity Securities (Topic 321), Investments – Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815),” which clarifies the interaction among the accounting standards for equity securities, equity method investments and certain derivatives. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2020. We are currently in the process of evaluating the impact of adoption of this guidance on our condensed consolidated financial statements. In August 2018, the FASB issued ASU 2018-13 “Fair Value Measurement (ASC 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements,” which modifies the disclosure requirements on fair value measurements. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2019. The adoption of this standard did not have a material impact on our 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 consolidated financial statements.
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 consolidated financial statements are prepared in conformity with GAAP, which requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. These estimates and the underlying assumptions affect the amounts of assets and liabilities reported, disclosures about contingent assets and liabilities and reported amounts of revenues and expenses. The estimates that are particularly significant to our financial statements include our ability to continue as a going concern; our reserves of natural gas, NGLs and oil; future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of derivatives; and fair values of assets and liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best judgment using the data available. Management evaluates its estimates and assumptions on an on-going basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from the estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.
Revenue Recognition	Revenue Recognition Midstream We account for revenue from contracts with customers in accordance with ASC 606 and ASC 842 for our midstream segment. The Seco Pipeline Transportation Agreement is our only contract that we account for using ASC 606. Under the Seco Pipeline Transportation Agreement, we agreed to provide transportation services of certain quantities of natural gas from the receipt point to the delivery point. Each MMBtu of natural gas transported is distinct and the transportation services performed on each distinct molecule of product is substantially the same in nature. As such, we applied the series guidance and treat these services as a single performance obligation satisfied over time using volumes delivered as the measure of progress. Additionally, Seco Pipeline Transportation Agreement contains variable consideration in the form of volume variability. As the distinct goods or services (rather than the series) are considered for the purpose of allocating variable consideration, we have taken the optional exception under ASC 606. Under this exception, revenue is alternatively recognized in the period that control is transferred to the customer and the respective variable component of the total transaction price is resolved. In October 2015, we acquired (the “Catarina Transaction”) a gathering system from Mesquite (“Western Catarina Midstream”), which is located on the western portion of Mesquite’s acreage position in Dimmit, La Salle and Webb counties in Texas. In conjunction with the Catarina Transaction, we entered into a 15-year firm gas gathering and processing agreement with Mesquite, pursuant to which Mesquite agreed to tender all of its crude oil, natural gas and other hydrocarbon-based product volumes on approximately 35,000 dedicated acres for processing and transportation through Western Catarina Midstream, with the potential to tender additional volumes outside of the dedicated acreage (the “Gathering Agreement”). The Gathering Agreement was classified as an operating lease at inception and is accounted for under ASC 842, as Mesquite controls the physical use of the property under the lease. Revenues relating to the Gathering Agreement is recognized in the period service is provided. Under this arrangement, the Partnership receives a fee or fees for services provided. The revenue the Partnership recognizes from gathering and transportation services is generally directly related to the volume of oil and natural gas that flows through its systems. Production Our oil, natural gas, and NGL revenue is marketed and sold on our behalf by the respective asset operators. We are not party to the contracts with the third-party customers. However, we are party to joint operating agreements, which we account for under ASC 808, and revenues and expenses for these arrangements is recognized based on the information provided to us by the operators. We additionally recognize and present changes in the fair value of our commodity derivative instruments within natural gas sales and oil sales in the consolidated statements of operations, which is accounted for under ASC 815, “Derivatives and Hedging”. Accounts Receivable, Net Our accounts receivable are primarily from our contractual agreements with Mesquite and its subsidiaries, operators of our oil and natural gas properties and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted. Our allowance for doubtful accounts was $0.4 million as of December 31, 2020 and 2019. Concentration of Credit Risk and Accounts Receivable Financial instruments that potentially subject us to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and derivative financial instruments. We place our cash with high credit quality financial institutions. We place our derivative financial instruments with financial institutions that participate in our Credit Agreement and maintain an investment grade credit rating. Substantially all of our accounts receivable are due from operators of our oil and natural gas properties. These sales are generally unsecured and, in some cases, may carry a parent guarantee. We routinely assess the financial strength of our customers. Bad debt expense is recognized on an account-by-account review and when recovery is not probable. We have no off-balance-sheet credit exposure related to our operations or customers. Mesquite accounted for 80% and 86% of total revenue for the years ended December 31, 2020 and 2019, respectively. We are highly dependent upon Mesquite as our most significant customer, and we expect to derive a substantial portion of our revenue from Mesquite in the foreseeable future. Accordingly, we are indirectly subject to the business risks of Mesquite.
Income Taxes	Income Taxes The Partnership and each of its wholly-owned subsidiary LLCs are treated as a partnership for federal and state income tax purposes. All of our taxable income or loss, which may differ considerably from net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our members. As such, no federal income tax for these entities has been provided for in the accompanying financial statements.
Earnings per Unit	Earnings per Unit Net income (loss) per common unit for the period is based on any distributions that are made to the unitholders (common units) plus an allocation of undistributed net income (loss) based on provisions of the Amended Partnership Agreement, divided by the weighted average number of common units outstanding. The two-class method dictates that net income (loss) for a period be reduced by the amount of distributions and that any residual amount representing undistributed net income (loss) be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income (loss) as if all of the income for the period had been distributed in accordance with the Amended Partnership Agreement. Unit-based awards granted but unvested are eligible to receive distributions. The underlying unvested restricted unit awards are considered participating securities for purposes of determining net income (loss) per unit. Undistributed income is allocated to participating securities based on the proportional relationship of the weighted average number of common units and unit-based awards outstanding. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units based on provisions of the Amended Partnership Agreement. Undistributed losses are not allocated to unvested restricted unit awards as they do not participate in net losses. Distributions declared and paid in the period are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings.
Asset Retirement Obligations	Asset Retirement Obligations Asset retirement obligations represent the present value of the estimated cash flows expected to be incurred to plug, abandon and remediate producing properties, excluding salvage values, at the end of their productive lives in accordance with applicable laws. The significant unobservable inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, asset life, inflation and the credit-adjusted risk-free rate. The inputs are calculated based on historical data as well as current estimates. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. Over time, accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset and is included in accretion expense in the our consolidated statements of operations. To estimate the fair value of an asset retirement obligation, the Partnership employs a present value technique, which reflects certain assumptions, including its credit‑adjusted risk‑free interest rate, inflation rate, the estimated settlement date of the liability and the estimated current cost to settle the liability. Changes in timing or to the original estimate of cash flows will result in changes to the carrying amount of the liability.
Oil and Natural Gas Properties	Oil and Natural Gas Properties We follow the successful efforts method of accounting for our oil and natural gas production activities. Under this method of accounting, costs relating to leasehold acquisition, property acquisition and the development of proved areas are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred. Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (including wells and related equipment and facilities) are amortized on the basis of proved developed reserves. As more fully described in Note 7 “Oil and Natural Gas Properties and Related Equipment” to our consolidated financial statements, proved reserves estimates are subject to future revisions when additional information becomes available. All other properties, including the gathering and transportation assets, are stated at historical acquisition cost, net of any impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, up to 36 years for gathering facilities, and up to 40 years for transportation assets. Estimated asset retirement costs are recognized when the asset is acquired or placed in service, and are amortized over proved reserves using the units-of-production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates. Oil and natural gas properties are reviewed for impairment when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. Cash flow estimates for impairment testing are based on third party reserve reports and exclude derivative instruments. Refer to Note 7 “Oil and Natural Gas Properties and Related Equipment” to our consolidated financial statements for additional information.
Reserves of Natural Gas, NGLs and Oil	Reserves of Natural Gas, NGLs and Oil Our estimate of proved reserves is based on the quantities of natural gas, NGLs and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Management estimates the proved reserves attributable to our ownership based on various factors, including consideration of the reserve report prepared by Ryder Scott, an independent oil and natural gas consulting firm. On an annual basis, our proved reserve estimates and the reserve report prepared by Ryder Scott are reviewed by the Audit Committee and the Board. Our financial statements for 2020 and 2019 were prepared using Ryder Scott’s estimates of our proved reserves. Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserve estimates. The accuracy of our reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. Our proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the actual quantities of oil and natural gas eventually recovered.
Unit-Based Compensation	Unit-Based Compensation The Partnership records unit-based compensation expense for awards granted in accordance with the provisions of Accounting Standards Codification (“ASC”) Topic 718, “Compensation—Stock Compensation.” Unit-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method.
Investments	Investments We follow the equity method of accounting when we do not exercise control over the investee, but we can exercise significant influence over the operating and financial policies of the investee. Under this method, our equity investments are carried originally at our acquisition cost, increased by our proportionate share of the investee’s net income and by contributions made, and decreased by our proportionate share of the investee’s net losses and by distributions received. We evaluate our equity investments for impairment when evidence indicates the carrying amount of our investment is no longer recoverable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. When the estimated fair value of an equity investment is less than its carrying value and the loss in value is determined to be other than temporary, we recognize the excess of the carrying value over the estimated fair value as an impairment loss within earnings from equity investments in our consolidated statements of operations.
Earnout Derivative	Earnout Derivative 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 is accounted for under ASC 815, and we measure its fair value through the use of a Monte Carlo simulation model which utilized observable inputs such as the earnout price and volume commitment, as well as unobservable inputs related to the weighted probabilities of various throughput scenarios.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2020
Fair Value Measurements
Schedule of fair value of assets and liabilities on a recurring basis	The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of 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) The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2019 (in thousands): Fair Value Measurements at December 31, 2019 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative liabilities $ — $ (759) $ — $ (759) Other liabilities Warrant — (629) — (629) Total $ — $ (1,388) $ — $ (1,388)
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

Derivative And Financial Inst_2

Derivative And Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2020
Derivative And Financial Instruments
Fair Value for Risk Management Assets and Liabilities	The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the years ended December 31, 2020 and 2019 (in thousands): Years Ended December 31, 2020 2019 Beginning fair value of commodity derivatives $ (759) $ 3,914 Net gains (losses) on crude oil derivatives 3,814 (4,031) Net gains on natural gas derivatives 87 259 Net settlements received on derivative contracts: Oil (2,829) (807) Natural gas (313) (94) Ending fair value of commodity derivatives $ — $ (759)
Schedule Of Effect Of Derivative Instruments On Consolidated Statements Of Operations	Years Ended December 31, 2020 2019 Beginning fair value of commodity derivatives $ (759) $ 3,914 Net gains (losses) on crude oil derivatives 3,814 (4,031) Net gains on natural gas derivatives 87 259 Net settlements received on derivative contracts: Oil (2,829) (807) Natural gas (313) (94) Ending fair value of commodity derivatives $ — $ (759) The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands): Location of Gain (Loss) Years Ended December 31, Derivative Type in Income 2020 2019 Commodity – Mark-to-Market Oil sales $ 3,814 $ (4,031) Commodity – Mark-to-Market Natural gas sales 87 259 $ 3,901 $ (3,772)

Oil And Natural Gas Propertie_2

Oil And Natural Gas Properties And Related Equipment (Tables)	12 Months Ended
	Dec. 31, 2020
Oil And Natural Gas Properties And Related Equipment.
Schedule of gathering and transportation assets	Gathering and transportation assets consist of the following (in thousands): December 31, 2020 2019 Gathering and transportation assets Midstream assets $ 187,977 $ 186,941 Less: Accumulated depreciation, amortization and impairment (82,710) (74,648) Total gathering and transportation assets, net $ 105,267 $ 112,293
Schedule of oil and natural gas properties	Oil and natural gas properties consist of the following (in thousands): December 31, 2020 2019 Oil and natural gas properties and related equipment Proved property $ 112,471 $ 112,476 Less: Accumulated depreciation, depletion, amortization and impairments (94,843) (69,541) Total oil and natural gas properties and equipment, net $ 17,628 $ 42,935
Schedule of depreciation, depletion, and amortization	Depreciation, depletion and amortization consisted of the following (in thousands): Years Ended December 31, 2020 2019 Depreciation, depletion and amortization of oil and natural gas-related assets $ 2,218 $ 3,942 Depreciation and amortization of gathering and transportation related assets 7,195 7,931 Amortization of intangible assets 13,460 13,460 Total Depreciation, depletion and amortization $ 22,873 $ 25,333

Provision For Income Taxes (Tab

Provision For Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2020
Provision For Income Taxes
Summary of Federal and State Income Tax Provision (Benefit)	Years Ended December 31, 2020 2019 Current: Federal $ — $ — State 128 328 Total current 128 328 Deferred: Federal — — State (104) (126) Total deferred (104) (126) Total provision for income taxes $ 24 $ 202
Reconciliation of Provision for (Benefit from) Income Taxes	A reconciliation of the provision for (benefit from) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income (loss) before income taxes is as follows (in thousands): Years Ended December 31, 2020 2019 Pre-tax net book loss $ (118,737) $ (50,940) Texas Margin Tax (a) 36 126 Return to accrual (12) 76 Provision for income taxes $ 24 $ 202 Effective income tax rate (0.02)% (0.40)% Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses.
Significant Components of Deferred Tax Assets and Deferred Tax Liabilities	The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated (in thousands): December 31, 2020 2019 Deferred tax assets (liabilities): Derivative assets $ (29) $ (23) Depreciable, depletable property, plant and equipment 129 21 Other 4 2 Deferred tax assets (liabilities): 104 — Valuation allowance — — Total deferred tax assets (liabilities) $ 104 $ —

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation
Reconciliation of changes in asset retirement obligation	The following table is a reconciliation of the ARO (in thousands): December 31, 2020 2019 Asset retirement obligation, beginning balance $ 6,898 $ 6,200 Liabilities added from escalating working interests — 172 Accretion expense 567 526 Asset retirement obligation, ending balance $ 7,465 $ 6,898

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2020
Intangible Assets
Schedule of Intangible assets	Intangible assets as of December 31, 2020 and 2019 are detailed below (in thousands): December 31, 2020 2019 Beginning balance $ 145,246 $ 158,706 Amortization (13,460) (13,460) Ending balance $ 131,786 $ 145,246

Investments (Tables)

Investments (Tables)	12 Months Ended
	Dec. 31, 2020
Investments
Summarized financial information of unconsolidated entities	Summarized financial information of unconsolidated entities is as follows (in thousands): Years Ended December 31, 2020 2019 Sales $ 80,228 $ 159,508 Total expenses 63,121 145,837 Net income $ 17,107 $ 13,671

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2020
Unit-Based Compensation
Schedule of units activity	Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2018 513,694 $ 12.31 Granted 1,129,173 2.35 Vested (382,690) 8.50 Returned/Cancelled (104,710) 12.04 Outstanding at December 31, 2019 1,155,467 $ 3.86 Vested (338,840) 5.14 Returned/Cancelled (133,456) 5.61 Outstanding at December 31, 2020 683,171 $ 2.68

Distributions To Unitholders (T

Distributions To Unitholders (Tables)	12 Months Ended
	Dec. 31, 2020
Common units
Schedule of payment of cash distributions	Distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2019 $ 0.1500 May 3, 2019 May 22, 2019 May 31, 2019
Class B preferred units
Schedule of payment of cash distributions	Cash distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2019 $ 0.28225 May 3, 2019 May 22, 2019 May 31, 2019
Class C preferred units
Schedule of payment of cash distributions	Class C Preferred Date of Date of Date of Three months ended PIK distribution declaration record distribution June 30, 2019 939,327 August 8, 2019 August 20, 2019 August 30, 2019 September 30, 2019 1,007,820 October 30, 2019 November 29, 2019 November 20, 2019 December 31, 2019 1,039,314 February 13, 2020 February 28, 2020 February 20, 2020 March 31, 2020 1,071,793 April 29, 2020 May 20, 2020 May 29, 2020 June 30, 2020 1,105,286 July 31, 2020 August 20, 2020 August 31, 2020

Partners' Capital (Tables)

Partners' Capital (Tables)	12 Months Ended
	Dec. 31, 2020
Partners' Capital
Schedule of Class B preferred units accounted for as mezzanine equity in the consolidated balance sheet	The Class B Preferred Units were accounted for as mezzanine equity on our consolidated balance sheet. The following table sets forth a reconciliation of the changes in mezzanine equity (in thousands): December 31, 2019 Mezzanine equity, beginning balance $ 349,857 Amortization of discount 1,708 Distributions 23,247 Distributions paid (17,675) Class B Preferred Unit exchange (357,137) Mezzanine equity, ending balance $ —
Schedule of Class C preferred units	The Class C Preferred Units are accounted for as a long-term liability on the consolidated balance sheet consisting of the following (in thousands): December 31, 2020 2019 Class C Preferred Units, beginning balance $ 281,688 $ — Private placement of Class C Preferred Units — 353,500 Discount — (104,250) Accretion of discount 38,938 13,129 Distribution accrual 24,579 19,309 Class C Preferred Units, ending balance $ 345,205 $ 281,688

Reporting Segments (Tables)

Reporting Segments (Tables)	12 Months Ended
	Dec. 31, 2020
Reporting Segments
Schedule of segment information	The following tables present financial information for each operating segment for the periods indicated based on our operating segments (in thousands): Years Ended December 31, 2020 2019 Production Midstream Production Midstream Segment revenues Natural gas sales $ 427 $ — $ 683 $ — Oil sales 10,856 — 9,512 — Natural gas liquid sales 254 — 539 — Gathering and transportation sales — 785 — 6,825 Gathering and transportation lease revenues — 44,671 — 59,090 Total segment revenues 11,537 45,456 10,734 65,915 Segment operating costs Lease operating expenses 5,340 884 5,879 1,499 Transportation operating expenses — 9,314 — 11,553 Production taxes 311 — 621 — Depreciation, depletion and amortization 2,218 20,655 3,942 21,391 Asset impairments 23,355 867 — 32,119 Accretion expense 212 355 200 326 Total segment operating costs 31,436 32,075 10,642 66,888 Segment other income Earnings from equity investments — 4,479 — 2,831 Total segment other income — 4,479 — 2,831 Segment operating income (loss) $ (19,899) $ 17,860 $ 92 $ 1,858
Schedule of reconciliation of segment operating income to net income (loss)	The following tables present financial information for each operating segment for the periods indicated based on our operating segments (in thousands): Years Ended December 31, 2020 2019 Reconciliation of segment operating income (loss) to net loss Total midstream operating income $ 17,860 $ 1,858 Total production operating income (loss) (19,899) 92 Total segment operating income (loss) (2,039) 1,950 General and administrative expenses (18,296) (17,610) Unit-based compensation expense (2,602) (1,351) Interest expense, net (95,871) (39,789) Other income 71 5,860 Income tax expense (24) (202) Net loss $ (118,761) $ (51,142)
Summary of assets and capital expenditures by operating segment	The following table summarizes the total assets and capital expenditures by operating segment as of December 31, 2020 and 2019 (in thousands): 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 December 31, 2019 Production Midstream Corporate (a) Total Other financial information Total assets $ 45,550 $ 362,961 $ 5,929 $ 414,440 Capital expenditures (b) $ 130 $ 775 $ — $ 905 (a) Corporate assets not reviewed by the CODM on a segment basis consists of cash, certain prepaid expenses, office furniture and other assets. Inclusive of capital contributions made to equity method investments.

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2020
Variable Interest Entities
Schedule of carrying amounts of assets and liabilities of variable interest entity	Below is a tabular comparison of the carrying amounts of the assets and liabilities of the VIE and the Partnership’s maximum exposure to loss as of December 31, 2020 and 2019 (in thousands): December 31, 2020 2019 Acquisitions, earnout and capital investments $ 128,251 $ 128,140 Earnings in equity investments 30,455 25,976 Distributions received (69,071) (53,805) Maximum exposure to loss $ 89,635 $ 100,311

Supplemental Information On O_2

Supplemental Information On Oil And Natural Gas Producing Activities (Tables)	12 Months Ended
	Dec. 31, 2020
Supplemental Information On Oil And Natural Gas Producing Activities
Schedule Of Capitalized Costs	The following table sets forth our capitalized costs as of December 31, 2020 and 2019 (in thousands): December 31, 2020 2019 Capitalized costs at the end of the period: ⁽ᵃ⁾ Oil and natural gas properties and related equipment (successful efforts method) Proved property $ 112,471 $ 112,476 Less: Accumulated depreciation, depletion, amortization and impairments (94,843) (69,541) Oil and natural gas properties and equipment, net $ 17,628 $ 42,935 (a) Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment.
Schedule Of Costs Incurred For Oil And Natural Gas Producing Activities	The following table sets forth costs incurred for oil and natural gas producing activities for the years ended December 31, 2020 and 2019 (in thousands): Years Ended December 31, 2020 2019 Costs incurred for the period: Development costs $ — $ 131 Oil and natural gas properties and equipment, net $ — $ 131
Schedule Of Changes In Proved Developed And Undeveloped Reserves	Natural Gas Total Oil Natural Gas Liquids (MBoe) (MBoe) (MBoe) (MBoe) Net proved reserves December 31, 2018 3,453 2,479 454 520 Revisions of previous estimates (145) (10) (67) (68) Production (309) (228) (39) (42) December 31, 2019 2,999 2,241 348 410 Revisions of previous estimates (475) (334) (35) (106) Production (241) (191) (26) (24) December 31, 2020 2,283 1,716 287 280 Proved developed reserves: December 31, 2019 2,999 2,241 348 410 December 31, 2020 2,283 1,716 287 280
Summary Of Standardized Measure Of Estimated Discounted Future Cash Flows From Properties	The following table summarizes the standardized measure of estimated discounted future cash flows from the oil and natural gas properties (in thousands): Years Ended December 31, 2020 2019 Future cash inflows $ 71,161 $ 144,628 Future production costs (50,809) (80,007) Future estimated development costs (3,614) (3,400) Future net cash flows 16,738 61,221 10% annual discount for estimated timing of cash flows (4,857) (22,871) Standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves $ 11,881 $ 38,350
Summary Of Change In Standardized Measure Of Estimated Discounted Future Net Cash Flows	Years Ended December 31, 2020 2019 Future cash inflows $ 71,161 $ 144,628 Future production costs (50,809) (80,007) Future estimated development costs (3,614) (3,400) Future net cash flows 16,738 61,221 10% annual discount for estimated timing of cash flows (4,857) (22,871) Standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves $ 11,881 $ 38,350 The following table summarizes the principal sources of change in the standardized measure of estimated discounted future net cash flows (in thousands): Years Ended December 31, 2020 2019 Beginning of the period $ 38,350 $ 52,246 Sales and transfers of oil and natural gas, net of production costs (1,985) (8,006) Net changes in prices and production costs related to future production (27,157) (7,330) Changes in development costs (595) 35 Revisions of previous quantity estimates (2,652) (1,942) Accretion discount 3,835 5,225 Change in production rates, timing, and other 2,085 (1,878) Standardized measure of discounted future net cash flows related to proved oil and natural gas reserves $ 11,881 $ 38,350

Basis Of Presentation And Sum_3

Basis Of Presentation And Summary Of Significant Accounting Policies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)segment	Dec. 31, 2019USD ($)
Number of reportable segments | segment	2
Number of business segments | segment	2
Allowance for doubtful accounts | $	$ 0.4	$ 0.4
Credit Agreement
Credit facility, borrowings | $	$ 111
Oil reserves
Trade accounts receivable, general collection period after month end	30 days
Natural gas
Trade accounts receivable, general collection period after month end	60 days
Minimum | Furniture and Equipment
Useful life	3 years
Maximum | Furniture and Equipment
Useful life	15 years
Maximum | Gathering Facilities
Useful life	36 years
Maximum | Transportation assets
Useful life	40 years
Revenue | Customer Concentration Risk | Mesquite Energy, Inc.
Percentage of sales revenue	80.00%	86.00%
Midstream | Revenue | Customer Concentration Risk | Mesquite Energy, Inc.
Percentage of sales revenue	80.00%	86.00%

Revenue Recognition (Details)

Revenue Recognition (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenue Recognition
Performance obligation	true
Revenues	$ 56,993	$ 76,649
Payment term (in days)	30 days
Receivables	$ 1,900	$ 1,100

Fair Value Measurements (Recurr

Fair Value Measurements (Recurring) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Earnout derivative liability	$ 0	$ 0
Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative liabilities		(759)
Other liabilities: Warrant	(1,418)	(629)
Total	(1,418)	(1,388)
Fair Value, Inputs, Level 2 | Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative liabilities		(759)
Other liabilities: Warrant	(1,418)	(629)
Total	$ (1,418)	$ (1,388)

Fair Value Measurements (Non-Re

Fair Value Measurements (Non-Recurring) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Market-based weighted average cost of capital rate	15.00%
Nonrecurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair value		$ 0
Asset impairments	$ 23,400,000
Seco Pipeline, LLC | Nonrecurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Asset impairments	900,000	$ 32,100,000
Fair Value, Inputs, Level 3 | Nonrecurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment	12,884,000
Total	12,884,000
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

Derivative And Financial Inst_3

Derivative And Financial Instruments (Changes In Fair Value) (Details) - Commodity Contract - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments Gain Loss [Line Items]
Beginning fair value of commodity derivatives	$ (759)	$ 3,914
Net gain (loss) on derivatives	3,901	(3,772)
Ending fair value of commodity derivatives		(759)
Oil reserves
Derivative Instruments Gain Loss [Line Items]
Net gain (loss) on derivatives	3,814	(4,031)
Net settlements received on derivative contracts	(2,829)	(807)
Natural gas
Derivative Instruments Gain Loss [Line Items]
Net gain (loss) on derivatives	87	259
Net settlements received on derivative contracts	$ (313)	$ (94)

Derivative And Financial Inst_4

Derivative And Financial Instruments (Effect On Statement Of Operations) (Details) - Commodity Contract - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Embedded Derivative [Line Items]
Net gain (loss) on derivatives	$ 3,901	$ (3,772)
Oil reserves
Embedded Derivative [Line Items]
Net gain (loss) on derivatives	3,814	(4,031)
Natural gas
Embedded Derivative [Line Items]
Net gain (loss) on derivatives	$ 87	$ 259

Debt (Details)

Debt (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Nov. 06, 2020USD ($)	Nov. 22, 2019USD ($)
Line of Credit Facility [Line Items]
Remaining borrowing capacity	$ 9,000
Letters of credit outstanding	0
Unamortized debt issue costs	800	$ 1,200
Amortization of debt issuance costs	767	$ 1,266
Letter of Credit
Line of Credit Facility [Line Items]
Maximum borrowing capacity				$ 155,000
Credit agreement, outstanding	105,000
Debt Instrument, Periodic Payment, Total	10,000
Revolving Loan
Line of Credit Facility [Line Items]
Maximum borrowing capacity	15,000		$ 17,500	$ 17,500
Credit agreement, outstanding	6,000
Revolving Loan | Borrowings limitation
Line of Credit Facility [Line Items]
Maximum borrowing capacity	15,000		$ 15,000
Credit Agreement
Line of Credit Facility [Line Items]
Maximum borrowing capacity	129,100
Sub-limit which may be used for issuance of letters of credit	2,500
Initial borrowing capacity	$ 235,500
Borrowing base term	45 days
Credit agreement, outstanding	$ 111,000
Commitment fee on unutilized borrowing base	0.50%
Credit Agreement | Letter of Credit
Line of Credit Facility [Line Items]
Line of Credit Facility, Periodic Payment	$ 10,000
Initial borrowing capacity	$ 155,000
Minimum | Credit Agreement
Line of Credit Facility [Line Items]
Ownership percentage by subsidiary	0.50
Required working capital ratio	1
Minimum | Credit Agreement | London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Variable interest rate	2.50%
Minimum | Credit Agreement | ABR
Line of Credit Facility [Line Items]
Variable interest rate	1.50%
Maximum | Credit Agreement | 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
Western Catarina Midstream | Maximum | Credit Agreement
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	3.5

Oil And Natural Gas Propertie_3

Oil And Natural Gas Properties And Related Equipment (Gathering and Transportation Assets) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Midstream assets	$ 187,977	$ 186,941
Less: Accumulated depreciation, amortization and impairment	(94,843)	(69,541)
Midstream
Property, Plant and Equipment [Line Items]
Midstream assets	187,977	186,941
Less: Accumulated depreciation, amortization and impairment	(82,710)	(74,648)
Total gathering and transportation assets, net	$ 105,267	$ 112,293

Oil And Natural Gas Propertie_4

Oil And Natural Gas Properties And Related Equipment (Properties) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Oil And Natural Gas Properties And Related Equipment.
Proved property	$ 112,471	$ 112,476
Less: Accumulated depreciation, depletion, amortization and impairments	(94,843)	(69,541)
Total oil and natural gas properties and equipment, net	$ 17,628	$ 42,935

Oil And Natural Gas Propertie_5

Oil And Natural Gas Properties And Related Equipment (DDA and Impairments) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Amortization of intangible assets	$ 13,460	$ 13,460
Depreciation, depletion and amortization	9,413	11,873
Asset impairments	24,222	32,119
Non-cash impairment charges	23,400	0
Exploration and dry hole costs	$ 0	0
Furniture and Equipment | Minimum
Property, Plant and Equipment [Line Items]
Useful lives	3 years
Furniture and Equipment | Maximum
Property, Plant and Equipment [Line Items]
Useful lives	15 years
Gathering Facilities | Maximum
Property, Plant and Equipment [Line Items]
Useful lives	36 years
Transportation assets | Maximum
Property, Plant and Equipment [Line Items]
Useful lives	40 years
Oil and Natural Gas-Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	$ 2,218	3,942
Gathering and Transportation Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	7,195	7,931
Oil and Natural Gas-Related Assets and Gathering and Transportation-Related Assets
Property, Plant and Equipment [Line Items]
Total Depreciation, depletion and amortization	22,873	25,333
Seco Pipeline, LLC
Property, Plant and Equipment [Line Items]
Asset impairments	$ 900
Non-cash impairment charges		$ 32,100

Provision For Income Taxes (Inc

Provision For Income Taxes (Income Tax Provision (Benefit)) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Current:
State	$ 128	$ 328
Total current	128	328
Deferred:
State	(104)	(126)
Total deferred	(104)	(126)
Provision for income taxes	$ 24	$ 202

Provision For Income Taxes (Rec

Provision For Income Taxes (Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Provision For Income Taxes
Pre-tax net book loss	$ (118,737)	$ (50,940)
Texas Margin Tax	36	126
Return to accrual	(12)	76
Provision for income taxes	$ 24	$ 202
Effective income tax rate	(0.02%)	(0.40%)

Provision For Income Taxes (DTA

Provision For Income Taxes (DTA and DTL) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Deferred tax assets (liabilities):
Derivative assets	$ (29)	$ (23)
Depreciable, depletable property, plant and equipment	129	21
Other	4	2
Deferred tax assets:	104
Deferred tax liabilities:
Total deferred tax liabilities
Total deferred tax assets	$ 104

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation
Asset retirement obligation, beginning balance	$ 6,898	$ 6,200
Liabilities added from escalating working interests		172
Accretion expense	567	526
Asset retirement obligation, ending balance	7,465	6,898
Legally restricted assets	$ 0	$ 0

Intangible Assets (Details)

Intangible Assets (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020USD ($)a	Dec. 31, 2019USD ($)
Finite-Lived Intangible Assets [Line Items]
Amortization of intangible assets	$ 13,460	$ 13,460
Beginning balance	145,246	158,706
Amortization	(13,460)	(13,460)
Ending balance	$ 131,786	$ 145,246
Customer Contracts
Finite-Lived Intangible Assets [Line Items]
Agreement term (in years)	15 years
Dedicated acreage | a	35,000
Useful life	15 years

Investments (Details)

Investments (Details) $ in Thousands	1 Months Ended				12 Months Ended
	May 31, 2018amiMMcf	Apr. 30, 2018MMcf	Nov. 30, 2016USD ($)	Jul. 31, 2016USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Schedule of Equity Method Investments [Line Items]
Earnings (loss) from equity investments					$ 4,479	$ 2,831
Amortization of intangible assets					13,460	13,460
Distributions received					15,266	$ 17,227
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
Daily processing capacity | MMcf	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
Daily processing capacity | MMcf	460	260
Number of miles of high pressure natural gas gathering pipelines | mi	45
Acres dedicated for gathering | a	315,000
Earnings (loss) from equity investments					5,700
Amortization of intangible assets					1,200
Distributions received					$ 15,300
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 | Carnero G&P, Joint Venture
Schedule of Equity Method Investments [Line Items]
Equity interests in plant transferred to joint venture (as a percent)	100.00%

Investments (Unconsolidated Ent

Investments (Unconsolidated Entities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Investments
Sales	$ 80,228	$ 159,508
Total expenses	63,121	145,837
Net income	$ 17,107	$ 13,671

Commitments And Contingencies (

Commitments And Contingencies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2020
Variable Interest Entity [Line Items]
Earnout derivative liability	$ 0	$ 0
Carnero Gathering, Joint Venture
Variable Interest Entity [Line Items]
Earnout payments	$ 32,000

Related Party Transactions (Det

Related Party Transactions (Details)	Mar. 16, 2021shares	Feb. 25, 2021USD ($)shares	Feb. 01, 2021USD ($)shares	Aug. 02, 2019	Jun. 30, 2020shares	Mar. 31, 2020shares	Dec. 31, 2019USD ($)shares	Sep. 30, 2019shares	Jun. 30, 2019shares	Dec. 31, 2020USD ($)director$ / shares	Jun. 29, 2020
Related Party Transaction [Line Items]
Long term accrued liabilities - related entities							$ 4,892,000			$ 12,137,000
JT3 Consulting Agreement | Fee Paid Monthly
Related Party Transaction [Line Items]
Consulting fee										$ 20,000
Stonepeak Catarina
Related Party Transaction [Line Items]
Directors that are representatives of related party | director										4
Ownership percentage threshold for right to exercise limited call right										80.00%
Exercise of limited call right, scenario of price based on stock closing price during number of trading days										20 days
Exercise of limited call right, scenario of price based on highest price paid during number of days preceding date of notice										90 days
SP Holdings | Shared Services Agreement
Related Party Transaction [Line Items]
Quarterly fee (as a percent)										0.375%
Maximum asset acquisition, disposition and financing fee (as a percent)										2.00%
Number of days after delivery within which payment of accrued fees has to be made										30 days
Agreement term (in years)										10 years
Services Agreement renewal term										10 years
Agreement notice of termination period										180 days
Related parties, payable							$ 7,300,000			$ 7,200,000
SP Holdings | Shared Services Agreement | Scenario if agreement terminated
Related Party Transaction [Line Items]
Termination fee										5,000,000
Termination fee plus applicable percentage of asset acquisitions										$ 35,000,000
Transaction value, percentage										5.00%
SP Holdings | Stonepeak Catarina | Subsequent event
Related Party Transaction [Line Items]
Units owned by third party, (as a percentage)	100.00%
Common units | Subsequent event
Related Party Transaction [Line Items]
Units distribution (in units) | shares		12,445,491	22,274,869
Common units | Stonepeak Catarina | Subsequent event
Related Party Transaction [Line Items]
Units owned (in units) | shares	39,623,443
Units owned by third party, (as a percentage)	72.70%
Units distribution (in units) | shares			22,274,869
Units distribution value		$ 12,900,000	$ 12,900,000
Common units | Mesquite Energy, Inc. and certain other members of the Sanchez family
Related Party Transaction [Line Items]
Units owned by minority interest (as a percentage)											24.30%
Junior Securities | Stonepeak Catarina | Subsequent event
Related Party Transaction [Line Items]
Units owned by third party, (as a percentage)	10.00%
Junior Securities | Stonepeak Catarina
Related Party Transaction [Line Items]
Date from which warrant is exercisable										Aug. 2, 2019
Number of days within which warrants or rights are exercisable										30 days
Warrant, stated percentage of securities class redeemable										10.00%
Warrant exercise price | $ / shares										$ 0
Class C preferred units
Related Party Transaction [Line Items]
Units distribution (in units) | shares					1,105,286	1,071,793	1,039,314	1,007,820	939,327
Class B preferred units | Stonepeak Catarina
Related Party Transaction [Line Items]
Units owned by third party, (as a percentage)				61.70%

Unit-Based Compensation (Detail

Unit-Based Compensation (Details) - $ / shares	1 Months Ended		12 Months Ended
	Apr. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019
LTIP
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units available for issuance			974,393
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding			1,155,467	513,694
Number of Restricted Units, Granted				1,129,173
Number of Restricted Units, Vested			(338,840)	(382,690)
Number of Restricted Units, Returned/Cancelled			(133,456)	(104,710)
Number of Restricted Units, Outstanding			683,171	1,155,467
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding			$ 3.86	$ 12.31
Weighted Averaged Grant Date Fair Value Per Unit, Granted				2.35
Weighted Averaged Grant Date Fair Value Per Unit, Vested			5.14	8.50
Weighted Averaged Grant Date Fair Value Per Unit, Returned/Cancelled			5.61	12.04
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding			$ 2.68	$ 3.86
Restricted Stock Units (RSUs) | Directors
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted	137,613
Restricted Stock Units (RSUs) | Executives
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period		3 years
Restricted Stock Units (RSUs) | Officers and Directors
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted		991,560

Distributions To Unitholders (D

Distributions To Unitholders (Details) - $ / shares	Feb. 25, 2021	Feb. 01, 2021	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019
Common units
Distribution paid per unit								$ 0.1500
Common units | Subsequent event
Units distribution (in units)	12,445,491	22,274,869
Class C preferred units
Units distribution (in units)			1,105,286	1,071,793	1,039,314	1,007,820	939,327

Partners' Capital (Details)

Partners' Capital (Details) - USD ($) $ / shares in Units, $ in Millions	Jan. 25, 2017	Oct. 14, 2015	Dec. 31, 2020	Dec. 31, 2019	Dec. 06, 2016
Limited Partners' Capital Account [Line Items]
Common units, outstanding			19,953,880	20,087,462
Units, issued			19,953,880	20,087,462
Class B preferred units
Limited Partners' Capital Account [Line Items]
Class B preferred units, outstanding			0
Units sold (in units)		19,444,445
Price per unit sold		$ 18
Proceeds from preferred units sold		$ 350
Percent of consideration paid		2.25%
Class B preferred units, issued					9,851,996
Class B preferred units | Settlement Agreement with Stonepeak Catarina Holdings LLC
Limited Partners' Capital Account [Line Items]
Class B preferred units, issued	1,704,446
Class B preferred units, unit price	$ 11.29
Class C preferred units
Limited Partners' Capital Account [Line Items]
Class C preferred units, outstanding			36,474,436
Common units
Limited Partners' Capital Account [Line Items]
Common units, outstanding			19,953,880
Unvested restricted common units
Limited Partners' Capital Account [Line Items]
Common units, outstanding			683,171

Partners' Capital (Preferred Un

Partners' Capital (Preferred Units) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Distributions		$ 17,675
Class C Preferred Units, beginning balance	$ 281,688
Class C Preferred Units, ending balance		281,688
Class B preferred units
Mezzanine equity, beginning balance	0	349,857
Amortization of discount		1,708
Distributions		23,247
Distributions paid		(17,675)
Class B Preferred Unit exchange		(357,137)
Mezzanine equity, ending balance		0
Class C preferred units
Deemed contribution from exchange	103,800
Class C Preferred Units, beginning balance	281,688
Private placement of Class C Preferred Units	0	353,500
Discount	0	(104,250)
Accretion of discount	38,938	13,129
Distribution accrual	24,579	19,309
Class C Preferred Units, ending balance	$ 345,205	$ 281,688
Warrant exercise period	30 days
Class C preferred units | Distribution period commencing with the quarter ended on September 30, 2019
Distributions (as a percent)	12.50%
Class C preferred units | Distribution period commencing with the quarter ending March 31, 2022
Distributions (as a percent)	14.00%

Reporting Segments (Segment Inf

Reporting Segments (Segment Information) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Segment operating revenues:
Gathering and transportation lease revenues	$ 44,671	$ 59,090
Total revenues	56,993	76,649
Segment operating costs:
Lease operating expenses	6,224	7,378
Transportation operating expenses	9,314	11,553
Production taxes	311	621
Depreciation, depletion and amortization	22,873	25,333
Asset impairments	24,222	32,119
Accretion expense	567	526
Total operating expenses	84,409	96,491
Segment other income
Earnings (loss) from equity investments	4,479	2,831
Segment operating income (loss)	(2,039)	1,950
Midstream
Segment operating revenues:
Gathering and transportation lease revenues	44,671	59,090
Total revenues	45,456	65,915
Segment operating costs:
Lease operating expenses	884	1,499
Transportation operating expenses	9,314	11,553
Depreciation, depletion and amortization	20,655	21,391
Asset impairments	867	32,119
Accretion expense	355	326
Total operating expenses	32,075	66,888
Segment other income
Earnings (loss) from equity investments	4,479	2,831
Total segment other income	4,479	2,831
Segment operating income (loss)	17,860	1,858
Production
Segment operating revenues:
Total revenues	11,537	10,734
Segment operating costs:
Lease operating expenses	5,340	5,879
Production taxes	311	621
Depreciation, depletion and amortization	2,218	3,942
Asset impairments	23,355
Accretion expense	212	200
Total operating expenses	31,436	10,642
Segment other income
Segment operating income (loss)	(19,899)	92
Natural gas sales
Segment operating revenues:
Revenues	427	683
Natural gas sales | Production
Segment operating revenues:
Revenues	427	683
Oil sales
Segment operating revenues:
Revenues	10,856	9,512
Oil sales | Production
Segment operating revenues:
Revenues	10,856	9,512
Natural gas liquid sales
Segment operating revenues:
Revenues	254	539
Natural gas liquid sales | Production
Segment operating revenues:
Revenues	254	539
Gathering and transportation sales
Segment operating revenues:
Revenues	785	6,825
Gathering and transportation sales | Midstream
Segment operating revenues:
Revenues	$ 785	$ 6,825

Reporting Segments - Reconcilia

Reporting Segments - Reconciliation of Segment Operating Income (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Reconciliation of segment operating income (loss) to net loss
Segment operating income (loss)	$ (2,039)	$ 1,950
General and administrative expenses	(18,296)	(17,610)
Unit-based compensation expense	(2,602)	(1,351)
Interest expense, net	(95,871)	(39,789)
Other income	71	5,860
Income tax expense	(24)	(202)
Net loss	(118,761)	(51,142)
Midstream
Reconciliation of segment operating income (loss) to net loss
Segment operating income (loss)	17,860	1,858
Production
Reconciliation of segment operating income (loss) to net loss
Segment operating income (loss)	$ (19,899)	$ 92

Reporting Segments (Assets by S

Reporting Segments (Assets by Segment) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 353,428	$ 414,440
Capital expenditures	1,938	905
Production
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	19,242	45,550
Capital expenditures	(5)	130
Midstream
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	331,926	362,961
Capital expenditures	1,943	775
Corporate
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 2,260	$ 5,929

Reporting Segments (Percentage

Reporting Segments (Percentage of Revenue) (Details) - Revenue - Customer Concentration Risk - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenue, Major Customer [Line Items]
Number of major customers	0	0
Mesquite Energy, Inc.
Revenue, Major Customer [Line Items]
Concentration risk, percentage of revenue	80.00%	86.00%
Midstream | Mesquite Energy, Inc.
Revenue, Major Customer [Line Items]
Concentration risk, percentage of revenue	80.00%	86.00%

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Jul. 31, 2016	Dec. 31, 2020	Dec. 31, 2019
Variable Interest Entity [Line Items]
Acquisitions, earnout and capital investments		$ 128,251	$ 128,140
Earnings in equity investments		30,455	25,976
Distributions received		(69,071)	(53,805)
Maximum exposure to loss		89,635	$ 100,311
Carnero Gathering, Joint Venture
Variable Interest Entity [Line Items]
Payments to acquire interest in joint venture	$ 37,000	124,200
Debt incurred		0
Maximum exposure to loss		$ 89,600

Supplemental Information On O_3

Supplemental Information On Oil And Natural Gas Producing Activities (Capitalized Costs) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Supplemental Information On Oil And Natural Gas Producing Activities
Proved property	$ 112,471	$ 112,476
Less: accumulated depreciation, depletion, amortization and impairments	(94,843)	(69,541)
Oil and natural gas properties and equipment, net	$ 17,628	$ 42,935

Supplemental Information On O_4

Supplemental Information On Oil And Natural Gas Producing Activities (Costs Incurred Production) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Supplemental Information On Oil And Natural Gas Producing Activities
Development costs	$ 131
Oil and natural gas properties and equipment, net	$ 131

Supplemental Information On O_5

Supplemental Information On Oil And Natural Gas Producing Activities (Proved Reserves) (Details) - MMBoe	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Changes in proved developed and undeveloped reserves
Balance	2,999	3,453
Revisions of previous estimates	(475)	(145)
Production	(241)	(309)
Balance	2,283	2,999
Proved developed reserves	2,283	2,999
Oil reserves
Changes in proved developed and undeveloped reserves
Balance	2,241	2,479
Revisions of previous estimates	(334)	(10)
Production	(191)	(228)
Balance	1,716	2,241
Proved developed reserves	1,716	2,241
Natural gas
Changes in proved developed and undeveloped reserves
Balance	348	454
Revisions of previous estimates	(35)	(67)
Production	(26)	(39)
Balance	287	348
Proved developed reserves	287	348
Natural gas liquids
Changes in proved developed and undeveloped reserves
Balance	410	520
Revisions of previous estimates	(106)	(68)
Production	(24)	(42)
Balance	280	410
Proved developed reserves	280	410

Supplemental Information On O_6

Supplemental Information On Oil And Natural Gas Producing Activities (Proved Reserves Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)MMBoe$ / Mcf$ / bbl	Dec. 31, 2019USD ($)MMBoe$ / Mcf$ / bbl	Dec. 31, 2018MMBoe
Reserve Quantities [Line Items]
Exploration and dry hole costs | $	$ 0	$ 0
Proved reserve estimates	2,283	2,999	3,453
Reserve revision	2,283	2,999
Increase (decrease) in proved reserve estimates	0.7	0.5
Production	(241)	(309)
Revisions of previous estimates	(475)	(145)
Oil reserves
Reserve Quantities [Line Items]
Proved reserve estimates	1,716	2,241	2,479
Reserve revision	1,716	2,241
Production	(191)	(228)
Revisions of previous estimates	(334)	(10)
Weighted-average product price | $ / bbl	37.70	59.55
Natural gas
Reserve Quantities [Line Items]
Proved reserve estimates	287	348	454
Reserve revision	287	348
Production	(26)	(39)
Revisions of previous estimates	(35)	(67)
Weighted-average product price	10.69	2.66
Natural gas liquids
Reserve Quantities [Line Items]
Proved reserve estimates	280	410	520
Reserve revision	280	410
Production	(24)	(42)
Revisions of previous estimates	(106)	(68)
Weighted-average product price	2.02	13.68

Supplemental Information On O_7

Supplemental Information On Oil And Natural Gas Producing Activities (Standardized Measure) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Supplemental Information On Oil And Natural Gas Producing Activities
Future cash inflows	$ 71,161	$ 144,628
Future production costs	(50,809)	(80,007)
Future estimated development costs	(3,614)	(3,400)
Future net cash flows	16,738	61,221
10% annual discount for estimated timing of cash flows	(4,857)	(22,871)
Standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves	$ 11,881	$ 38,350	$ 52,246

Supplemental Information On O_8

Supplemental Information On Oil And Natural Gas Producing Activities (Change Standardized Measure) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Supplemental Information On Oil And Natural Gas Producing Activities
Beginning of the period	$ 38,350	$ 52,246
Sales and transfers of oil and natural gas, net of production costs	(1,985)	(8,006)
Net changes in prices and production costs related to future production	(27,157)	(7,330)
Changes in development costs	(595)	35
Revisions of previous quantity estimates	(2,652)	(1,942)
Accretion discount	3,835	5,225
Change in production rates, timing, and other	2,085	(1,878)
Standardized measure of discounted future net cash flows related to proved oil and natural gas reserves	$ 11,881	$ 38,350

Subsequent Events (Details)

Subsequent Events (Details) - shares	Feb. 25, 2021	Feb. 01, 2021
Subsequent event | Common units
Subsequent Event [Line Items]
Units distribution (in units)	12,445,491	22,274,869