Black Stone Minerals (BSM) 10-Q 4 May 21 2021 Q1 Quarterly report Financial data

Cover

Cover - shares	3 Months Ended
	Mar. 31, 2021	Apr. 30, 2021
Entity Information [Line Items]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2021
Document Transition Report	false
Entity File Number	001-37362
Entity Registrant Name	Black Stone Minerals, L.P.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	47-1846692
Entity Address, Address Line One	1001 Fannin Street, Suite 2020
Entity Address, City or Town	Houston,
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	(713)
Local Phone Number	445-3200
Title of 12(b) Security	Common Units Representing Limited Partner Interests
Trading Symbol	BSM
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Smaller reporting company	false
Emerging growth company	false
Entity shell company	false
Amendment Flag	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q1
Entity Central Index Key	0001621434
Current Fiscal Year End Date	--12-31
Common units
Entity Information [Line Items]
Entity Partnership Units Outstanding (in shares)		207,552,011
Preferred Units
Entity Information [Line Items]
Entity Partnership Units Outstanding (in shares)		14,711,219

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
CURRENT ASSETS
Cash and cash equivalents	$ 3,789	$ 1,796
Accounts receivable	59,288	61,908
Commodity derivative assets	315	1,149
Prepaid expenses and other current assets	1,393	1,668
TOTAL CURRENT ASSETS	64,785	66,521
PROPERTY AND EQUIPMENT
Oil and natural gas properties, at cost, using the successful efforts method of accounting, includes unproved properties of $937,464 at March 31, 2021 and December 31, 2020	3,164,065	3,157,818
Accumulated depreciation, depletion, amortization, and impairment	(2,009,867)	(1,987,332)
Oil and natural gas properties, net	1,154,198	1,170,486
Other property and equipment, net of accumulated depreciation of $12,453 and $12,292 at March 31, 2021 and December 31, 2020, respectively	1,492	1,650
NET PROPERTY AND EQUIPMENT	1,155,690	1,172,136
DEFERRED CHARGES AND OTHER LONG-TERM ASSETS	5,674	5,321
TOTAL ASSETS	1,226,149	1,243,978
CURRENT LIABILITIES
Accounts payable	2,219	3,407
Accrued liabilities	8,382	15,568
Commodity derivative liabilities	44,447	19,318
Other current liabilities	1,736	1,654
TOTAL CURRENT LIABILITIES	56,784	39,947
LONG–TERM LIABILITIES
Credit facility	111,000	121,000
Accrued incentive compensation	243	766
Commodity derivative liabilities	0	1,848
Asset retirement obligations	17,503	17,377
Other long-term liabilities	3,829	4,073
TOTAL LIABILITIES	189,359	185,011
COMMITMENTS AND CONTINGENCIES (Note 7)
EQUITY
Partners' equity – general partner interest	0	0
TOTAL EQUITY	738,429	760,606
TOTAL LIABILITIES, MEZZANINE EQUITY, AND EQUITY	1,226,149	1,243,978
Series B Cumulative Convertible Preferred Units
MEZZANINE EQUITY
Partners' equity – convertible preferred units	298,361	298,361
Common units
EQUITY
Partners' equity – common units, 207,542 and 206,749 units outstanding at March 31, 2021 and December 31, 2020, respectively	$ 738,429	$ 760,606

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) shares in Thousands, $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Unproved properties	$ 937,464	$ 937,464
Accumulated depreciation	$ 12,453	$ 12,292
Series B Cumulative Convertible Preferred Units
Partners' equity, preferred units, outstanding (in shares)	14,711	14,711
Common units
Partners' equity - units, outstanding (in shares)	207,542	206,749

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
REVENUE
Revenue from contracts with customers	$ 89,450,000	$ 93,043,000
Gain (loss) on commodity derivative instruments	(27,882,000)	90,011,000
TOTAL REVENUE	61,568,000	183,054,000
OPERATING (INCOME) EXPENSE
Lease operating expense	2,664,000	3,827,000
Production costs and ad valorem taxes	11,842,000	12,376,000
Exploration expense	1,073,000	1,000
Depreciation, depletion, and amortization	15,632,000	23,182,000
Impairment of oil and natural gas properties	0	51,031,000
General and administrative	12,852,000	11,856,000
Accretion of asset retirement obligations	292,000	272,000
TOTAL OPERATING EXPENSE	44,355,000	102,545,000
INCOME (LOSS) FROM OPERATIONS	17,213,000	80,509,000
OTHER INCOME (EXPENSE)
Interest and investment income	0	31,000
Interest expense	(1,210,000)	(4,427,000)
Other income (expense)	183,000	(1,000)
TOTAL OTHER EXPENSE	(1,027,000)	(4,397,000)
NET INCOME (LOSS)	16,186,000	76,112,000
Distributions on Series B cumulative convertible preferred units	(5,250,000)	(5,250,000)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	10,936,000	70,862,000
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0
Common units	10,936,000	70,862,000
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$ 10,936,000	$ 70,862,000
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic) (in dollars per share)	$ 0.05	$ 0.34
Per common unit (diluted) (in dollars per share)	$ 0.05	$ 0.34
Weighted average common units outstanding (basic) (in shares)	207,442	206,631
Weighted average common units outstanding (diluted) (in shares)	207,442	206,631
Oil and condensate sales
REVENUE
Revenue from contracts with customers	$ 44,176,000	$ 52,093,000
Natural gas and natural gas liquids sales
REVENUE
Revenue from contracts with customers	42,889,000	36,642,000
Lease bonus and other income
REVENUE
Revenue from contracts with customers	$ 2,385,000	$ 4,308,000

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) shares in Thousands, $ in Thousands	Total	Common units	Partners' equity — common units	Series B cumulative convertible preferred units on an as-converted basis	Series B cumulative convertible preferred units on an as-converted basisPartners' equity — common units
Beginning balance (in shares) at Dec. 31, 2019		205,960
Beginning balance at Dec. 31, 2019	$ 798,443		$ 798,443
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Repurchases of common units (in shares)		(503)
Repurchases of common units	(5,029)		(5,029)
Restricted units granted, net of forfeitures (in shares)		1,238
Equity–based compensation	1,159		1,159
Distributions	(61,641)		(61,641)
Charges to partners' equity for accrued distribution equivalent rights	(68)		(68)
Distributions on Series B cumulative convertible preferred units				$ (5,250)	$ (5,250)
Net income (loss)	76,112		76,112
Ending balance (in shares) at Mar. 31, 2020		206,695
Ending balance at Mar. 31, 2020	803,726		803,726
Beginning balance (in shares) at Dec. 31, 2020		206,749
Beginning balance at Dec. 31, 2020	760,606		760,606
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Repurchases of common units (in shares)		(223)
Repurchases of common units	(1,957)		(1,957)
Restricted units granted, net of forfeitures (in shares)		1,016
Equity–based compensation	5,353		5,353
Distributions	(36,272)		(36,272)
Charges to partners' equity for accrued distribution equivalent rights	(237)		(237)
Distributions on Series B cumulative convertible preferred units				$ (5,250)	$ (5,250)
Net income (loss)	16,186		16,186
Ending balance (in shares) at Mar. 31, 2021		207,542
Ending balance at Mar. 31, 2021	$ 738,429		$ 738,429

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$ 16,186,000	$ 76,112,000
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization	15,632,000	23,182,000
Impairment of oil and natural gas properties	0	51,031,000
Accretion of asset retirement obligations	292,000	272,000
Amortization of deferred charges	257,000	260,000
(Gain) loss on commodity derivative instruments	27,882,000	(90,011,000)
Net cash (paid) received on settlement of commodity derivative instruments	(4,523,000)	8,954,000
Equity-based compensation	3,462,000	(2,894,000)
Exploratory dry hole expense	1,049,000	0
Changes in operating assets and liabilities:
Accounts receivable	2,620,000	19,693,000
Prepaid expenses and other current assets	275,000	(827,000)
Accounts payable, accrued liabilities, and other	(7,341,000)	(14,269,000)
Settlement of asset retirement obligations	(105,000)	(53,000)
NET CASH PROVIDED BY OPERATING ACTIVITIES	55,686,000	71,450,000
CASH FLOWS FROM INVESTING ACTIVITIES
Acquisitions of oil and natural gas properties	0	(28,000)
Additions to oil and natural gas properties	(191,000)	(3,548,000)
Additions to oil and natural gas properties leasehold costs	(21,000)	0
Purchases of other property and equipment	(2,000)	(2,000)
Proceeds from the sale of oil and natural gas properties	0	1,266,000
Proceeds from farmouts of oil and natural gas properties	0	3,703,000
NET CASH PROVIDED BY (USED IN) INVESTING ACTIVITIES	(214,000)	1,391,000
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under credit facility	39,000,000	67,000,000
Repayments under credit facility	(49,000,000)	(73,000,000)
NET CASH USED IN FINANCING ACTIVITIES	(53,479,000)	(77,920,000)
NET CHANGE IN CASH AND CASH EQUIVALENTS	1,993,000	(5,079,000)
CASH AND CASH EQUIVALENTS – beginning of the period	1,796,000	8,119,000
CASH AND CASH EQUIVALENTS – end of the period	3,789,000	3,040,000
SUPPLEMENTAL DISCLOSURE
Interest paid	941,000	4,173,000
Common units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	(36,272,000)	(61,641,000)
Repurchases of common units	(1,957,000)	(5,029,000)
Series B cumulative convertible preferred units on an as-converted basis | Preferred Units
CASH FLOWS FROM FINANCING ACTIVITIES
Distributions to unitholders	$ (5,250,000)	$ (5,250,000)

BUSINESS AND BASIS OF PRESENTAT

BUSINESS AND BASIS OF PRESENTATION	3 Months Ended
	Mar. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
BUSINESS AND BASIS OF PRESENTATION	NOTE 1 - BUSINESS AND BASIS OF PRESENTATION Description of the Business Black Stone Minerals, L.P. (“BSM” or the “Partnership”) is a publicly traded Delaware limited partnership that owns oil and natural gas mineral interests, which make up the vast majority of the asset base. The Partnership's assets also include nonparticipating royalty interests and overriding royalty interests. These interests, which are substantially non-cost-bearing, are collectively referred to as “mineral and royalty interests.” The Partnership’s mineral and royalty interests are located in 41 states in the continental United States ("U.S."), including all of the major onshore producing basins. The Partnership also owns non-operated working interests in certain oil and natural gas properties. The Partnership's common units trade on the New York Stock Exchange under the symbol "BSM." Basis of Presentation The accompanying unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles ("GAAP") in the United States and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2020 ("2020 Annual Report on Form 10-K"). The unaudited interim consolidated financial statements include the consolidated results of the Partnership. The results of operations for the three months ended March 31, 2021 are not necessarily indicative of the results to be expected for the full year. In the opinion of management, all adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. All intercompany balances and transactions have been eliminated. The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for using fair value or cost minus impairment if fair value is not readily determinable. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income (loss) and equity. The unaudited interim consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying unaudited interim consolidated balance sheets, statements of operations, and statements of cash flows. Segment Reporting The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	3 Months Ended
	Mar. 31, 2021
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Significant Accounting Policies Significant accounting policies are disclosed in the Partnership’s 2020 Annual Report on Form 10-K. There have been no changes in such policies or the application of such policies during the three months ended March 31, 2021. Accounts Receivable The following table presents information about the Partnership's accounts receivable: March 31, 2021 December 31, 2020 (in thousands) Accounts receivable: Revenues from contracts with customers $ 55,297 $ 58,181 Other 3,991 3,727 Total accounts receivable $ 59,288 $ 61,908

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES	3 Months Ended
	Mar. 31, 2021
Business Combinations [Abstract]
OIL AND NATURAL GAS PROPERTIES	NOTE 3 - OIL AND NATURAL GAS PROPERTIES Divestitures In the third quarter of 2020, the Partnership closed two separate divestitures of certain mineral and royalty properties in the Permian Basin for total proceeds, after closing adjustments, of $150.6 million. One of these transactions, effective May 1, 2020, involved the sale of the Partnership's mineral and royalty interest in specific tracts in Midland County, Texas for net proceeds of approximately $54.5 million. The other transaction, effective July 1, 2020, involved the sale of an undivided interest across parts of the Partnership's Delaware Basin and Midland Basin positions for net proceeds of approximately $96.1 million. The total book value of the assets divested through these transactions was $126.6 million at the time of sale. The Partnership recognized a $24.0 million gain associated with the divestitures in the third quarter of 2020. Farmout Agreements In 2017, the Partnership entered into two farmout arrangements designed to reduce its working interest capital expenditures and thereby significantly lower its capital spending other than for mineral and royalty interest acquisitions. Under these agreements, the Partnership conveyed its rights to participate in certain non-operated working interest opportunities to external capital providers while retaining value from these interests in the form of additional royalty income or retained economic interests. Canaan Farmout In February 2017, the Partnership entered into a farmout agreement with Canaan Resource Partners ("Canaan") which covers certain Haynesville and Bossier shale acreage in San Augustine County, Texas operated by XTO Energy Inc. ("XTO"), a subsidiary of Exxon Mobil Corporation. The Partnership has an approximate 50% working interest in the acreage and is the largest mineral owner. During the first three phases of the farmout agreement, Canaan commits on a phase-by-phase basis and funds 80% of the Partnership's drilling and completion costs and is assigned 80% of the Partnership's working interests in such wells (40% working interest on an 8/8ths basis) as the wells are drilled. After the third phase, Canaan can earn 40% of the Partnership’s working interest (20% working interest on an 8/8ths basis) in additional wells drilled in the area by continuing to fund 40% of the Partnership's costs for those wells on a well-by-well basis. The Partnership receives an ORRI before payout and an increased ORRI after payout on all wells drilled under the agreement . Canaan has participated in a total of 37 wells under the farmout agreement through March 31, 2021, covering two election phases. In 2019, XTO Energy Inc. suspended its development activities in the area due to low natural gas prices. Canaan has the right to elect to continue its participation in a third phase covering up to 20 future wells drilled under the farmout agreement should XTO resume drilling activity. Pivotal Farmout In November 2017, the Partnership entered into a farmout agreement (the "First Pivotal Farmout") with Pivotal Petroleum Partners (“Pivotal”), a portfolio company of Tailwater Capital, LLC. The farmout agreement covers substantially all of the Partnership's remaining working interests in wells operated by XTO Energy and BPX Energy in the Shelby Trough area of East Texas targeting the Haynesville and Bossier shale acreage (after giving effect to the Canaan Farmout), until November 2025. Pivotal is obligated to fund the development of up to 80 wells, in designated well groups, across several development areas and then has options to continue funding the Partnership's working interest across those areas for the duration of the farmout agreement. Once Pivotal achieves a specified payout for a designated well group, the Partnership will obtain a majority of the original working interest in such well group. As of March 31, 2021, a total of 68 wells have been spud in the contract area subject to the First Pivotal Farmout. The Partnership's development agreement with BPX Energy terminated in 2019 with respect to the majority of the Partnership's acreage covered by the agreement. As such, Pivotal retains minimal rights or obligations related to the farmout for that area that remains subject to the First Pivotal Farmout. In the second quarter of 2020, the Partnership entered into a development agreement with Aethon Energy ("Aethon") to develop certain portions of the area forfeited by BPX Energy in Angelina County, Texas. The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to our mineral and leasehold acreage in the contract area. The agreement calls for a minimum of four wells to be drilled in the initial program year, which began in the third quarter of 2020, increasing to a minimum of 15 wells per year beginning with the third program year. In November 2020, the Partnership entered into a new farmout agreement (the "Second Pivotal Farmout") with Pivotal. The Second Pivotal Farmout supersedes and replaces the First Pivotal Farmout with respect to the area covered by the Aethon development agreement. The Second Pivotal Farmout covers the Partnership's share of working interest under active development by Aethon in Angelina County, Texas and continues until April 2028, unless earlier terminated in accordance to the terms of the agreement. Pivotal will earn 100% of the Partnership's working interest (ranging from approximately 12.5% to 25% on an 8/8ths basis) in wells drilled and operated by Aethon in accordance with the development agreement. Pivotal is obligated to fund the development of all wells drilled by Aethon in the initial program year and thereafter, Pivotal has certain rights and options to continue funding the Partnership's working interests for the duration of the Second Pivotal Farmout. Once Pivotal achieves a specified payout for a designated well group, the Partnership will obtain a majority of the original working interest in such well group. As of March 31, 2021, a total of two wells have been spud in the contract area subject to the Second Pivotal Farmout. From the inception of the farmout agreements through March 31, 2021, the Partnership has received $90.2 million and $119.2 million from Canaan and Pivotal, respectively, under the agreements. When such reimbursements are received prior to assigning the wells to Canaan and Pivotal, the Partnership records the amounts as increases to Oil and natural gas properties and Other long-term liabilities. When working interests in farmout wells are assigned to Canaan and Pivotal, the Partnership's Oil and natural gas properties and Other long-term liabilities are reduced by the reimbursed capital costs. As of March 31, 2021 and December 31, 2020, $0.1 million was included in the Other long-term liabilities line item of the consolidated balance sheets for reimbursements received associated with farmed-out working interests not yet assigned to Canaan and Pivotal. XTO Completions Agreement In June 2020, the Partnership entered into a new incentive agreement with XTO with respect to certain drilled but uncompleted wells ("DUCs") in the Shelby Trough. The agreement allowed for royalty relief on 13 existing DUCs if XTO completed and turned the wells to sales by March 31, 2021. As of January 18, 2021, XTO had turned all 13 DUCs to sales. Impairment of Oil and Natural Gas Properties Proved and unproved oil and natural gas properties are reviewed for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of those properties. When assessing producing properties for impairment, the Partnership compares the expected undiscounted projected future cash flows of the producing properties to the carrying amount of the producing properties to determine recoverability. When the carrying amount exceeds its estimated undiscounted future cash flows, the carrying amount is written down to its fair value, which is measured as the present value of the projected future cash flows of such properties.

COMMODITY DERIVATIVE FINANCIAL

COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS	3 Months Ended
	Mar. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS	NOTE 4 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS The Partnership’s ongoing operations expose it to changes in the market price for oil and natural gas. To mitigate the inherent commodity price risk associated with its operations, the Partnership uses oil and natural gas commodity derivative financial instruments. From time to time, such instruments may include variable-to-fixed-price swaps, costless collars, fixed-price contracts and other contractual arrangements. The Partnership enters into oil and natural gas derivative contracts that contain netting arrangements with each counterparty. The Partnership does not enter into derivative instruments for speculative purposes. As of March 31, 2021, the Partnership’s open derivative contracts consisted of fixed-price swap contracts. A fixed-price swap contract between the Partnership and the counterparty specifies a fixed commodity price and a future settlement date. The Partnership has not designated any of its contracts as fair value or cash flow hedges. Accordingly, the changes in the fair value of the contracts are included in the consolidated statement of operations in the period of the change. All derivative gains and losses from the Partnership’s derivative contracts have been recognized in revenue in the Partnership's accompanying consolidated statements of operations. Derivative instruments that have not yet been settled in cash are reflected as either derivative assets or liabilities in the Partnership’s accompanying consolidated balance sheets as of March 31, 2021 and December 31, 2020. See Note 5 - Fair Value Measurements for further discussion. The Partnership's derivative contracts expose it to credit risk in the event of nonperformance by counterparties that may adversely impact the fair value of the Partnership's commodity derivative assets. While the Partnership does not require its derivative contract counterparties to post collateral, the Partnership does evaluate the credit standing of such counterparties as deemed appropriate. This evaluation includes reviewing a counterparty’s credit rating and latest financial information. As of March 31, 2021, the Partnership had seven counterparties, all of which are rated Baa1 or better by Moody’s and are lenders under the Credit Facility. The tables below summarize the fair values and classifications of the Partnership’s derivative instruments, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheets as of each date: March 31, 2021 Classification Balance Sheet Location Gross Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 1,573 $ (1,258) $ 315 Long-term asset Deferred charges and other long-term assets 756 — 756 Total assets $ 2,329 $ (1,258) $ 1,071 Liabilities: Current liability Commodity derivative liabilities $ 45,705 $ (1,258) $ 44,447 Long-term liability Commodity derivative liabilities — — — Total liabilities $ 45,705 $ (1,258) $ 44,447 December 31, 2020 Classification Balance Sheet Location Gross Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 6,362 $ (5,213) $ 1,149 Long-term asset Deferred charges and other long-term assets — — — Total assets $ 6,362 $ (5,213) $ 1,149 Liabilities: Current liability Commodity derivative liabilities $ 24,531 $ (5,213) $ 19,318 Long-term liability Commodity derivative liabilities 1,848 — 1,848 Total liabilities $ 26,379 $ (5,213) $ 21,166 Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations and consolidated statements of cash flows and consist of the following for the periods presented: Three Months Ended March 31, Derivatives not designated as hedging instruments 2021 2020 (in thousands) Beginning fair value of commodity derivative instruments $ (20,017) $ 15,221 Gain (loss) on oil derivative instruments (24,854) 77,811 Gain (loss) on natural gas derivative instruments (3,028) 12,200 Net cash paid (received) on settlements of oil derivative instruments 4,502 (1,541) Net cash paid (received) on settlements of natural gas derivative instruments 21 (7,413) Net change in fair value of commodity derivative instruments (23,359) 81,057 Ending fair value of commodity derivative instruments $ (43,376) $ 96,278 The Partnership had the following open derivative contracts for oil as of March 31, 2021: Weighted Average Price (Per Bbl) Range (Per Bbl) Period and Type of Contract Volume (Bbl) Low High Oil Swap Contracts: 2021 First Quarter 220,000 $ 38.97 $ 32.64 $ 46.50 Second Quarter 660,000 38.97 32.64 46.50 Third Quarter 660,000 38.97 32.64 46.50 Fourth Quarter 660,000 38.97 32.64 46.50 2022 First Quarter 150,000 $ 55.47 $ 55.29 $ 56.10 Second Quarter 150,000 55.47 55.29 56.10 Third Quarter 150,000 55.47 55.29 56.10 Fourth Quarter 150,000 55.47 55.29 56.10 The Partnership had the following open derivative contracts for natural gas as of March 31, 2021: Weighted Average Price (Per MMBtu) Range (Per MMBtu) Period and Type of Contract Volume (MMBtu) Low High Natural Gas Swap Contracts: 2021 Second Quarter 10,010,000 $ 2.69 $ 2.52 $ 3.08 Third Quarter 10,120,000 2.69 2.52 3.08 Fourth Quarter 10,120,000 2.69 2.52 3.08

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	3 Months Ended
	Mar. 31, 2021
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	NOTE 5 - FAIR VALUE MEASUREMENTS Fair value is defined as the amount at which an asset (or liability) could be bought (or incurred) or sold (or settled) in an orderly transaction between market participants at the measurement date. Further, ASC 820, Fair Value Measurement , establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value, and includes certain disclosure requirements. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. ASC 820 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: Level 1 —Unadjusted quoted prices for identical assets or liabilities in active markets. Level 2 —Quoted prices for similar assets or liabilities in non-active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. Level 3 —Inputs that are unobservable and significant to the fair value measurement (including the Partnership’s own assumptions in determining fair value). A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The carrying value of the Partnership's cash and cash equivalents, receivables, and payables approximate fair value due to the short-term nature of the instruments. The estimated carrying value of all debt as of March 31, 2021 and December 31, 2020 approximated the fair value due to variable market rates of interest. These debt fair values, which are Level 3 measurements, were estimated based on the Partnership’s incremental borrowing rates for similar types of borrowing arrangements, when quoted market prices were not available. The estimated fair values of the Partnership’s financial instruments are not necessarily indicative of the amounts that would be realized in a current market exchange. Assets and Liabilities Measured at Fair Value on a Recurring Basis The Partnership estimated the fair value of commodity derivative financial instruments using the market approach via a model that uses inputs that are observable in the market or can be derived from, or corroborated by, observable data. See Note 4 - Commodity Derivative Financial Instruments for further discussion. The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis: Fair Value Measurements Using Effect of Counterparty Netting Total Level 1 Level 2 Level 3 (in thousands) As of March 31, 2021 Financial Assets Commodity derivative instruments $ — $ 2,329 $ — $ (1,258) $ 1,071 Financial Liabilities Commodity derivative instruments $ — $ 45,705 $ — $ (1,258) $ 44,447 As of December 31, 2020 Financial Assets Commodity derivative instruments $ — $ 6,362 $ — $ (5,213) $ 1,149 Financial Liabilities Commodity derivative instruments $ — $ 26,379 $ — $ (5,213) $ 21,166 Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis Nonfinancial assets and liabilities measured at fair value on a non-recurring basis include certain nonfinancial assets and liabilities as may be acquired in a business combination and measurements of oil and natural gas property values for assessment of impairment. The determination of the fair values of proved and unproved properties acquired in business combinations are estimated by discounting projected future cash flows. The factors used to determine fair value include estimates of economic reserves, future operating and development costs, future commodity prices, timing of future production, and a risk-adjusted discount rate. The Partnership has designated these measurements as Level 3. The Partnership’s fair value assessments for recent acquisitions are included in Note 3 - Oil and Natural Gas Properties. Oil and natural gas properties are measured at fair value on a non-recurring basis using the income approach when assessing for impairment. The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and a risk-adjusted discount rate. The Partnership estimated the fair value of the impaired properties using published forward commodity price curves as of the measurement date of March 31, 2020, considering locational and quality differentials based on a review of historical realizations, and using an annual discount rate of 8%. The following table presents information about the non-recurring fair value measurements of the impaired properties: Fair Value Measurements Using Impairment Level 1 Level 2 Level 3 (in thousands) Three Months Ended March 31, 2021 Impaired oil and natural gas properties $ — $ — $ — $ — Three Months Ended March 31, 2020 Impaired oil and natural gas properties $ — $ — $ 2,044 $ 51,031 The Partnership’s estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty, particularly in the current volatile market, and cannot be determined with precision. Changes to these estimates, particularly related to economic reserves, future commodity prices, and timing of future production could result in additional impairment charges in the future. There were no significant changes in valuation techniques or related inputs as of March 31, 2021 or December 31, 2020.

CREDIT FACILITY

CREDIT FACILITY	3 Months Ended
	Mar. 31, 2021
Debt Disclosure [Abstract]
CREDIT FACILITY	NOTE 6 - CREDIT FACILITY The Partnership maintains a senior secured revolving credit agreement, as amended (the “Credit Facility”). The Credit Facility has an aggregate maximum credit amount of $1.0 billion. The commitment of the lenders equals the lesser of the aggregate maximum credit amount and the borrowing base. The amount of the borrowing base is redetermined semi-annually, usually in October and April, and is derived from the value of the Partnership’s oil and natural gas properties as determined by the lender syndicate using pricing assumptions that often differ from the current market for future prices. The Partnership and the lenders (at the direction of two-thirds of the lenders) each have discretion to request a borrowing base redetermination one time between scheduled redeterminations. The Partnership also has the right to request a redetermination following the acquisition of oil and natural gas properties in excess of 10% of the value of the borrowing base immediately prior to such acquisition. Effective November 3, 2020, the borrowing base redetermination reduced the borrowing base from $430.0 million to $400.0 million, and effective April 30, 2021, the borrowing base was reaffirmed at $400.0 million and the term of the Credit Facility was extended through November 1, 2024. Please see Item 5 of Part II of this quarterly report for a more detailed description of the amendment to the Credit Facility effective April 30, 2021. The next semi-annual redetermination is scheduled for October 2021. Outstanding borrowings under the Credit Facility bear interest at a floating rate elected by the Partnership equal to an alternative base rate (which is equal to the greatest of the Prime Rate, the Federal Funds effective rate plus 0.50%, or 1-month LIBOR plus 1.00%) or LIBOR, in each case, plus the applicable margin. As of March 31, 2021 and December 31, 2020, the applicable margin for the alternative base rate ranged from 1.00% to 2.00% and the applicable margin for LIBOR ranged from 2.00% to 3.00%, depending on the borrowings outstanding in relation to the borrowing base. Effective April 30, 2021, the LIBOR margin was increased to between 2.50% and 3.50% and the alternative base rate margin was increased to between 1.50% and 2.50%. The weighted-average interest rate of the Credit Facility was 2.37% and 2.40% as of March 31, 2021 and December 31, 2020, respectively. Accrued interest is payable at the end of each calendar quarter or at the end of each interest period, unless the interest period is longer than 90 days, in which case interest is payable at the end of every 90-day period. In addition, a commitment fee is payable at the end of each calendar quarter based on either a rate of 0.375% if the borrowing base utilization percentage is less than 50%, or 0.500% per annum if the borrowing base utilization percentage is equal to or greater than 50%. The Credit Facility is secured by substantially all of the Partnership’s oil and natural gas production and assets. The Credit Facility contains various limitations on future borrowings, leases, hedging, and sales of assets. Additionally, the Credit Facility requires the Partnership to maintain a current ratio of not less than 1.0:1.0 and a ratio of total debt to EBITDAX (Earnings before Interest, Taxes, Depreciation, Amortization, and Exploration) of not more than 3.5:1.0. As of March 31, 2021, the Partnership was in compliance with all financial covenants in the Credit Facility. The aggregate principal balance outstanding was $111.0 million and $121.0 million at March 31, 2021 and December 31, 2020, respectively. The unused portion of the available borrowings under the Credit Facility were $289.0 million and $279.0 million at March 31, 2021 and December 31, 2020, respectively. On March 5, 2021, the U.K. Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after December 31, 2021 for the 1-week and 2-month U.S. dollar settings and after June 30, 2023 for the remaining U.S. dollar settings. Our Credit Facility includes provisions to determine a replacement rate for LIBOR if necessary during its term, based on the secured overnight financing rate published by the Federal Reserve Bank of New York (“SOFR”). We currently do not expect the transition from LIBOR to have a material impact on us.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	3 Months Ended
	Mar. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	NOTE 7 - COMMITMENTS AND CONTINGENCIES Environmental Matters The Partnership’s business includes activities that are subject to U.S. federal, state, and local environmental regulations with regard to air, land, and water quality and other environmental matters. The Partnership does not consider the potential remediation costs that could result from issues identified in any environmental site assessments to be significant to the consolidated financial statements, and no provision for potential remediation costs has been recorded. Litigation

INCENTIVE COMPENSATION

INCENTIVE COMPENSATION	3 Months Ended
	Mar. 31, 2021
Share-based Payment Arrangement [Abstract]
INCENTIVE COMPENSATION	NOTE 8 - INCENTIVE COMPENSATION The table below summarizes incentive compensation expense recorded in the General and administrative line item of the consolidated statements of operations for the periods presented: Three Months Ended March 31, 2021 2020 (in thousands) Cash—short and long-term incentive plans $ 1,385 $ 963 Equity-based compensation—restricted common units 949 1,285 Equity-based compensation—restricted performance units 1 2,161 (4,657) Board of Directors incentive plan 352 478 Total incentive compensation expense $ 4,847 $ (1,931) 1 Compensation expense related to the restricted performance awards is determined using the measurement-date (i.e., the last day of each reporting period date) fair value of the Partnership's common units. Downward cost revisions recognized in the three months ended March 31, 2020 are due to the decrease in the Partnership's common unit price period over period.

PREFERRED UNITS

PREFERRED UNITS	3 Months Ended
	Mar. 31, 2021
Equity [Abstract]
PREFERRED UNITS	NOTE 9 - PREFERRED UNITS Series B Cumulative Convertible Preferred Units On November 28, 2017, the Partnership issued and sold in a private placement 14,711,219 Series B cumulative convertible preferred units representing limited partner interests in the Partnership for a cash purchase price of $20.3926 per Series B cumulative convertible preferred unit, resulting in total proceeds of approximately $300.0 million. The Series B cumulative convertible preferred units are entitled to an annual distribution of 7%, payable on a quarterly basis in arrears. The Series B cumulative convertible preferred units may be converted by each holder at its option, in whole or in part, into common units on a one-for-one basis at the purchase price of $20.3926, adjusted to give effect to any accrued but unpaid accumulated distributions on the applicable Series B cumulative convertible preferred units through the most recent declaration date. However, the Partnership shall not be obligated to honor any request for such conversion if such request does not involve an underlying value of common units of at least $10.0 million based on the closing trading price of common units on the trading day immediately preceding the conversion notice date, or such lesser amount to the extent such exercise covers all of a holder's Series B cumulative convertible preferred units. The Series B cumulative convertible preferred units had a carrying value of $298.4 million, including accrued distributions of $5.3 million, as of March 31, 2021 and December 31, 2020. The Series B cumulative convertible preferred units are classified as mezzanine equity on the consolidated balance sheets since certain provisions of redemption are outside the control of the Partnership.

EARNINGS PER UNIT

EARNINGS PER UNIT	3 Months Ended
	Mar. 31, 2021
Earnings Per Share [Abstract]
EARNINGS PER UNIT	NOTE 10 - EARNINGS PER UNIT The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted common units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to these participating units was not material. Net income (loss) attributable to the Partnership is allocated to the Partnership’s general partner and the common unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period. The Partnership assesses the Series B cumulative convertible preferred units on an as-converted basis for the purpose of calculating diluted EPU. The Partnership’s restricted performance unit awards are contingently issuable units that are considered in the calculation of diluted EPU. The Partnership assesses the number of units that would be issuable, if any, under the terms of the arrangement if the end of the reporting period were the end of the contingency period. The following table sets forth the computation of basic and diluted earnings per common unit: Three Months Ended March 31, 2021 2020 (in thousands, except per unit amounts) NET INCOME (LOSS) $ 16,186 $ 76,112 Distributions on Series B cumulative convertible preferred units (5,250) (5,250) NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS 10,936 70,862 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — Common units 10,936 70,862 $ 10,936 $ 70,862 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT: Per common unit (basic) $ 0.05 $ 0.34 Per common unit (diluted) 0.05 0.34 WEIGHTED AVERAGE COMMON UNITS OUTSTANDING: Weighted average common units outstanding (basic) 207,442 206,631 Effect of dilutive securities — — Weighted average common units outstanding (diluted) 207,442 206,631 The following units of potentially dilutive securities were excluded from the computation of diluted weighted average units outstanding because their inclusion would be anti-dilutive: Three Months Ended March 31, 2021 2020 (in thousands) Potentially dilutive securities (common units): Series B cumulative convertible preferred units on an as-converted basis 14,969 14,969

COMMON UNITS

COMMON UNITS	3 Months Ended
	Mar. 31, 2021
Share-based Payment Arrangement [Abstract]
COMMON UNITS	NOTE 11 - COMMON UNITS Common Units The common units represent limited partner interests in the Partnership. The holders of common units are entitled to participate in distributions and exercise the rights and privileges provided to limited partners holding common units under the partnership agreement. The partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 15% or more of any class of units then outstanding, their transferees, persons who acquired such units with the prior approval of the board of directors of the Partnership's general partner (the "Board"), holders of Series B cumulative convertible preferred units in connection with any vote, consent or approval of the Series B cumulative convertible preferred units as a separate class, and persons who own 15% or more of any class as a result of any redemption or purchase of any other person's units or similar action by the Partnership or any conversion of the Series B cumulative convertible preferred units at the Partnership's option or in connection with a change of control, may not vote on any matter. The partnership agreement generally provides that any distributions are paid each quarter in the following manner: • first , to the holders of the Series B cumulative convertible preferred units in an amount equal to 7% per annum, subject to certain adjustments; and • second , to the holders of common units. The following table provides information about the Partnership's per unit distributions to common unitholders: Three Months Ended March 31, 2021 2020 Distributions declared and paid per common unit $ 0.1750 $ 0.3000 Common Unit Repurchase Program On November 5, 2018, the Board authorized the repurchase of up to $75.0 million in common units. The repurchase program authorizes the Partnership to make repurchases on a discretionary basis as determined by management, subject to market conditions, applicable legal requirements, available liquidity, and other appropriate factors. The Partnership made no repurchases under this program for the three months ended March 31, 2021. As of March 31, 2021, the Partnership has repurchased $4.2 million in common units under the repurchase program since inception. The repurchase program is funded from the Partnership's cash on hand or availability on the Credit Facility. Any repurchased units are canceled.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	3 Months Ended
	Mar. 31, 2021
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	NOTE 12 - SUBSEQUENT EVENTS On April 21, 2021, the Board approved a distribution for the three months ended March 31, 2021 of $0.175 per common unit. Distributions will be payable on May 21, 2021 to unitholders of record at the close of business on May 14, 2021. On April 30, 2021, the Partnership amended its Credit Facility. Please see Item 5 of Part II of this quarterly report for a description of the amendment. In April 2021, the Partnership entered into an agreement with several operators to test and develop areas of the Austin Chalk in East Texas where the Partnership has significant acreage positions. Under the terms of the agreement, the operators will participate in three test wells targeting the Austin Chalk formation. In April 2021, the Partnership entered into an agreement with a large, private independent operator ("Operator") to drill and complete multiple Austin Chalk wells on the Partnership's acreage within East Texas in 2021. If the initial wells are successful, the Operator has the option to expand the Austin Chalk development program on additional acreage owned by the Partnership. In May 2021, the Partnership entered into an agreement with Aethon to develop certain of the Partnership's undeveloped acreage in San Augustine County. The agreement provides for minimum well commitments by Aethon in exchange for reduced royalty rates and exclusive access to the Partnership's mineral and leasehold acreage in the contract area. The agreement calls for a minimum of five wells to be drilled in the initial program year, which begins in the third quarter of 2021, increasing to a minimum of 12 wells per year beginning with the fourth program year. The Partnership's development agreement with Aethon and related drilling commitments covering its San Augustine County acreage is independent of the development agreement and associated commitments covering Angelina County. In May 2021, the Partnership entered into an agreement to acquire mineral and royalty acreage in the northern Midland Basin for total consideration of $20.7 million. The purchase price will consist of $10.0 million in cash and $10.7 million in common units of the Partnership.

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	3 Months Ended
	Mar. 31, 2021
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation The accompanying unaudited interim consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles ("GAAP") in the United States and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). These unaudited interim consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with GAAP. Accordingly, the accompanying unaudited interim consolidated financial statements and related notes should be read in conjunction with the Partnership’s consolidated financial statements included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2020 ("2020 Annual Report on Form 10-K"). The unaudited interim consolidated financial statements include the consolidated results of the Partnership. The results of operations for the three months ended March 31, 2021 are not necessarily indicative of the results to be expected for the full year. In the opinion of management, all adjustments, which are of a normal and recurring nature, necessary for the fair presentation of the financial results for all periods presented have been reflected. All intercompany balances and transactions have been eliminated. The Partnership evaluates the significant terms of its investments to determine the method of accounting to be applied to each respective investment. Investments in which the Partnership has less than a 20% ownership interest and does not have control or exercise significant influence are accounted for using fair value or cost minus impairment if fair value is not readily determinable. Investments in which the Partnership exercises control are consolidated, and the noncontrolling interests of such investments, which are not attributable directly or indirectly to the Partnership, are presented as a separate component of net income (loss) and equity. The unaudited interim consolidated financial statements include undivided interests in oil and natural gas property rights. The Partnership accounts for its share of oil and natural gas property rights by reporting its proportionate share of assets, liabilities, revenues, costs, and cash flows within the relevant lines on the accompanying unaudited interim consolidated balance sheets, statements of operations, and statements of cash flows.
Segment Reporting	Segment Reporting The Partnership operates in a single operating and reportable segment. Operating segments are defined as components of an enterprise for which separate financial information is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and assess performance. The Partnership’s chief executive officer has been determined to be the chief operating decision maker and allocates resources and assesses performance based upon financial information at the consolidated level.
Earnings Per Unit	The Partnership applies the two-class method for purposes of calculating earnings per unit (“EPU”). The holders of the Partnership’s restricted common units have all the rights of a unitholder, including non-forfeitable distribution rights. As participating securities, the restricted common units are included in the calculation of basic earnings per unit. For the periods presented, the amount of earnings allocated to these participating units was not material. Net income (loss) attributable to the Partnership is allocated to the Partnership’s general partner and the common unitholders in proportion to their pro rata ownership after giving effect to distributions, if any, declared during the period.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - (Tables)	3 Months Ended
	Mar. 31, 2021
Accounting Policies [Abstract]
Schedule of Accounts Receivable	The following table presents information about the Partnership's accounts receivable: March 31, 2021 December 31, 2020 (in thousands) Accounts receivable: Revenues from contracts with customers $ 55,297 $ 58,181 Other 3,991 3,727 Total accounts receivable $ 59,288 $ 61,908

COMMODITY DERIVATIVE FINANCIA_2

COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS (Tables)	3 Months Ended
	Mar. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of Fair Value and Classification of Derivative Instruments	The tables below summarize the fair values and classifications of the Partnership’s derivative instruments, as well as the gross recognized derivative assets, liabilities, and amounts offset in the consolidated balance sheets as of each date: March 31, 2021 Classification Balance Sheet Location Gross Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 1,573 $ (1,258) $ 315 Long-term asset Deferred charges and other long-term assets 756 — 756 Total assets $ 2,329 $ (1,258) $ 1,071 Liabilities: Current liability Commodity derivative liabilities $ 45,705 $ (1,258) $ 44,447 Long-term liability Commodity derivative liabilities — — — Total liabilities $ 45,705 $ (1,258) $ 44,447 December 31, 2020 Classification Balance Sheet Location Gross Effect of Counterparty Netting Net Carrying Value on Balance Sheet (in thousands) Assets: Current asset Commodity derivative assets $ 6,362 $ (5,213) $ 1,149 Long-term asset Deferred charges and other long-term assets — — — Total assets $ 6,362 $ (5,213) $ 1,149 Liabilities: Current liability Commodity derivative liabilities $ 24,531 $ (5,213) $ 19,318 Long-term liability Commodity derivative liabilities 1,848 — 1,848 Total liabilities $ 26,379 $ (5,213) $ 21,166
Changes in Fair Value of Company's Commodity Derivative Instruments	Changes in the fair values of the Partnership’s derivative instruments (both assets and liabilities) are presented on a net basis in the accompanying consolidated statements of operations and consolidated statements of cash flows and consist of the following for the periods presented: Three Months Ended March 31, Derivatives not designated as hedging instruments 2021 2020 (in thousands) Beginning fair value of commodity derivative instruments $ (20,017) $ 15,221 Gain (loss) on oil derivative instruments (24,854) 77,811 Gain (loss) on natural gas derivative instruments (3,028) 12,200 Net cash paid (received) on settlements of oil derivative instruments 4,502 (1,541) Net cash paid (received) on settlements of natural gas derivative instruments 21 (7,413) Net change in fair value of commodity derivative instruments (23,359) 81,057 Ending fair value of commodity derivative instruments $ (43,376) $ 96,278
Summary of Open Derivative Contracts	The Partnership had the following open derivative contracts for oil as of March 31, 2021: Weighted Average Price (Per Bbl) Range (Per Bbl) Period and Type of Contract Volume (Bbl) Low High Oil Swap Contracts: 2021 First Quarter 220,000 $ 38.97 $ 32.64 $ 46.50 Second Quarter 660,000 38.97 32.64 46.50 Third Quarter 660,000 38.97 32.64 46.50 Fourth Quarter 660,000 38.97 32.64 46.50 2022 First Quarter 150,000 $ 55.47 $ 55.29 $ 56.10 Second Quarter 150,000 55.47 55.29 56.10 Third Quarter 150,000 55.47 55.29 56.10 Fourth Quarter 150,000 55.47 55.29 56.10 The Partnership had the following open derivative contracts for natural gas as of March 31, 2021: Weighted Average Price (Per MMBtu) Range (Per MMBtu) Period and Type of Contract Volume (MMBtu) Low High Natural Gas Swap Contracts: 2021 Second Quarter 10,010,000 $ 2.69 $ 2.52 $ 3.08 Third Quarter 10,120,000 2.69 2.52 3.08 Fourth Quarter 10,120,000 2.69 2.52 3.08

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	3 Months Ended
	Mar. 31, 2021
Fair Value Disclosures [Abstract]
Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis	The following table presents information about the Partnership’s assets and liabilities measured at fair value on a recurring basis: Fair Value Measurements Using Effect of Counterparty Netting Total Level 1 Level 2 Level 3 (in thousands) As of March 31, 2021 Financial Assets Commodity derivative instruments $ — $ 2,329 $ — $ (1,258) $ 1,071 Financial Liabilities Commodity derivative instruments $ — $ 45,705 $ — $ (1,258) $ 44,447 As of December 31, 2020 Financial Assets Commodity derivative instruments $ — $ 6,362 $ — $ (5,213) $ 1,149 Financial Liabilities Commodity derivative instruments $ — $ 26,379 $ — $ (5,213) $ 21,166
Fair Value Measurements, Nonrecurring	The following table presents information about the non-recurring fair value measurements of the impaired properties: Fair Value Measurements Using Impairment Level 1 Level 2 Level 3 (in thousands) Three Months Ended March 31, 2021 Impaired oil and natural gas properties $ — $ — $ — $ — Three Months Ended March 31, 2020 Impaired oil and natural gas properties $ — $ — $ 2,044 $ 51,031

INCENTIVE COMPENSATION (Tables)

INCENTIVE COMPENSATION (Tables)	3 Months Ended
	Mar. 31, 2021
Share-based Payment Arrangement [Abstract]
Summary of Incentive Compensation Expense	The table below summarizes incentive compensation expense recorded in the General and administrative line item of the consolidated statements of operations for the periods presented: Three Months Ended March 31, 2021 2020 (in thousands) Cash—short and long-term incentive plans $ 1,385 $ 963 Equity-based compensation—restricted common units 949 1,285 Equity-based compensation—restricted performance units 1 2,161 (4,657) Board of Directors incentive plan 352 478 Total incentive compensation expense $ 4,847 $ (1,931) 1 Compensation expense related to the restricted performance awards is determined using the measurement-date (i.e., the last day of each reporting period date) fair value of the Partnership's common units. Downward cost revisions recognized in the three months ended March 31, 2020 are due to the decrease in the Partnership's common unit price period over period.

EARNINGS PER UNIT (Tables)

EARNINGS PER UNIT (Tables)	3 Months Ended
	Mar. 31, 2021
Earnings Per Share [Abstract]
Computation of Basic and Diluted Earnings per Common and Subordinated Unit	The following table sets forth the computation of basic and diluted earnings per common unit: Three Months Ended March 31, 2021 2020 (in thousands, except per unit amounts) NET INCOME (LOSS) $ 16,186 $ 76,112 Distributions on Series B cumulative convertible preferred units (5,250) (5,250) NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS 10,936 70,862 ALLOCATION OF NET INCOME (LOSS): General partner interest $ — $ — Common units 10,936 70,862 $ 10,936 $ 70,862 NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT: Per common unit (basic) $ 0.05 $ 0.34 Per common unit (diluted) 0.05 0.34 WEIGHTED AVERAGE COMMON UNITS OUTSTANDING: Weighted average common units outstanding (basic) 207,442 206,631 Effect of dilutive securities — — Weighted average common units outstanding (diluted) 207,442 206,631
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following units of potentially dilutive securities were excluded from the computation of diluted weighted average units outstanding because their inclusion would be anti-dilutive: Three Months Ended March 31, 2021 2020 (in thousands) Potentially dilutive securities (common units): Series B cumulative convertible preferred units on an as-converted basis 14,969 14,969

COMMON UNITS (Tables)

COMMON UNITS (Tables)	3 Months Ended
	Mar. 31, 2021
Share-based Payment Arrangement [Abstract]
Distributions Made to Limited Partner, by Distribution	The following table provides information about the Partnership's per unit distributions to common unitholders: Three Months Ended March 31, 2021 2020 Distributions declared and paid per common unit $ 0.1750 $ 0.3000

BUSINESS AND BASIS OF PRESENT_2

BUSINESS AND BASIS OF PRESENTATION - Narrative (Details)	Mar. 31, 2021state
Limited Partners Capital Account [Line Items]
Cost basis, ownership percentage	20.00%
U.S.
Limited Partners Capital Account [Line Items]
Number of states major onshore oil and natural gas basins located	41

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Accounts Receivable (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 59,288	$ 61,908
Revenues from contracts with customers
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	55,297	58,181
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable	$ 3,991	$ 3,727

OIL AND NATURAL GAS PROPERTIES

OIL AND NATURAL GAS PROPERTIES - Divestitures (Details) $ in Millions	Jul. 01, 2020USD ($)	May 01, 2020USD ($)	Sep. 30, 2020USD ($)well
Business Acquisition [Line Items]
Number of divestitures | well			2
Assets held for sale	$ 126.6
Gain on sale of assets			$ 24
Disposal Group, Held-for-sale, Not Discontinued Operations | Permian Basin
Business Acquisition [Line Items]
Proceeds from sale of property held-for-sale			$ 150.6
Disposal Group, Held-for-sale, Not Discontinued Operations | Divestiture A | Midland County, Texas
Business Acquisition [Line Items]
Proceeds from sale of property held-for-sale		$ 54.5
Disposal Group, Held-for-sale, Not Discontinued Operations | Divestiture B | Midland County, Texas
Business Acquisition [Line Items]
Proceeds from sale of property held-for-sale	$ 96.1

OIL AND NATURAL GAS PROPERTIE_2

OIL AND NATURAL GAS PROPERTIES - Farmout Agreements (Details) $ in Millions	1 Months Ended			3 Months Ended			5 Months Ended	12 Months Ended		50 Months Ended
	Nov. 30, 2020	Nov. 30, 2017well	Feb. 28, 2017	Mar. 31, 2021USD ($)well	Sep. 30, 2020well	Jun. 30, 2020well	Mar. 31, 2021USD ($)well	Dec. 31, 2020USD ($)	Dec. 31, 2017arrangement	Mar. 31, 2021USD ($)well
Business Acquisition [Line Items]
Number of arrangements | arrangement									2
Farmout Agreement | Other long-term liabilities
Business Acquisition [Line Items]
Business combination, pro forma information, working interests in wells drilled and completed, actual | $				$ 0.1				$ 0.1
Farmout Agreement | San Augustine County, Texas
Business Acquisition [Line Items]
Business combination, ownership interest, acreage, percent			50.00%
Farmout Agreement | Canaan Resource Partners
Business Acquisition [Line Items]
Business combination, pro forma information, revenue of acquiree since acquisition date, actual | $										$ 90.2
Farmout Agreement | Canaan Resource Partners | San Augustine County, Texas
Business Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, percent			80.00%
Asset acquisition, ownership interest, gross, percent			40.00%
Asset acquisition, third phase, ownership interest in additional wells, percent			20.00%
Exploratory wells, expected to be drilled				20						37
Farmout Agreement | Pivotal | San Augustine County, Texas
Business Acquisition [Line Items]
Exploratory wells, expected to be drilled		80
Oil, productive well, number of wells, net				68			68			68
Farmout Agreement | Pivotal | Angelina County, Texas
Business Acquisition [Line Items]
Exploratory wells, expected to be drilled						4
Exploratory wells, expected to be drilled per year					15
Farmout Agreement | Second Pivotal Farmout
Business Acquisition [Line Items]
Business combination, pro forma information, revenue of acquiree since acquisition date, actual | $							$ 119.2
Farmout Agreement | Second Pivotal Farmout | Angelina County, Texas
Business Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, percent	100.00%
Oil, productive well, number of wells, net				2			2			2
Farmout Agreement | Second Pivotal Farmout | Angelina County, Texas | Minimum
Business Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, gross, percent	12.50%
Farmout Agreement | Second Pivotal Farmout | Angelina County, Texas | Maximum
Business Acquisition [Line Items]
Asset acquisition, ownership interest, in wells operated by others, gross, percent	25.00%

OIL AND NATURAL GAS PROPERTIE_3

OIL AND NATURAL GAS PROPERTIES - XTO Completions Agreement (Details) - XTO Completions Agreement - well	Jan. 18, 2021	Jun. 30, 2020
Business Acquisition [Line Items]
Number of drilled but uncompleted (DUC) wells		13
Number of drilled but uncompleted wells (DUC), turned to sales	13

OIL AND NATURAL GAS PROPERTIE_4

OIL AND NATURAL GAS PROPERTIES - Impairment of Oil and Gas Properties (Details) - USD ($)	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Business Combinations [Abstract]
Impairment of oil and natural gas properties	$ 0	$ 51,031,000

COMMODITY DERIVATIVE FINANCIA_3

COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Narrative (Details)	Mar. 31, 2021counterparty
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Number of counterparties	7

COMMODITY DERIVATIVE FINANCIA_4

COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Summary of Fair Value and Classification of Derivative Instruments (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Derivatives Fair Value [Line Items]
Gross fair value, assets	$ 2,329	$ 6,362
Effect of counterparty netting, assets	(1,258)	(5,213)
Total net carrying value on balance sheet, assets	1,071	1,149
Gross fair value, liabilities	45,705	26,379
Effect of counterparty netting, liabilities	(1,258)	(5,213)
Total net carrying value on balance sheet, liabilities	44,447	21,166
Commodity derivative assets
Derivatives Fair Value [Line Items]
Gross fair value, assets	1,573	6,362
Effect of counterparty netting, assets	(1,258)	(5,213)
Total net carrying value on balance sheet, assets	315	1,149
Deferred charges and other long-term assets
Derivatives Fair Value [Line Items]
Gross fair value, assets	756	0
Effect of counterparty netting, assets	0	0
Total net carrying value on balance sheet, assets	756	0
Commodity derivative liabilities
Derivatives Fair Value [Line Items]
Gross fair value, liabilities	45,705	24,531
Effect of counterparty netting, liabilities	(1,258)	(5,213)
Total net carrying value on balance sheet, liabilities	44,447	19,318
Commodity derivative liabilities
Derivatives Fair Value [Line Items]
Gross fair value, liabilities	0	1,848
Effect of counterparty netting, liabilities	0	0
Total net carrying value on balance sheet, liabilities	$ 0	$ 1,848

COMMODITY DERIVATIVE FINANCIA_5

COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Changes in Fair Value of Company's Commodity Derivative Instruments (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	$ (27,882)	$ 90,011
Net cash paid (received) on settlements of derivative instruments	4,523	(8,954)
Not Designated as Hedging Instrument
Derivatives not designated as hedging instruments
Beginning fair value of commodity derivative instruments	(20,017)	15,221
Net change in fair value of commodity derivative instruments	(23,359)	81,057
Ending fair value of commodity derivative instruments	(43,376)	96,278
Not Designated as Hedging Instrument | Oil
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	(24,854)	77,811
Net cash paid (received) on settlements of derivative instruments	4,502	(1,541)
Not Designated as Hedging Instrument | Natural gas and natural gas liquids sales
Derivatives not designated as hedging instruments
Gain (loss) on commodity derivative instruments	(3,028)	12,200
Net cash paid (received) on settlements of derivative instruments	$ 21	$ (7,413)

COMMODITY DERIVATIVE FINANCIA_6

COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS - Summary of Open Derivative Contracts for Oil and Natural Gas (Details) - Swaps Contract - Swap - Not Designated as Hedging Instrument bbl in Thousands, MMBTU in Thousands	3 Months Ended
	Mar. 31, 2021MMBTU$ / MMBTU$ / bblbbl
Oil | First Quarter 2021
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	220
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	38.97
Derivative contract, price range low (in USD per Bbl or MMBtu)	32.64
Derivative, average cap price	46.50
Oil | Second Quarter 2021
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	660
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	38.97
Derivative contract, price range low (in USD per Bbl or MMBtu)	32.64
Derivative, average cap price	46.50
Oil | Third Quarter 2021
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	660
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	38.97
Derivative contract, price range low (in USD per Bbl or MMBtu)	32.64
Derivative, average cap price	46.50
Oil | Fourth Quarter 2021
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	660
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	38.97
Derivative contract, price range low (in USD per Bbl or MMBtu)	32.64
Derivative, average cap price	46.50
Oil | First Quarter 2022
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	150
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	55.47
Derivative contract, price range low (in USD per Bbl or MMBtu)	55.29
Derivative, average cap price	56.10
Oil | Second Quarter 2022
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	150
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	55.47
Derivative contract, price range low (in USD per Bbl or MMBtu)	55.29
Derivative, average cap price	56.10
Oil | Third Quarter 2022
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	150
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	55.47
Derivative contract, price range low (in USD per Bbl or MMBtu)	55.29
Derivative, average cap price	56.10
Oil | Fourth Quarter 2022
Derivative [Line Items]
Derivative contract, volume (in Bbl) | bbl	150
Derivative contract, weighted average price (in USD per Bbl or MMBtu)	55.47
Derivative contract, price range low (in USD per Bbl or MMBtu)	55.29
Derivative, average cap price	56.10
Natural gas and natural gas liquids sales | Second Quarter 2021
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	10,010
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU	2.69
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / MMBTU	2.52
Derivative, average cap price | $ / MMBTU	3.08
Natural gas and natural gas liquids sales | Third Quarter 2021
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	10,120
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU	2.69
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / MMBTU	2.52
Derivative, average cap price | $ / MMBTU	3.08
Natural gas and natural gas liquids sales | Fourth Quarter 2021
Derivative [Line Items]
Derivative contract, volume (in MMBtu) | MMBTU	10,120
Derivative contract, weighted average price (in USD per Bbl or MMBtu) | $ / MMBTU	2.69
Derivative contract, price range low (in USD per Bbl or MMBtu) | $ / MMBTU	2.52
Derivative, average cap price | $ / MMBTU	3.08

FAIR VALUE MEASUREMENTS - Sched

FAIR VALUE MEASUREMENTS - Schedule of Assets and Liabilities Measured at Fair Value on a Recurring Basis (Details) - USD ($) $ in Thousands	Mar. 31, 2021	Dec. 31, 2020
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	$ 2,329	$ 6,362
Effect of Counterparty Netting, Assets	(1,258)	(5,213)
Net carrying value on balance sheet, assets	1,071	1,149
Gross fair value, liabilities	45,705	26,379
Effect of counterparty netting, liabilities	(1,258)	(5,213)
Net carrying value on balance sheet, liabilities	44,447	21,166
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Effect of Counterparty Netting, Assets	(1,258)	(5,213)
Net carrying value on balance sheet, assets	1,071	1,149
Effect of counterparty netting, liabilities	(1,258)	(5,213)
Net carrying value on balance sheet, liabilities	44,447	21,166
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis | Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	0	0
Gross fair value, liabilities	0	0
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis | Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	2,329	6,362
Gross fair value, liabilities	45,705	26,379
Commodity Derivative Instruments | Fair Value Measurements, Recurring Basis | Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Gross fair value, assets	0	0
Gross fair value, liabilities	$ 0	$ 0

FAIR VALUE MEASUREMENTS - Sch_2

FAIR VALUE MEASUREMENTS - Schedule of Assets and Liabilities Measured At Fair Value on a Nonrecurring Basis (Details) - USD ($)	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties	$ 0	$ 51,031,000
Fair Value Measurements, Nonrecurring Basis
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment of oil and natural gas properties	0	$ 51,031,000
Fair Value Measurements, Nonrecurring Basis | Measurement Input, Discount Rate
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impaired property, plant and equipment, measurement input		8.00%
Fair Value Measurements, Nonrecurring Basis | Level 1
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impaired oil and natural gas properties	0	$ 0
Fair Value Measurements, Nonrecurring Basis | Level 2
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impaired oil and natural gas properties	0	0
Fair Value Measurements, Nonrecurring Basis | Level 3
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impaired oil and natural gas properties	$ 0	$ 2,044,000

CREDIT FACILITY (Details)

CREDIT FACILITY (Details) - USD ($)	Apr. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Nov. 03, 2020	Jul. 21, 2020
Line Of Credit Facility [Line Items]
Credit facility		$ 111,000,000	$ 121,000,000
Senior Line of Credit | Revolving Credit Facility
Line Of Credit Facility [Line Items]
Maximum borrowing capacity		$ 1,000,000,000
Right to request a redetermination, acquisition of properties in excess of value of borrowing base (percent)		10.00%
Borrowing base				$ 400,000,000	$ 430,000,000
Weighted average interest rate (percent)		2.37%	2.40%
Interest payable, term		90 days
Borrowing base threshold (percent)		50.00%
Credit facility		$ 111,000,000	$ 121,000,000
Unused portion of current borrowing base		$ 289,000,000	$ 279,000,000
Senior Line of Credit | Revolving Credit Facility | Subsequent Event
Line Of Credit Facility [Line Items]
Borrowing base	$ 400,000,000
Senior Line of Credit | Revolving Credit Facility | Federal Funds
Line Of Credit Facility [Line Items]
Interest rate (percent)		0.50%
Senior Line of Credit | Revolving Credit Facility | LIBOR Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)		1.00%
Senior Line of Credit | Revolving Credit Facility | Borrowing Base Utilization Percentage Less Than 50%
Line Of Credit Facility [Line Items]
Commitment fee payable rate (percent)		0.375%
Senior Line of Credit | Revolving Credit Facility | Borrowing Base Utilization Percentage Equal to or Greater Than 50%
Line Of Credit Facility [Line Items]
Commitment fee payable rate (percent)		0.50%
Senior Line of Credit | Revolving Credit Facility | Minimum
Line Of Credit Facility [Line Items]
Interest payable, term		90 days
Current ratio		1
Senior Line of Credit | Revolving Credit Facility | Minimum | LIBOR Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)		2.00%	2.00%
Senior Line of Credit | Revolving Credit Facility | Minimum | LIBOR Plus Margin Rate | Subsequent Event
Line Of Credit Facility [Line Items]
Interest rate (percent)	2.50%
Senior Line of Credit | Revolving Credit Facility | Minimum | Prime Rate Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)		1.00%	1.00%
Senior Line of Credit | Revolving Credit Facility | Minimum | Prime Rate Plus Margin Rate | Subsequent Event
Line Of Credit Facility [Line Items]
Interest rate (percent)	1.50%
Senior Line of Credit | Revolving Credit Facility | Maximum
Line Of Credit Facility [Line Items]
Ratio of total debt to EBITDAX		3.5
Senior Line of Credit | Revolving Credit Facility | Maximum | LIBOR Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)		3.00%	3.00%
Senior Line of Credit | Revolving Credit Facility | Maximum | LIBOR Plus Margin Rate | Subsequent Event
Line Of Credit Facility [Line Items]
Interest rate (percent)	3.50%
Senior Line of Credit | Revolving Credit Facility | Maximum | Prime Rate Plus Margin Rate
Line Of Credit Facility [Line Items]
Interest rate (percent)		2.00%	2.00%
Senior Line of Credit | Revolving Credit Facility | Maximum | Prime Rate Plus Margin Rate | Subsequent Event
Line Of Credit Facility [Line Items]
Interest rate (percent)	2.50%

INCENTIVE COMPENSATION - Summar

INCENTIVE COMPENSATION - Summary of Incentive Compensation Expense (Details) - General and administrative expenses - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash—short and long-term incentive plans	$ 1,385	$ 963
Incentive compensation expense	4,847	(1,931)
Restricted Common Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	949	1,285
Restricted Performance Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation	2,161	(4,657)
Common units | Board of Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incentive compensation expense	$ 352	$ 478

PREFERRED UNITS (Details)

PREFERRED UNITS (Details) - Series B Cumulative Convertible Preferred Units - USD ($) $ / shares in Units, $ in Thousands	Nov. 28, 2017	Mar. 31, 2021	Dec. 31, 2020
Class of Stock [Line Items]
Shares, price per share (in dollars per share)	$ 20.3926
Proceeds from issuance of convertible preferred stock	$ 300,000
Preferred units distribution rate	7.00%	7.00%
Minimum underlying value for conversion trigger	$ 10,000
Preferred units, outstanding value		$ 298,361	$ 298,361
Accrued distributions		$ 5,300	$ 5,300
Noble Acquisition
Class of Stock [Line Items]
Number of shares issued (in shares)	14,711,219

EARNINGS PER UNIT - Computation

EARNINGS PER UNIT - Computation of Basic and Diluted Earnings per Unit (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Earnings Per Share [Abstract]
Net income (loss)	$ 16,186	$ 76,112
Distributions on Series B cumulative convertible preferred units	(5,250)	(5,250)
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	10,936	70,862
ALLOCATION OF NET INCOME (LOSS):
General partner interest	0	0
Common units	10,936	70,862
NET INCOME (LOSS) ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS	$ 10,936	$ 70,862
NET INCOME (LOSS) ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT:
Per common unit (basic) (in dollars per share)	$ 0.05	$ 0.34
Per common unit (diluted) (in dollars per share)	$ 0.05	$ 0.34
WEIGHTED AVERAGE COMMON UNITS OUTSTANDING:
Weighted average common units outstanding (basic) (in shares)	207,442	206,631
Effect of dilutive securities (in shares)	0	0
Weighted average units outstanding (diluted) (in shares)	207,442	206,631

EARNINGS PER UNIT - Potentially

EARNINGS PER UNIT - Potentially Dilutive Securities Excluded from the Computation of Diluted Weighted Average Shares Outstanding (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Series B cumulative convertible preferred units on an as-converted basis | Common units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Units issuable upon conversion of preferred units excluded from the calculation of diluted EPU (in shares)	14,969	14,969

COMMON UNITS - Narrative (Detai

COMMON UNITS - Narrative (Details) - USD ($)	Nov. 28, 2017	Mar. 31, 2021	Mar. 31, 2021	Nov. 05, 2018
November 2018 Repurchase Program
Class of Stock [Line Items]
Stock repurchase program, authorized amount				$ 75,000,000
Series B Cumulative Convertible Preferred Units
Class of Stock [Line Items]
Preferred units minimum voting rights rate (percent)		15.00%	15.00%
Preferred units distribution rate	7.00%	7.00%
Common units | November 2018 Repurchase Program
Class of Stock [Line Items]
Treasury stock, value, acquired, cost method		$ 0	$ 4,200,000

COMMON UNITS - Per share distri

COMMON UNITS - Per share distributions to common and subordinated unitholders (Details) - $ / shares	3 Months Ended
	Mar. 31, 2021	Mar. 31, 2020
Class of Stock [Line Items]
Per unit (in dollars per share)	$ 0.1750
Common units
Class of Stock [Line Items]
Per unit (in dollars per share)		$ 0.3000

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) $ / shares in Units, $ in Millions	Apr. 21, 2021$ / shares	May 31, 2021USD ($)	Apr. 30, 2021well	Sep. 30, 2021well
San Augustine County, Texas | Aethon Energy | Forecast
Subsequent Event [Line Items]
Test wells | well				5
Exploratory wells, expected to be drilled per year | well				12
Subsequent Event | Austin Chalk Formation, East Texas
Subsequent Event [Line Items]
Test wells | well			3
Subsequent Event | Northern Midland Basin | Mineral And Royalty Acreage
Subsequent Event [Line Items]
Total consideration for acquisition | $		$ 20.7
Cash payments for acquisition | $		10
Common unit consideration for acquisition | $		$ 10.7
Subsequent Event | Common units
Subsequent Event [Line Items]
Quarterly cash distribution declared (in dollars per share) | $ / shares	$ 0.175