Mid-Con Energy Partners (MCEP) 10-K 12 Mar 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Mar. 03, 2020	Jun. 30, 2019
Cover [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Trading Symbol	MCEP
Entity Registrant Name	Mid-Con Energy Partners, LP
Entity Central Index Key	0001527709
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 10.6
Entity Common Stock, Shares Outstanding		31,156,957
Title of 12(b) Security	Common Units Representing Limited Partner Interests
Security Exchange Name	NASDAQ
Entity Incorporation, State or Country Code	DE
Entity File Number	1-35374
Entity Tax Identification Number	45-2842469
Entity Address, Address Line One	2431 East 61st Street
Entity Address, Address Line Two	Suite 850
Entity Address, City or Town	Tulsa
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	74136
City Area Code	918
Local Phone Number	743-7575
Entity Interactive Data Current	Yes
Document Annual Report	true
Document Transition Report	false

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 255	$ 467
Accounts receivable	6,853	4,194
Derivative financial instruments		5,666
Prepaid expenses	87	118
Assets held for sale	365	430
Total current assets	7,560	10,875
Oil and natural gas properties, successful efforts method
Proved properties	261,375	379,441
Unproved properties	3,125	2,928
Other property and equipment	1,262	427
Accumulated depletion, depreciation, amortization and impairment	(72,303)	(175,948)
Total property and equipment, net	193,459	206,848
Derivative financial instruments	730	2,418
Other assets	1,020	1,563
Total assets	202,769	221,704
Accounts payable
Trade	320	141
Related parties	6,902	3,732
Derivative financial instruments	1,944
Accrued liabilities	795	2,024
Other current liabilities	430
Total current liabilities	10,391	5,897
Long-term debt	68,000	93,000
Other long-term liabilities	457	47
Asset retirement obligations	30,265	26,001
Commitments and contingencies
General partner	(793)	(786)
Limited partners - 30,824,291 and 30,436,124 units issued and outstanding, respectively	56,656	61,195
Total equity	55,863	60,409
Total liabilities, convertible preferred units and equity	202,769	221,704
Class A Convertible Preferred Units [Member]
Accounts payable
Convertible preferred units	22,964	21,715
Class B Convertible Preferred Units [Member]
Accounts payable
Convertible preferred units	$ 14,829	$ 14,635

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - shares	Dec. 31, 2019	Dec. 31, 2018
Limited partners, units issued	30,824,291	30,436,124
Limited partners, units outstanding	30,824,291	30,436,124
Class A Convertible Preferred Units [Member]
Convertible Preferred Units, shares issued	11,627,906	11,627,906
Convertible Preferred Units, shares outstanding	11,627,906	11,627,906
Class B Convertible Preferred Units [Member]
Convertible Preferred Units, shares issued	9,803,921	9,803,921
Convertible Preferred Units, shares outstanding	9,803,921	9,803,921

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenues
(Loss) gain on derivatives, net	$ (10,246)	$ 5,674
Total revenues	55,501	72,788
Operating costs and expenses
Lease operating expenses	31,870	22,537
Production and ad valorem taxes	5,486	5,483
Other operating expenses	2,068	945
Impairment of proved oil and natural gas properties	384	31,160
Impairment of assets held for sale	65
Depreciation, depletion and amortization	10,621	16,751
Dry holes and abandonments of unproved properties		612
Accretion of discount on asset retirement obligations	1,596	721
General and administrative	8,572	6,311
Total operating costs and expenses	60,662	84,520
Gain (loss) on sales of oil and natural gas properties, net	9,671	(509)
Income (loss) from operations	4,510	(12,241)
Other (expense) income
Interest income	10	3
Interest expense	(5,166)	(6,010)
Other expense	(3)	(15)
Gain on sale of other assets	123
(Loss) gain on settlements of asset retirement obligations	(73)	10
Total other expense	(5,109)	(6,012)
Net loss	(599)	(18,253)
Less: Distributions to preferred unitholders	4,643	4,456
Less: General partner's interest in net loss	(7)	(214)
Limited partners' interest in net loss	$ (5,235)	$ (22,495)
Limited partners' interest in net loss per unit
Basic and diluted	$ (0.17)	$ (0.74)
Weighted average limited partner units outstanding
Limited partner units (basic and diluted)	30,764	30,328
Oil Sales [Member]
Revenues
Revenue	$ 63,163	$ 65,206
Natural Gas Sales [Member]
Revenues
Revenue	1,304	1,130
Other Operating Revenues [Member]
Revenues
Revenue	$ 1,280	$ 778

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Cash flows from operating activities
Net loss	$ (599)	$ (18,253)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization	10,621	16,751
Debt issuance costs amortization	702	678
Accretion of discount on asset retirement obligations	1,596	721
Impairment of proved oil and natural gas properties	384	31,160
Impairment of assets held for sale	65
Dry holes and abandonments of unproved properties		612
Loss (gain) on settlements of asset retirement obligations	73	(10)
Cash paid for settlements of asset retirement obligations	(97)	(128)
Loss (gain) on derivatives, net	10,246	(5,674)
Cash settlements paid for matured derivatives, net	(949)	(6,928)
Cash premiums paid for derivatives		(401)
(Gain) loss on sales of oil and natural gas properties	(9,671)	509
Gain on sale of other assets	(123)
Non-cash equity-based compensation	696	744
Changes in operating assets and liabilities
Accounts receivable	(2,856)	1,367
Prepaid expenses and other assets	70	(61)
Accounts payable - trade and accrued liabilities	97	(210)
Accounts payable - related parties	1,554	1,708
Net cash provided by operating activities	11,809	22,585
Cash flows from investing activities
Acquisitions of oil and natural gas properties	(3,331)	(21,243)
Additions to oil and natural gas properties	(13,868)	(8,617)
Proceeds from sales of oil and natural gas properties	33,453	1,044
Proceeds from sale of other assets	123
Net cash provided by (used in) investing activities	16,377	(28,816)
Cash flows from financing activities
Proceeds from line of credit	11,000	22,000
Payments on line of credit	(36,000)	(28,000)
Debt issuance costs	(198)	(681)
Net cash (used in) provided by financing activities	(28,398)	4,866
Net decrease in cash and cash equivalents	(212)	(1,365)
Beginning cash and cash equivalents	467	1,832
Ending cash and cash equivalents	255	467
Class B Convertible Preferred Units [Member]
Cash flows from financing activities
Proceeds from sale of Class B convertible preferred units, net of offering costs		14,847
Distributions to convertible preferred units	(1,200)	(800)
Class A Convertible Preferred Units [Member]
Cash flows from financing activities
Distributions to convertible preferred units	$ (2,000)	$ (2,500)

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - USD ($) shares in Thousands, $ in Thousands	Total	Class A Convertible Preferred Units [Member]	Class B Convertible Preferred Units [Member]	General Partner [Member]	Limited Partner [Member]	Limited Partner [Member]Class A Convertible Preferred Units [Member]	Limited Partner [Member]Class B Convertible Preferred Units [Member]
Balance at Dec. 31, 2017	$ 81,688			$ (572)	$ 82,260
Balance, Units at Dec. 31, 2017					30,091
Increase (Decrease) in Partners' Capital [Roll Forward]
Equity-based compensation	744				$ 744
Equity-based compensation, Units					345
Distributions to convertible preferred units		$ (2,000)	$ (1,100)			$ (2,000)	$ (1,100)
Allocation of value to beneficial conversion feature of Class B convertible preferred units			686				686
Accretion of beneficial conversion feature of convertible preferred units		(1,181)	(175)			(1,181)	(175)
Net loss	(18,253)			(214)	$ (18,039)
Balance at Dec. 31, 2018	60,409			(786)	$ 61,195
Balance, Units at Dec. 31, 2018					30,436
Increase (Decrease) in Partners' Capital [Roll Forward]
Equity-based compensation	696				$ 696
Equity-based compensation, Units					388
Distributions to convertible preferred units		(2,000)	(1,200)			(2,000)	(1,200)
Accretion of beneficial conversion feature of convertible preferred units		$ (1,249)	$ (194)			$ (1,249)	$ (194)
Net loss	(599)			(7)	$ (592)
Balance at Dec. 31, 2019	$ 55,863			$ (793)	$ 56,656
Balance, Units at Dec. 31, 2019					30,824

Organization and Nature of Oper

Organization and Nature of Operations	12 Months Ended
	Dec. 31, 2019
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Nature of Operations	Note 1. Organization and Nature of Operations Nature of Operations Mid-Con Energy Partners, LP is a publicly held Delaware limited partnership formed in July 2011 that engages in the ownership, acquisition and development of producing oil and natural gas properties in North America, with a focus on EOR. Our limited partner units (“common units”) are listed under the symbol “MCEP” on the NASDAQ. Our general partner is Mid-Con Energy GP, a Delaware limited liability company.

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Basis of Presentation and Summary of Significant Accounting Policies	Note 2. Basis of Presentation and Summary of Significant Accounting Policies Basis of Presentation and Principles of Consolidation The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2019 and 2018, and the results of operations, cash flows and changes in equity for the years then ended December 31, 2019 and 2018. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Depletion and impairment of oil and natural gas properties, in part, are determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not Cash and Cash Equivalents We consider all cash on hand, depository accounts held by banks and money market accounts with an original maturity of three months or less to be cash equivalents. Accounts Receivable Accounts receivable are generated from the sale of oil and natural gas to various customers. We routinely assess the financial strength of our customers, and bad debts are recorded based on an account level review after all means of collection have been exhausted, and the potential recovery is considered remote. At December 31, 2019 and 2018, we did not have any reserves for doubtful accounts and we did not incur any expenses related to bad debts in any period presented. Revenue Recognition We adopted ASC 606 effective January 1, 2018, using the modified retrospective approach. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Under ASC 605, we followed the sales method of accounting for oil and natural gas sales revenues in which revenues were recognized on our share of actual proceeds from oil and natural gas sold to purchasers. Revenue recognition required for our oil and natural gas sales contracts by ASC 606 does not differ from revenue recognition required under ASC 605 to account for such contracts. Therefore, we concluded that there was no change in our revenue recognition under ASC 606 and the cumulative effect of applying the new standard to all outstanding contracts as of January 1, 2018, did not result in an adjustment to retained earnings. We had no significant natural gas imbalances at December 31, 2019 and 2018. Revenue from Contracts with Customers . Under our oil and natural gas sales contracts, enforceable rights and obligations arise at the time production occurs on dedicated leases as the Partnership promises to deliver goods in the form of oil or natural gas production on contractually-specified leases to the purchasers. Sales of oil and natural gas are recognized at the point that control of the product is transferred to the customer; title and risk of loss to the product generally transfers at the delivery point specified in the contract. We do not extract NGLs from our natural gas production prior to the sale and transfer of title of the natural gas stream to our purchasers. While some of our purchasers extracted NGLs from the natural gas stream sold by us to them, we had no ownership in such NGLs. The Partnership commits and dedicates for sale all of the oil or natural gas production from contractually agreed-upon leases to the purchaser. Our oil contract pricing provisions are tied to a market index, with certain marketing adjustments, including location and quality differentials as well as certain embedded marketing fees. The majority of our natural gas contract pricing provisions are tied to a market index less customary deductions, such as gathering, processing and transportation. Payment is typically received 30 to 60 days after the date production is delivered. Transaction Price Allocated to Remaining Performance Obligations . Our oil and natural gas sales are generally short-term in nature, with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14, exempting the Partnership from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For our oil and natural gas sales contracts, the variable consideration related to variable production is not estimated because the uncertainty related to the consideration is resolved as the Bbl and Mcf of natural gas are transferred to the customer each day. Therefore, we have utilized the practical expedient in ASC 606-10-50-14(a), which states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations for specific situations in which the Partnership does not need to estimate variable consideration to recognize revenue. Contract Balances . Our oil and natural gas sales contracts do not give rise to contract assets or liabilities under ASC 606. Oil and Natural Gas Properties Our oil and natural gas development and production activities are accounted for using the successful efforts method. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized costs of proved properties are depleted using the units-of-production method based on proved reserves on a field basis. The depreciation of capitalized production equipment is based on the units-of-production method using proved developed reserves on a field basis. Costs associated with unproved properties are excluded from depletion until proved reserves are established or impairment determined. When proven reserves are established, any unproved property costs associated with the project are transferred to proved properties and included in depletion. Unproved properties are assessed at least annually to ascertain whether impairment has occurred. In addition, impairment assessments are made for interim reporting periods if facts and circumstances exist that suggest impairment may have occurred. The impairment test for unproved properties is not based on the estimated fair value of the unproved properties. The impairment assessment includes consideration of our intent to fully develop our unproved properties, remaining lease terms, geological and geophysical evaluations, our drilling results, potential drilling locations, availability of capital, assignment of proved reserves, expected divestitures, anticipated future capital expenditures and economic considerations, among others. Costs of significant proved non-producing properties and wells in the process of being drilled are excluded from depletion until such time as the proved reserves are established or impairment is determined. Costs of significant development projects are excluded from depletion until the related project is completed. We capitalize interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intended use. We had no capitalized interest during any of the periods presented. We have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These ARO are primarily associated with plugging and abandoning wells. We typically incur this liability upon acquiring or drilling a well. Determining the future restoration and removal requires management to make estimates and judgments, including the ultimate settlement amounts, inflation factors, credit-adjusted Derivatives and Hedging Our risk management program is intended to reduce our exposure to commodity price volatility and to assist with stabilizing cash flows. Accordingly, we utilize commodity derivatives (commodity price and differential swaps, calls, puts and collars) to manage a portion of our exposure to commodity prices. We enter into commodity derivative contracts or modify our portfolio of existing commodity derivative contracts when we believe market conditions or other circumstances suggest that it is prudent or as required by our lenders. Derivatives are recorded at fair value and are presented on a net basis on the consolidated balance sheets as assets or liabilities. We net the fair value of derivatives by counterparty where the right of offset exists and determine the fair value of our derivatives by utilizing certain pricing models to validate the data provided by third parties. See Note 6 in this section for additional discussion of our fair value measurements. We do not designate derivatives as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value of unsettled derivative contracts is recorded in current period earnings. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. In addition to mark-to-market adjustments, gains or losses arise from net payments made or received on monthly settlements, proceeds or payments for termination of contracts prior to their expiration and premiums paid or received for new contracts. Any deferred premiums are recorded as a liability and recognized in earnings as the related contracts mature. Gains and losses on derivatives are included in cash flows from operating activities. See Note 5 in this section for discussion regarding derivative financial instruments. Equity-Based Compensation The cost of employee services received in exchange for equity instruments is measured based on the grant-date fair value and is recorded as compensation expense over the requisite service period (often the vesting period). Awards subject to performance criteria vest when it is probable that the performance criteria will be met. We recognize forfeitures of equity awards as they occur. Debt Issuance Costs Debt placement costs are stated at cost, net of amortization, which is computed using the straight-line method and recognized as interest expense in the consolidated statements of operations over the remaining life of the agreement. Since our debt consists of a revolving credit facility, net debt placement costs are presented in “Other Assets” in our consolidated balance sheets. When debt is retired before its scheduled maturity date, any remaining issuance costs associated with that debt are expensed. Income Taxes The Partnership is not taxable for federal income tax purposes. As such, we do not directly pay federal income tax. As appropriate, taxable income or loss is includable in the federal income tax returns of our unitholders. Earnings or losses for financial statement purposes may differ significantly from those reported to the individual unitholders for income tax purposes as a result of differences between the tax basis and financial reporting basis of assets and liabilities. Allocation of Net Income or Loss Net income or loss is allocated to our general partner in proportion to its pro rata ownership during the period. The remaining net income or loss is allocated to the limited partner unitholders net of Preferred Unit distributions, including accretion of the Preferred Unit beneficial conversion feature. In the event of net income, diluted net income per partner unit reflects the potential dilution of non-vested restricted stock awards and the conversion of Preferred Units to common units. Non-cash Investing and Supplemental Cash Flow Information The following presents the non-cash investing and supplemental cash flow information for the periods presented: Year Ended December 31, (in thousands) 2019 2018 Non-cash investing information Change in oil and natural gas properties - assets received in exchange $ 38,533 $ — Change in oil and natural gas properties - accrued capital expenditures $ 1,663 $ 348 Change in oil and natural gas properties - accrued acquisitions $ (1,462 ) $ 1,506 Supplemental cash flow information Cash paid for interest $ 4,644 $ 5,052 Recently Issued Accounting Standards In June 2016, the FASB issued ASC 326, Financial Instruments- Credit Losses

Acquisitions, Divestitures and

Acquisitions, Divestitures and Assets Held for Sale	12 Months Ended
	Dec. 31, 2019
Business Combinations [Abstract]
Acquisitions, Divestitures and Assets Held for Sale	Note 3. Acquisitions, Divestitures and Assets Held for Sale Acquisitions We adopted ASU 2017-01, “ Business Combinations Assets and liabilities assumed in acquisitions accounted for as business combinations are recorded in our consolidated balance sheets at their estimated fair values as of the acquisition date using assumptions that represent Level 3 fair value measurement inputs. See Note 6 in this section for additional discussion of our fair value measurements. Results of operations attributable to the acquisition subsequent to the closing were included in our statements of operations. The operations and cash flows of divested properties are eliminated from our ongoing operations. Pine Tree Business Combination In January 2018, we acquired multiple oil and gas properties located in Campbell and Converse Counties, Wyoming (the “Pine Tree” acquisition). Pine Tree was accounted for as a business combination. We acquired Pine Tree for cash consideration of $8.4 million, after final post-closing purchase price adjustments. The recognized fair values of the Pine Tree assets acquired and liabilities assumed are as follows: (in thousands) Fair value of net assets acquired Proved oil and natural gas properties $ 8,833 Total assets acquired 8,833 Fair value of net liabilities assumed Asset retirement obligation 463 Net assets acquired $ 8,370 The following table presents revenues and expenses of the acquired oil and natural gas properties included in the accompanying consolidated statements of operations for the periods presented: Year Ended December 31, (in thousands) 2019 2018 Oil and natural gas sales $ 1,349 $ 1,116 Expenses (1) $ 1,211 $ 714 (1) Strategic Transaction In March 2019, we simultaneously closed the previously announced definitive agreements to sell substantially all of our oil and natural gas properties located in Texas for $60.0 million and to purchase certain oil and natural gas properties located in Osage, Grady and Caddo Counties in Oklahoma for an aggregate purchase price of $27.5 million, both agreements subject to customary purchase price adjustments. We received net proceeds of $32.5 million at the close of this Strategic Transaction (“Strategic Transaction”) of which $32.0 million was used to reduce borrowings outstanding on our revolving credit facility. The acquired properties were accounted for as an asset acquisition. A gain on the sale of oil and natural gas properties of $9.3 million was reported in the consolidated statements of operations. The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying consolidated statements of operations for the periods presented: Year Ended December 31, (in thousands) 2019 2018 Oil and natural gas sales $ 4,688 $ 25,861 Expenses (1) $ 3,358 $ 39,214 (1) Nolan County Divestiture In January 2018, we completed the sale of certain oil and natural gas proved properties in Nolan County, Texas, for $1.5 million, after final post-closing purchase price adjustments. These properties were deemed to meet held for-sale-accounting criteria as of December 31, 2017, and impairment of $0.3 million was recorded to reduce the carrying value of these assets to their estimated fair value of $1.5 million at December 31, 2017; therefore, no gain or loss was realized on the sale in 2018. Assets Held for Sale Land in Southern Oklahoma met held-for-sale criteria as of December 31, 2019 and 2018. The carrying value of $0.4 million was presented in “Assets held for sale” on our consolidated balance sheet. Impairment of $0.1 million was recorded to reduce the carrying value of the land to its estimated fair value at December 31, 2019.

Equity Awards

Equity Awards	12 Months Ended
	Dec. 31, 2019
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Equity Awards	Note 4. Equity Awards We have a long-term incentive program (the “Long-Term Incentive Program”) for employees, officers, consultants and directors of our general partner and its affiliates, including Mid-Con Energy Operating and ME3 Oilfield Service, who perform services for us. The Long-Term Incentive Program allows for the award of unit options, unit appreciation rights, unrestricted units, restricted units, phantom units, distribution equivalent rights granted with phantom units and other types of awards. The Long-Term Incentive Program is administered by the voting members of the general partner and approved by the Board. If an employee terminates employment prior to the restriction lapse date, the awarded units are forfeited and canceled and are no longer considered issued and outstanding. The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at December 31, 2019: Number of Common Units Approved and authorized awards 3,514,000 Unrestricted units granted (1,350,538 ) Restricted units granted, net of forfeitures (399,424 ) Equity-settled phantom units granted, net of forfeitures (1,490,669 ) Awards available for future grant 273,369 We recognized $0.7 million of total equity-based compensation expense for the years ended December 31, 2019 and 2018. These costs are reported as a component of G&A in our consolidated statements of operations. Unrestricted Unit Awards During the year ended December 31, 2019, we granted 50,000 unrestricted units with an average grant date fair value of $1.04 per unit. During the year ended December 31, 2018, we granted 87,832 unrestricted units with an average grant date fair value of $1.79 per unit. Equity-Settled Phantom Unit Awards Equity-settled phantom units vest over a period of two or three years. During the year ended December 31, 2019, we granted 510,000 equity-settled phantom units with a two-year vesting period and 66,000 equity-settled phantom units with a three-year vesting period. During the year ended December 31, 2018, we granted 450,000 equity-settled phantom awards with a two-year vesting period and 44,500 equity-settled phantom awards with a three-year vesting period. As of December 31, 2019, there were $0.3 million of unrecognized compensation costs related to equity-settled phantom units. These costs are expected to be recognized over a weighted average period of thirteen months. A summary of our equity-settled phantom unit awards for the years ended December 31, 2019 and 2018, is presented below: Number of Equity-Settled Phantom Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2017 117,495 $ 1.45 Units granted 494,500 1.74 Units vested (257,829 ) 1.63 Units forfeited (3,000 ) 1.31 Outstanding at December 31, 2018 351,166 1.73 Units granted 576,000 1.04 Units vested (338,167 ) 1.38 Units forfeited (18,000 ) 1.51 Outstanding at December 31, 2019 570,999 $ 1.25

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2019
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Note 5. Derivative Financial Instruments Our risk management program is intended to reduce our exposure to commodity price volatility and to assist with stabilizing cash flows. Accordingly, we utilize commodity derivative contracts (commodity price and differential swaps, calls, puts and collars) to manage a portion of our exposure to commodity prices. We enter into commodity derivative contracts or modify our portfolio of existing commodity derivative contracts when we believe market conditions or other circumstances suggest that it is prudent or as required by our lenders. We account for our commodity derivative contracts at fair value. See Note 6 in this section for a description of our fair value measurements. We do not designate derivatives as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value of our commodity derivative contracts is recorded in current period earnings. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash gains or losses due to changes in the fair value of our commodity derivative contracts. In addition to mark-to-market adjustments, gains or losses arise from net amounts paid or received on monthly settlements, proceeds from or payments for termination of contracts prior to their expiration and premiums paid or received for new contracts. Any deferred premiums are recorded as a liability and recognized in earnings as the related contracts mature. Gains and losses on derivatives are included in cash flows from operating activities. Pursuant to the accounting standard that permits netting of assets and liabilities where the right of offset exists, we present the fair value of commodity derivative contracts on a net basis. At December 31, 2019, our commodity derivative contracts were in a net liability position with a fair value of $1.2 million, whereas at December 31, 2018, our commodity derivative contracts were in a net asset position with a fair value of $8.1 million. All of our commodity derivative contracts are with major financial institutions that are also lenders under our revolving credit facility. Should one of these financial counterparties not perform, we may not realize the benefit of some of our commodity derivative contracts under lower commodity prices and we could incur a loss. During the years ended December 31, 2019 and 2018, all of our counterparties have performed pursuant to their commodity derivative contracts. The following tables summarize the gross fair value by the appropriate balance sheet classification, even when the derivative financial instruments are subject to netting arrangements and qualify for net presentation in our consolidated balance sheets at December 31, 2019 and 2018: (in thousands) Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheet December 31, 2019 Assets Derivative financial instruments - long-term asset $ 1,635 $ (905 ) $ 730 Total 1,635 (905 ) 730 Liabilities Derivative financial instruments - current liability (1,944 ) — (1,944 ) Derivative financial instruments - long-term liability (905 ) 905 — Total (2,849 ) 905 (1,944 ) Net Liability $ (1,214 ) $ — $ (1,214 ) (in thousands) Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheet December 31, 2018 Assets Derivative financial instruments - current asset $ 5,705 $ (39 ) $ 5,666 Derivative financial instruments - long-term asset 2,418 — 2,418 Total 8,123 (39 ) 8,084 Liabilities Derivative financial instruments - current liability (39 ) 39 — Total (39 ) 39 — Net Asset $ 8,084 $ — $ 8,084 The following table presents the impact of derivative financial instruments and their location within the consolidated statements of operations: Year Ended December 31, (in thousands) 2019 2018 Net settlements on matured derivatives (1) $ (949 ) $ (6,928 ) Net change in fair value of derivatives (9,297 ) 12,602 Total (loss) gain on derivatives, net $ (10,246 ) $ 5,674 (1) At December 31, 2019 and 2018, our commodity derivative contracts had maturities at various dates through December 2021 and were comprised of commodity price and differential swaps and collar contracts. At December 31, 2019, we had the following oil derivatives net positions: Period Covered Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls Hedged/day Index Swaps - 2020 $ 55.81 $ — $ — 1,931 NYMEX-WTI Swaps - 2021 $ 55.78 $ — $ — 672 NYMEX-WTI Collars - 2021 $ — $ 52.00 $ 58.80 672 NYMEX-WTI At December 31, 2018, we had the following oil derivatives net positions: Period Covered Differential Fixed Price Weighted Average Floor Price Total Bbls Hedged/day Index Swaps - 2019 $ — $ 56.14 1,779 NYMEX-WTI Swaps - 2019 $ (20.15 ) $ — 137 WCS-CRUDE-OIL Swaps - 2020 $ — $ 54.81 1,199 NYMEX-WTI

Fair Value Disclosures

Fair Value Disclosures	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Fair Value Disclosures	Note 6. Fair Value Disclosures Fair Value of Financial Instruments The carrying amounts reported in our consolidated balance sheets for cash, accounts receivable and accounts payable approximate their fair values. The carrying amount of debt under our revolving credit facility approximates fair value because the revolving credit facility’s variable interest rate resets frequently and approximates current market rates available to us. We account for our commodity derivative contracts at fair value as discussed in “Assets and Liabilities Measures at Fair Value on a Recurring Basis” below. Fair Value Measurements 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. GAAP establishes a three-tier fair value hierarchy that is intended to increase consistency and comparability in fair value measurements and related disclosures. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Assets and liabilities recorded in the balance sheet are categorized based on the inputs to the valuation technique as follows: Level 1 - Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access. We consider active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an on-going basis. Level 2 - Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability. Level 2 instruments primarily include swap, call, put and collar contracts. Level 3 - Financial assets and liabilities for which values are based on prices or valuation approaches that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability. When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. We had no transfers in or out of Levels 1, 2 or 3 during the years ended December 31, 2019 and 2018. Our estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no changes in valuation approach or related inputs for the years ended December 31, 2019 and 2018. Assets and Liabilities Measured at Fair Value on a Recurring Basis We account for commodity derivative contracts and their corresponding deferred premiums at fair value on a recurring basis utilizing certain pricing models. Inputs to the pricing models include publicly available prices from a compilation of data gathered from third parties and brokers. We validate the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Any deferred premiums associated with our commodity derivative contracts are categorized as Level 3, as we utilize a net present value calculation to determine the valuation. See Note 5 in this section for a summary of our derivative financial instruments. The following sets forth, by level within the hierarchy, the fair value of our assets and liabilities measured at fair value on a recurring basis as of December 31, 2019 and 2018: (in thousands) Level 1 Level 2 Level 3 Fair Value December 31, 2019 Derivative financial instruments - asset $ — $ 1,635 $ — $ 1,635 Derivative financial instruments - liability $ — $ 2,849 $ — $ 2,849 December 31, 2018 Derivative financial instruments - asset $ — $ 8,123 $ — $ 8,123 Derivative financial instruments - liability $ — $ 39 $ — $ 39 A summary of the changes in Level 3 fair value measurements for the periods presented are as follows: Year Ended December 31, (in thousands) 2019 2018 Balance of Level 3 at beginning of period $ — $ (401 ) Derivative deferred premiums - settlements — 401 Balance of Level 3 at end of period $ — $ — Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis Asset Retirement Obligations We estimate the fair value of our ARO based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for ARO, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. See Note 7 in this section for a summary of changes in ARO. Acquisitions The estimated fair values of proved oil and natural gas properties acquired in business combinations are based on a discounted cash flow model and market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk-adjusted discount rates at the acquisition date. Based on the unobservable nature of certain of the inputs, the estimated fair value of the oil and natural gas properties acquired is deemed to use Level 3 inputs. See Note 3 in this section for further discussion of our acquisitions. Reserves We calculate the estimated fair values of reserves and properties using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of reserves, future operating and developmental costs, future commodity prices, a market-based weighted average cost of capital rate and the rate at which future cash flows are discounted to estimate present value. We discount future values by a per annum rate of 10% because we believe this amount approximates our long-term cost of capital and accordingly, is well aligned with our internal business decisions. The underlying commodity prices embedded in our estimated cash flows begin with Level 1 NYMEX-WTI forward curve pricing, less Level 3 assumptions that include location, pricing adjustments and quality differentials. See Note 17 in this section for additional information regarding our oil and natural gas reserves. Impairment The need to test oil and natural gas assets for impairment may result from significant declines in sales prices or downward revisions in estimated quantities of oil and natural gas reserves. If the carrying value of the long-lived assets exceeds the estimated undiscounted future net cash flows, an impairment expense is recognized for the difference between the estimated fair value and the carrying value of the assets. For the years ended December 31, 2019 and 2018, we recorded impairment expense of $0.4 million and $31.2 million, respectively. Additionally, for the year ended December 31, 2019, we recorded impairment expense related to assets held for sale of $0.1 million to reduce the carrying amount of the assets to their fair value.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 7. Asset Retirement Obligations We have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These ARO are primarily associated with plugging and abandoning wells. We typically incur this liability upon acquiring or successfully drilling a well and determine our ARO by calculating the present value of estimated cash flow related to the estimated future liability. Determining the removal and future restoration obligation requires management to make estimates and judgments, including the ultimate settlement amounts, inflation factors, credit-adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. We are required to record the fair value of a liability for the ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. We review our assumptions and estimates of future ARO on an annual basis, or more frequently, if an event or circumstances occur that would impact our assumptions. To the extent future revisions to these assumptions impact the present value of the abandonment liability, management will make corresponding adjustments to both the ARO and the related oil and natural gas property asset balance. The liability is accreted each period toward its future value and is recorded in our consolidated statement of operations. The discounted capitalized cost is amortized to expense through the depreciation calculation over the life of the assets based on proved developed reserves. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability. For the years ended December 31, 2019 and 2018, our ARO were reported as asset retirement obligations in our consolidated balance sheets. Changes in our ARO for the periods indicated are presented in the following table: Year Ended December 31, (in thousands) 2019 2018 Asset retirement obligations - beginning of period $ 26,001 $ 10,326 Liabilities incurred for new wells and interests 8,840 15,497 Liabilities settled upon plugging and abandoning wells (24 ) (138 ) Liabilities removed upon sale of wells (5,795 ) (399 ) Revision of estimates (353 ) (6 ) Accretion expense 1,596 721 Asset retirement obligations - end of period $ 30,265 $ 26,001

Debt

Debt	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt	Note 8. Debt At December 31, 2019 and 2018, we had outstanding borrowings under our revolving credit facility of $68.0 million and $93.0 million, respectively. Our current revolving credit facility matures in May 2021. Borrowings under the facility are secured by liens on not less than 90% of the value of our proved reserves. The borrowing base of our revolving credit facility is collectively determined by our lenders based on the value of our proved oil and natural gas reserves using assumptions regarding future prices, costs and other variables. The borrowing base is subject to scheduled redeterminations in the spring and fall of each year with an additional redetermination, either at our request or at the request of the lenders, during the period between each scheduled borrowing base redetermination. An additional borrowing base redetermination may be made at the request of the lenders in connection with a material disposition of our properties or a material liquidation of a hedge contract. The next regularly scheduled semi-annual redetermination is expected to occur during the spring of 2020. Borrowings under the revolving credit facility bear interest at a floating rate based on, at our election, the greater of the prime rate of Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50% and the one month adjusted London Interbank Offered Rate (“LIBOR”) plus 1.0%, all of which are subject to a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or the applicable LIBOR plus a margin that varies from 2.75% to 3.75% per annum according to the borrowing base usage. For the year ended December 31, 2019, the average effective rate was 5.56%. Any unused portion of the borrowing base will be subject to a commitment fee of 0.50% per annum. Letters of credit are subject to a letter of credit fee that varies from 2.75% to 3.75% according to usage. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general partnership purposes and for funding distributions to our unitholders. The revolving credit facility includes customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, and restrictions on certain transactions and payments, including distributions, and requires us to maintain hedges covering projected production. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the credit agreement, together with accrued interest, could be declared immediately due and payable. As of December 31, 2019, we were in compliance with our financial covenants. On January 31, 2018, Amendment 12 to the credit agreement was executed, extending the maturity of our credit facility from November 2018 until November 2020, and increasing the borrowing base of our revolving credit facility to $125.0 million. The lenders also waived any default or event of default that occurred as a result of our failure to maintain the required leverage ratios for the quarter ended September 30, 2017. The amendment also required us to have a minimum liquidity of 20% to make cash distributions to the Preferred Unitholders. During the fall 2018 semi-annual borrowing base redetermination of our revolving credit facility completed in December 2018, the lender group increased our borrowing base to $135.0 million effective December 19, 2018. There were no changes to the terms or conditions of the credit agreement. On March 28, 2019, in conjunction with closing the Strategic Transaction and serving as our spring redetermination, Amendment 13 to the credit agreement was executed, decreasing our borrowing base to $110.0 million. The amendment also required that the leverage ratio be calculated on a building, period-annualized basis, beginning the second quarter of 2019. See Note 3 in this section for further discussion of the Strategic Transaction. On December 6, 2019, Amendment 14 to the credit agreement was executed, decreasing the borrowing base of the Partnership’s revolving credit facility to $95.0 million. The amendment also extended the maturity date of the revolving credit facility to May 1, 2021, and provided for a benchmark rate replacement to address the transition of LIBOR in 2021. Under the terms of the amendment, the Partnership is required to have a Consolidated Funded Indebtedness to Consolidated EBITDAX of less than 3.0 to 1.0 to make any borrowings above the borrowing cap of $85.0 million, and must maintain a maximum Leverage Ratio of Consolidated Funded Indebtedness to Consolidated EBITDAX that does not exceed: • 4.0 to 1.0 for the quarter ending December 31, 2019, • 3.75 to 1.0 for the quarter ending March 31, 2020, and • 3.5 to 1.0 for the quarter ending June 30, 2020, and thereafter.

Commitment and Contingencies

Commitment and Contingencies	12 Months Ended
	Dec. 31, 2019
Commitments And Contingencies Disclosure [Abstract]
Commitment and Contingencies	Note 9. Commitment and Contingencies Services Agreement We are party to a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating provides certain services to us including management, administrative and operational services. We reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. See Note 11 in this section for additional information. Employment Agreements Our general partner has entered into employment agreements with Charles R. Olmstead and Jeffrey R. Olmstead. The employment agreements automatically renew for one-year terms on August 1st of each year unless either we or the employee gives written notice of termination by the preceding February. Pursuant to the employment agreements, each employee will serve in his respective position with our general partner, as set forth above, and has duties, responsibilities and authority as the Board may specify from time to time, in roles consistent with such positions that are assigned to them. The agreements stipulate that if there is a change of control, termination of employment, with cause or without cause, or death of the executive certain payments will be made to the executive officer. These payments, depending on the reason for termination, currently range from $0.3 million to $0.7 million, including the value of vesting of any outstanding units. Change in Control Severance Plan On July 24, 2019, the Board adopted a Change in Control Severance Plan that provides severance benefits to certain key management and employees of the general partner and its affiliates. The Change in Control Severance Plan provides for the payment of cash compensation and certain other benefits to eligible employees in the event of a change in control and a qualifying termination of employment. The obligations under the Change in Control Severance Plan are generally based on the terminated employee’s cash compensation and position within the Partnership. Depending on the facts and circumstances associated with a potential change in control, the total payments made pursuant to the Change in Control Severance Plan could be material. No liability has been recorded at December 31, 2019, associated with the Change in Control Severance Plan. For a more detailed description of the Change in Control Severance Plan, please refer to our Current Report on Form 8-K filed on July 26, 2019. Legal Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any material legal or governmental proceedings against us under the various environmental protection statutes to which we are subject.

Equity

Equity	12 Months Ended
	Dec. 31, 2019
Equity [Abstract]
Equity	Note 10. Equity Common Units At December 31, 2019 and 2018, the Partnership’s equity consisted of 30,824,291 and 30,436,124 common units, respectively, representing a 98.8% limited partnership interest in us. On May 5, 2015, we entered into an Equity Distribution Agreement to sell, from time to time through or to the Managers (as defined in the agreement), up to $50.0 million in common units representing limited partner interests. In connection with the purchase agreement for the Class A Preferred Units described below, we suspended sales of common units pursuant to the Equity Distribution Agreement effective as of the closing date until August 11, 2021, without the consent of a majority of the holders of the outstanding Preferred Units. Our Partnership Agreement requires us to distribute all of our available cash on a quarterly basis. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs, including cash from working capital borrowings. As of December 31, 2019, cash distributions to our common units continued to be indefinitely suspended. Our credit agreement stipulates written consent from our lenders is required in order to reinstate common unit distributions. Management and the Board will continue to evaluate, on a quarterly basis, the appropriate level of cash reserves in determining future distributions. The suspension of common unit cash distributions is designed to preserve liquidity and reallocate excess cash flow towards capital expenditure projects and debt reduction to maximize long-term value for our unitholders. There is no assurance as to future cash distributions since they are dependent upon our projections for future earnings, cash flows, capital requirements, financial conditions and other factors. Preferred Units The Partnership has issued two classes of Preferred Units. Per accounting guidance, we were required to allocate a portion of the proceeds from Preferred Units to a beneficial conversion feature based on the intrinsic value of the beneficial conversion feature. The intrinsic value is calculated at the commitment date based on the difference between the fair value of the common units at the issuance date (number of common units issuable at conversion multiplied by the per-share value of our common units at the issuance date) and the proceeds attributed to the class of Preferred Units. The beneficial conversion feature is accreted using the effective yield method over the period from the closing date to the effective date of the holder’s conversion right. The holders of our Preferred Units are entitled to certain rights that are senior to the rights of holders of common units, such as rights to distributions and rights upon liquidation of the Partnership. We pay holders of Preferred Units a cumulative, quarterly cash distribution on Preferred Units then outstanding at an annual rate of 8.0%, or in the event that the Partnership’s existing secured indebtedness prevents the payment of a cash distribution to all holders of the Preferred Units, in kind (additional Class A or Class B Preferred Units), at an annual rate of 10.0%. Such distributions will be paid for each such quarter within 45 days after such quarter end, or as otherwise permitted to accumulate pursuant to the Partnership Agreement. Prior to August 11, 2021, each holder of Preferred Units has the right, subject to certain conditions, to convert all or a portion of their Preferred Units into common units representing limited partner interests in the Partnership on a one-for-one basis, subject to adjustment for splits, subdivisions, combinations and reclassifications of the common units. Upon conversion of the Preferred Units, the Partnership will pay any distributions (to the extent accrued and unpaid as of the then most recent Preferred Units distribution date) on the converted units in cash. Class A Preferred Units On August 11, 2016, we completed a private placement of 11,627,906 Class A Preferred Units for an aggregate offering price of $25.0 million. The Class A Preferred Units were issued at a price of $2.15 per Class A Preferred Unit. Proceeds from this issuance were used to fund an acquisition and for general partnership purposes, including the reduction of borrowings under our revolving credit facility. We received net proceeds of $24.6 million in connection with the issuance of these Class A Preferred Units. We allocated these net proceeds, on a relative fair value basis, to the Class A Preferred Units ($18.6 million) and the beneficial conversion feature ($6.0 million). Accretion of the beneficial conversion feature was $1.2 million for the years ended December 31, 2019 and 2018. The registration statement registering resales of common units issued or to be issued upon conversion of the Class A Preferred Units was declared effective by the SEC on June 14, 2017. At December 31, 2019, the Partnership had accrued $0.5 million for the fourth quarter 2019 distributions that will be paid in cash in February 2020. The following table summarizes cash distributions paid on our Class A Preferred Units during the year ended December 31, 2019: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) February 14, 2019 October 1, 2018 - December 31, 2018 $ 0.0430 $ 500 May 14, 2019 January 1, 2019 - March 31, 2019 $ 0.0430 $ 500 August 14, 2019 April 1, 2019 - June 30, 2019 $ 0.0430 $ 500 November 14, 2019 July 1, 2019 - September 30, 2019 $ 0.0430 $ 500 The following table summarizes cash distributions paid on our Class A Preferred Units during the year ended December 31, 2018: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) February 14, 2018 July 1, 2017 - December 31, 2017 $ 0.0860 $ 1,000 May 15, 2018 January 1, 2018 - March 31, 2018 $ 0.0430 $ 500 August 22, 2018 April 1, 2018 - June 30, 2018 $ 0.0430 $ 500 November 14, 2018 July 1, 2018 - September 30, 2018 $ 0.0430 $ 500 Class B Preferred Units On January 31, 2018, we completed a private placement of 9,803,921 Class B Preferred Units for an aggregate offering price of $15.0 million. The Class B Preferred Units were issued at a price of $1.53 per Class B Preferred Unit. Proceeds from this issuance were used to fund the acquisition of certain oil and natural gas properties located in Campbell and Converse Counties, Wyoming, and for general partnership purposes, including the reduction of borrowings under our revolving credit facility. We received net proceeds of $14.9 million in connection with the issuance of these Class B Preferred Units. We allocated these net proceeds, on a relative fair value basis, to the Class B Preferred Units ($14.2 million) and the beneficial conversion feature ($0.7 million). Accretion of the beneficial conversion feature was $0.2 million for the years ended December 31, 2019 and 2018. The registration statement registering resales of common units issued or to be issued upon conversion of the Class B Preferred Units was declared effective by the SEC on May 25, 2018. At December 31, 2019, the Partnership had accrued $0.3 million for the fourth quarter 2019 distribution that will be paid in cash in February 2020. The following table summarizes cash distributions paid on our Class B Preferred Units during the year ended December 31, 2019: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) February 14, 2019 October 1, 2018 - December 31, 2018 $ 0.0306 $ 300 May 14, 2019 January 1, 2019 - March 31, 2019 $ 0.0306 $ 300 August 14, 2019 April 1, 2019 - June 30, 2019 $ 0.0306 $ 300 November 14, 2019 July 1, 2019 - September 30, 2019 $ 0.0306 $ 300 The following table summarizes cash distributions paid on our Class B Preferred Units during the year ended December 31, 2018: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) May 15, 2018 February 1, 2018 - March 31, 2018 $ 0.0204 $ 200 August 22, 2018 April 1, 2018 - June 30, 2018 $ 0.0306 $ 300 November 14, 2018 July 1, 2018 - September 30, 2018 $ 0.0306 $ 300 Allocations of Net Income or Loss Net income or loss is allocated to our general partner in proportion to its pro rata ownership during the period. The remaining net income or loss is allocated to the limited partner unitholders net of Preferred Unit distributions, including accretion of the Preferred Unit beneficial conversion feature. In the event of net income, diluted net income per partner unit reflects the potential dilution of non-vested restricted stock awards and the conversion of Preferred Units.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions	Note 11. Related Party Transactions Agreements with Affiliates The following agreements were negotiated among affiliated parties and, consequently, are not the result of arm’s length negotiations. The following is a description of those agreements that have been entered into with the affiliates of our general partner and with our general partner. Services Agreement We are party to a services agreement with our affiliate, Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating provides certain services to us, including managerial, administrative and operational services. The operational services include marketing, geological and engineering services. We reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by Mid-Con Energy Operating to us. These expenses are included in G&A in our consolidated statements of operations. Operating Agreements We, along with various third parties with an ownership interest in the same property, are parties to standard oil and natural gas joint operating agreements with our affiliate, Mid-Con Energy Operating. We and those third parties pay Mid-Con Energy Operating overhead associated with operating our properties and for its direct and indirect expenses that are chargeable to the wells under their respective operating agreements. The majority of these expenses are included in LOE in our consolidated statements of operations. Oilfield Services We are party to operating agreements, pursuant to which our affiliate, Mid-Con Energy Operating, bills us for oilfield services performed by our affiliates, ME3 Oilfield Service and ME2 Well Services. These amounts are either included in LOE in our consolidated statements of operations or are capitalized as part of oil and natural gas properties in our consolidated balance sheets. Other Agreements We are party to monitoring fee agreements with Bonanza Fund Management, Inc. (“Bonanza”), a Class A Preferred Unitholder, and Goff Focused Strategies, LLC (“GFS”), a Class B Preferred Unitholder, pursuant to which we pay Bonanza and GFS a quarterly monitoring fee in connection with monitoring the purchasers’ investments in the Preferred Units. These expenses are included in G&A in our consolidated statements of operations. The following table summarizes the related party transactions paid for the periods indicated: Year Ended December 31, (in thousands) 2019 2018 Services agreement $ 3,556 $ 2,685 Operating agreements 11,151 8,849 Oilfield services 6,213 3,941 Other agreements 320 310 Total $ 21,240 $ 15,785 At December 31, 2019, we had a net payable to our affiliate, Mid-Con Energy Operating, of $6.9 million, comprised of a joint interest billing payable of $7.8 million and a payable for operating services and other miscellaneous items of $0.8 million, offset by an oil and natural gas revenue receivable of $1.7 million. At December 31, 2018, we had a net payable to our affiliate Mid-Con Energy Operating of $3.7 million, comprised of a joint interest billing payable of $3.7 million and a payable for operating services and other miscellaneous items of $1.2 million, offset by an oil and natural gas revenue receivable of $1.2 million. These amounts were included in accounts payable-related parties in our consolidated balance sheets.

Credit Risk

Credit Risk	12 Months Ended
	Dec. 31, 2019
Risks And Uncertainties [Abstract]
Credit Risk	Note 12. Credit Risk Credit risk relates to the risk of loss resulting from non-performance of non-payment by counterparties under the terms of their contractual obligations, thereby impacting the amount and timing of expected cash flows. Financial instruments which potentially subject us to credit risk consist principally of cash balances, accounts receivable and derivative financial instruments. We maintain cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. We have not experienced any significant losses from such investments. For the year ended December 31, 2019, sales of oil and natural gas to three purchasers accounted for approximately 76% of our sales. At December 31, 2019, these purchasers accounted for approximately 89% of our outstanding oil and natural gas accounts receivable. For the year ended December 31, 2018, sales of oil and natural gas to three purchasers accounted for approximately 83% of our sales. At December 31, 2018, these purchasers accounted for approximately 89% of our outstanding oil and natural gas accounts receivable. We believe that the loss of any one purchaser would not have a material adverse effect on our ability to sell our oil and natural gas production as other purchasers would be accessible. We have not experienced any significant losses due to uncollectible accounts receivable from these purchasers.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2019
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Employee Benefit Plans	Note 13. Employee Benefit Plans In 2011, our general partner adopted the Long-Term Incentive Program which is intended to promote the interests of the Partnership by providing to employees, officers, consultants and directors of our general partner and our other affiliates, including Mid-Con Energy Operating and ME3 Oilfield Service, grants of restricted units, phantom units, unit appreciation rights, distribution equivalent rights and other unit based awards to encourage superior performance. The Long-Term Incentive Program is also intended to enhance the ability of the general partner and our affiliates, to attract and retain the services of individuals who are essential for the growth and profitability of the Partnership and to encourage them to devote their best efforts to advancing the business of the Partnership. The Long-Term Incentive Program is administered by the voting members of our general partner, and awards are approved by the Board. Except as set forth in the employment agreements of the executive officers of our general partner, there is no set formula for granting awards to our employees, officers, consultants and directors of our general partner and our affiliates. In determining whether to grant awards and the amount of any awards, the administrators take into consideration the performance of the Partnership along with discretionary factors such as the individual’s current and expected future performance, level of responsibility, retention considerations and the total compensation package. See Note 4 in this section for additional information regarding awards granted under the Long-Term Incentive Program.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Income Taxes	Note 14. Income Taxes We do not pay federal income taxes, as our profits or losses are reported to the taxing authorities by our individual partners.

Leases

Leases	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Leases	Note 15. Leases We adopted ASC 842, as amended, on January 1, 2019, using the modified retrospective approach. The modified retrospective approach provided a method for recording existing leases at adoption and allowed for a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The adoption of this standard did not result in an adjustment to retained earnings. We elected the transition package of practical expedients permitted under the transition guidance, which among other things, allowed us to carry forward the historical lease classification. We also elected the optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under ASC 840, Leases We lease office space in Tulsa, Oklahoma, Abilene, Texas, and Gillette, Wyoming. Per the short-term accounting policy election, leases with an initial term of 12 months or less were not recorded on the balance sheet, and we recognize lease expense for these leases on a straight-line basis over the term of the lease. Most of our leases include an option to renew. The exercise of the lease renewal options is at our discretion. A summary of our leases is presented below: Year Ended December 31, (in thousands) Classification 2019 2018 Assets Operating Other property and equipment $ 835 $ — Total lease assets $ 835 $ — Liabilities Current operating Other current liabilities $ 430 $ — Non-current operating Other long-term liabilities 457 — Total lease liabilities $ 887 $ — Year Ended December 31, Classification 2019 2018 Operating lease expense (1)(2) G&A expense $ 259 $ 257 Weighted average remaining lease term (months) Operating leases 23 36 Weighted average discount rate Operating leases 5.7 % (3 ) (1) (2) (3) Future minimum lease payments under the non-cancellable operating leases are presented in the following table: (in thousands) Operating Leases 2020 $ 489 2021 471 Total lease maturities 960 Less: interest 73 Present value of lease liabilities $ 887

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2019
Subsequent Events [Abstract]
Subsequent Events	Note 16. Subsequent Events Land Sale On January 23, 2020, we closed the sale of land in Southern Oklahoma, classified as held for sale at December 31, 2019, for a net cash settlement of $0.4 million. Equity Awards On January 29, 2020, the Board authorized the issuance of 32,666 unrestricted common units to replace unvested units to certain employees terminated during a reduction-in-force. Appointment and Departure of Certain Officers and Directors On January 30, 2020, the Partnership announced that Jeffrey R. Olmstead, President and Chief Executive Officer and Director of the general partner, was taking a three-month paid sabbatical commencing on February 1, 2020. Charles R. “Randy” Olmstead, Executive Chairman of the Board, was appointed as Chief Executive Officer of the general partner, and Chad B. Roller, PhD, was appointed as President of the general partner. Dr. Roller was previously appointed as Chief Operating Officer of the general partner effective July 24, 2019. Preferred Unit Distributions A cash distribution of $0.0430 per Class A Preferred Unit, or $0.5 million in aggregate, and a cash distribution of $0.0306 per Class B Preferred Unit, or $0.3 million in aggregate, was paid on February 14, 2020, to holders of record as of the close of business on February 7, 2020. Reverse Stock Split On March 3, 2020, the Partnership announced that the Board has approved a 1-for-10 reverse unit split on the Partnership’s common units, to become effective after the market closes on March 23, 2020.

Supplementary Information

Supplementary Information	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Supplementary Information	Note 17. Supplementary Information Supplementary Oil and Natural Gas Activities Costs incurred in oil and natural gas property acquisitions and development activities are presented below for the periods indicated: Year Ended December 31, (in thousands) 2019 2018 Property acquisition costs Proved $ 3,167 $ 20,158 Unproved 164 1,085 Exploration — — Development 13,868 8,617 Asset retirement obligations 8,487 15,491 Total costs incurred $ 25,686 $ 45,351 Estimated Proved Oil and Natural Gas Reserves (Unaudited) The Partnership’s proved oil and natural gas reserves are all located in the United States. The proved oil and natural gas reserves for the years ended December 31, 2019 and 2018, were prepared by our reservoir engineers and audited by CG&A, independent third party petroleum consultants. These reserve estimates have been prepared in compliance with the rules of the SEC. We emphasize that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates are expected to change as future information becomes available. An analysis of the change in estimated quantities of oil and natural gas reserves are presented below for the periods indicated: Oil (MBbls) Natural Gas (MMcf) MBoe Proved developed and undeveloped reserves As of December 31, 2017 18,510 6,282 19,557 Revisions of previous estimates (1) 1,484 (1,045 ) 1,310 Extensions, discoveries and other additions (2) 72 — 72 Purchases of reserves in place (3) 4,968 1,713 5,253 Sales of reserves in place (4) (133 ) (172 ) (162 ) Production (1,112 ) (457 ) (1,188 ) As of December 31, 2018 23,789 6,321 24,842 Revisions of previous estimates (1) 690 (1,527 ) 436 Extensions, discoveries and other additions — — — Purchases of reserves in place (5) 5,347 1,161 5,541 Sales of reserves in place (5) (3,704 ) (1,058 ) (3,880 ) Production (1,179 ) (676 ) (1,292 ) As of December 31, 2019 24,943 4,221 25,647 Proved developed reserves December 31, 2018 17,634 6,059 18,643 December 31, 2019 19,213 3,965 19,874 Proved undeveloped reserves December 31, 2018 6,155 262 6,199 December 31, 2019 5,730 256 5,773 (1) ( 2 ) (3 ) (4 ) ( 5 ) The increase in quantities of proved reserves from December 31, 2017, to December 31, 2018, was due in part to commodity price increases of 1,975 MBoe which extended the economic lives of certain producing properties, offset in part by net downward revisions of 1,169 MBoe from certain recent results and development modifications. Increased oil production was seen as a response to water injection in our Oklahoma and Texas core areas, resulting in upward revisions to our proved reserves of 504 MBoe. Positive outcomes from step out drilling locations in the Texas core area resulted in an extension within our Hardrock Field and generated an increase in proved reserves of 72 MBoe. During 2018, the acquisition of the Oklahoma and Wyoming waterflood properties resulted in a positive revision of 5,253 MBoe, and the divestiture of several small properties in the Texas core area resulted in a decrease in proved reserves of 162 MBoe. The increase in quantities of proved reserves from December 31, 2018, to December 31, 2019, was due in part to net upward revisions of 2,136 MBoe from certain recent results and development modifications, offset in part by commodity price decreases of 1,700 MBoe which decreased the economic lives of certain producing properties. The net upward revision is primarily the result of restoring production (reactivation of wells) from the acquired Oklahoma waterflood properties. During 2019, the acquisition of the Oklahoma waterflood properties resulted in a positive revision of 5,541 MBoe, and the divestiture of the Texas core area resulted in a decrease in proved reserves of 3,880 MBoe. Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts estimated. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Unaudited) The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, production, plugging and abandonment costs, discounted at the rate prescribed by the SEC. The standardized measure of discounted future net cash flow does not purport to be, nor should it be interpreted to represent, the fair market value of our proved oil and natural gas reserves. The following assumptions have been made: • in the determination of future cash inflows, sales prices used for oil and natural gas for the years ended December 31, 2019 and 2018, were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month in such period; • future costs of developing and producing the proved oil and natural gas reserves were based on costs determined at each such period-end, assuming the continuation of existing economic conditions, including abandonment costs; • no future income tax expenses are computed for the Partnership, because we are a non-taxable entity; and • future net cash flows were discounted at an annual rate of 10%. The standardized measure of discounted future net cash flow relating to estimated proved oil and natural gas reserves is presented below for the periods indicated: Year Ended December 31, (in thousands) 2019 2018 Future cash inflows $ 1,326,502 $ 1,494,349 Future production costs (745,748 ) (694,862 ) Future development costs, including abandonment costs (65,948 ) (92,973 ) Future net cash flow 514,806 706,514 10% discount for estimated timing of cash flow (273,602 ) (358,261 ) Standardized measure of discounted cash flow $ 241,204 $ 348,253 The prices utilized in calculating our total proved reserves were $55.69 and $65.56 per Bbl of oil and $2.58 and $3.10 per MMBtu of natural gas for December 31, 2019 and 2018, respectively. These prices were adjusted by lease for quality, transportation fees, location differentials, marketing bonuses or deductions or other factors affecting the price received at the wellhead. Average adjusted prices used were $52.90 and $62.17 per Bbl of oil and $1.68 and $2.43 per Mcf of natural gas for December 31, 2019 and 2018, respectively. Adjusted natural gas price includes the sale of associated NGLs. During the years ended December 31, 2019 and 2018, we did not extract NGLs from our natural gas production prior to the sale and transfer of title of the natural gas stream to our purchasers. While some of our purchasers extracted NGLs from the natural gas stream sold by us to them, we had no ownership in such NGLs. Therefore, we do not report NGLs in our production or proved reserves. All wellhead prices are held flat over the life of the properties for all reserve categories. Changes in the standardized measure of discounted future net cash flow relating to proved oil and natural gas reserves is presented below for the periods indicated: Year Ended December 31, (in thousands) 2019 2018 Standardized measure of discounted future net cash flow, beginning of year $ 348,253 $ 207,213 Changes in the year resulting from: Sales, less production costs (27,111 ) (38,316 ) Revisions of previous quantity estimates 5,691 24,035 Extensions, discoveries and improved recovery — 2,398 Net change in prices and production costs (113,400 ) 102,480 Net change in income taxes — — Changes in estimated future development costs (13,938 ) 4,534 Previously estimated development costs incurred during the year 14,947 8,428 Purchases of reserves in place 57,679 50,242 Sales of reserves in place (61,715 ) (2,714 ) Accretion of discount 34,825 20,721 Timing differences and other (4,027 ) (30,768 ) Standardized measure of discounted future net cash flow, end of year $ 241,204 $ 348,253

Basis of Presentation and Sum_2

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Basis of presentation and principles of consolidation	Basis of Presentation and Principles of Consolidation The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2019 and 2018, and the results of operations, cash flows and changes in equity for the years then ended December 31, 2019 and 2018.
Use of estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Depletion and impairment of oil and natural gas properties, in part, are determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not
Cash and cash equivalents	Cash and Cash Equivalents We consider all cash on hand, depository accounts held by banks and money market accounts with an original maturity of three months or less to be cash equivalents.
Accounts receivable	Accounts Receivable Accounts receivable are generated from the sale of oil and natural gas to various customers. We routinely assess the financial strength of our customers, and bad debts are recorded based on an account level review after all means of collection have been exhausted, and the potential recovery is considered remote. At December 31, 2019 and 2018, we did not have any reserves for doubtful accounts and we did not incur any expenses related to bad debts in any period presented.
Revenue recognition	Revenue Recognition We adopted ASC 606 effective January 1, 2018, using the modified retrospective approach. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Under ASC 605, we followed the sales method of accounting for oil and natural gas sales revenues in which revenues were recognized on our share of actual proceeds from oil and natural gas sold to purchasers. Revenue recognition required for our oil and natural gas sales contracts by ASC 606 does not differ from revenue recognition required under ASC 605 to account for such contracts. Therefore, we concluded that there was no change in our revenue recognition under ASC 606 and the cumulative effect of applying the new standard to all outstanding contracts as of January 1, 2018, did not result in an adjustment to retained earnings. We had no significant natural gas imbalances at December 31, 2019 and 2018. Revenue from Contracts with Customers . Under our oil and natural gas sales contracts, enforceable rights and obligations arise at the time production occurs on dedicated leases as the Partnership promises to deliver goods in the form of oil or natural gas production on contractually-specified leases to the purchasers. Sales of oil and natural gas are recognized at the point that control of the product is transferred to the customer; title and risk of loss to the product generally transfers at the delivery point specified in the contract. We do not extract NGLs from our natural gas production prior to the sale and transfer of title of the natural gas stream to our purchasers. While some of our purchasers extracted NGLs from the natural gas stream sold by us to them, we had no ownership in such NGLs. The Partnership commits and dedicates for sale all of the oil or natural gas production from contractually agreed-upon leases to the purchaser. Our oil contract pricing provisions are tied to a market index, with certain marketing adjustments, including location and quality differentials as well as certain embedded marketing fees. The majority of our natural gas contract pricing provisions are tied to a market index less customary deductions, such as gathering, processing and transportation. Payment is typically received 30 to 60 days after the date production is delivered. Transaction Price Allocated to Remaining Performance Obligations . Our oil and natural gas sales are generally short-term in nature, with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14, exempting the Partnership from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. For our oil and natural gas sales contracts, the variable consideration related to variable production is not estimated because the uncertainty related to the consideration is resolved as the Bbl and Mcf of natural gas are transferred to the customer each day. Therefore, we have utilized the practical expedient in ASC 606-10-50-14(a), which states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations for specific situations in which the Partnership does not need to estimate variable consideration to recognize revenue. Contract Balances . Our oil and natural gas sales contracts do not give rise to contract assets or liabilities under ASC 606.
Oil and natural gas properties	Oil and Natural Gas Properties Our oil and natural gas development and production activities are accounted for using the successful efforts method. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized costs of proved properties are depleted using the units-of-production method based on proved reserves on a field basis. The depreciation of capitalized production equipment is based on the units-of-production method using proved developed reserves on a field basis. Costs associated with unproved properties are excluded from depletion until proved reserves are established or impairment determined. When proven reserves are established, any unproved property costs associated with the project are transferred to proved properties and included in depletion. Unproved properties are assessed at least annually to ascertain whether impairment has occurred. In addition, impairment assessments are made for interim reporting periods if facts and circumstances exist that suggest impairment may have occurred. The impairment test for unproved properties is not based on the estimated fair value of the unproved properties. The impairment assessment includes consideration of our intent to fully develop our unproved properties, remaining lease terms, geological and geophysical evaluations, our drilling results, potential drilling locations, availability of capital, assignment of proved reserves, expected divestitures, anticipated future capital expenditures and economic considerations, among others. Costs of significant proved non-producing properties and wells in the process of being drilled are excluded from depletion until such time as the proved reserves are established or impairment is determined. Costs of significant development projects are excluded from depletion until the related project is completed. We capitalize interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intended use. We had no capitalized interest during any of the periods presented. We have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These ARO are primarily associated with plugging and abandoning wells. We typically incur this liability upon acquiring or drilling a well. Determining the future restoration and removal requires management to make estimates and judgments, including the ultimate settlement amounts, inflation factors, credit-adjusted
Derivatives and hedging	Derivatives and Hedging Our risk management program is intended to reduce our exposure to commodity price volatility and to assist with stabilizing cash flows. Accordingly, we utilize commodity derivatives (commodity price and differential swaps, calls, puts and collars) to manage a portion of our exposure to commodity prices. We enter into commodity derivative contracts or modify our portfolio of existing commodity derivative contracts when we believe market conditions or other circumstances suggest that it is prudent or as required by our lenders. Derivatives are recorded at fair value and are presented on a net basis on the consolidated balance sheets as assets or liabilities. We net the fair value of derivatives by counterparty where the right of offset exists and determine the fair value of our derivatives by utilizing certain pricing models to validate the data provided by third parties. See Note 6 in this section for additional discussion of our fair value measurements. We do not designate derivatives as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value of unsettled derivative contracts is recorded in current period earnings. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. In addition to mark-to-market adjustments, gains or losses arise from net payments made or received on monthly settlements, proceeds or payments for termination of contracts prior to their expiration and premiums paid or received for new contracts. Any deferred premiums are recorded as a liability and recognized in earnings as the related contracts mature. Gains and losses on derivatives are included in cash flows from operating activities. See Note 5 in this section for discussion regarding derivative financial instruments.
Equity-based compensation	Equity-Based Compensation The cost of employee services received in exchange for equity instruments is measured based on the grant-date fair value and is recorded as compensation expense over the requisite service period (often the vesting period). Awards subject to performance criteria vest when it is probable that the performance criteria will be met. We recognize forfeitures of equity awards as they occur.
Debt placement fee	Debt Issuance Costs Debt placement costs are stated at cost, net of amortization, which is computed using the straight-line method and recognized as interest expense in the consolidated statements of operations over the remaining life of the agreement. Since our debt consists of a revolving credit facility, net debt placement costs are presented in “Other Assets” in our consolidated balance sheets. When debt is retired before its scheduled maturity date, any remaining issuance costs associated with that debt are expensed.
Income taxes	Income Taxes The Partnership is not taxable for federal income tax purposes. As such, we do not directly pay federal income tax. As appropriate, taxable income or loss is includable in the federal income tax returns of our unitholders. Earnings or losses for financial statement purposes may differ significantly from those reported to the individual unitholders for income tax purposes as a result of differences between the tax basis and financial reporting basis of assets and liabilities.
Allocation of Net Income or Loss	Allocation of Net Income or Loss Net income or loss is allocated to our general partner in proportion to its pro rata ownership during the period. The remaining net income or loss is allocated to the limited partner unitholders net of Preferred Unit distributions, including accretion of the Preferred Unit beneficial conversion feature. In the event of net income, diluted net income per partner unit reflects the potential dilution of non-vested restricted stock awards and the conversion of Preferred Units to common units.
Recently Issued Accounting Standards	Recently Issued Accounting Standards In June 2016, the FASB issued ASC 326, Financial Instruments- Credit Losses

Basis of Presentation and Sum_3

Basis of Presentation and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Accounting Policies [Abstract]
Schedule of Non-cash Investing and Cash Flow Supplemental Disclosures	The following presents the non-cash investing and supplemental cash flow information for the periods presented: Year Ended December 31, (in thousands) 2019 2018 Non-cash investing information Change in oil and natural gas properties - assets received in exchange $ 38,533 $ — Change in oil and natural gas properties - accrued capital expenditures $ 1,663 $ 348 Change in oil and natural gas properties - accrued acquisitions $ (1,462 ) $ 1,506 Supplemental cash flow information Cash paid for interest $ 4,644 $ 5,052

Acquisitions, Divestitures an_2

Acquisitions, Divestitures and Assets Held for Sale, Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2019
Texas Assets [Member]
Divestiture Information	The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying consolidated statements of operations for the periods presented: Year Ended December 31, (in thousands) 2019 2018 Oil and natural gas sales $ 4,688 $ 25,861 Expenses (1) $ 3,358 $ 39,214 (1)
Pine Tree [Member]
Acquisitions of Oil Properties	The recognized fair values of the Pine Tree assets acquired and liabilities assumed are as follows: (in thousands) Fair value of net assets acquired Proved oil and natural gas properties $ 8,833 Total assets acquired 8,833 Fair value of net liabilities assumed Asset retirement obligation 463 Net assets acquired $ 8,370
Summary of Revenues and Expenses of Properties Acquired	The following table presents revenues and expenses of the acquired oil and natural gas properties included in the accompanying consolidated statements of operations for the periods presented: Year Ended December 31, (in thousands) 2019 2018 Oil and natural gas sales $ 1,349 $ 1,116 Expenses (1) $ 1,211 $ 714 (1)

Equity Awards (Tables)

Equity Awards (Tables)	12 Months Ended
	Dec. 31, 2019
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of awards under Long-Term Incentive program	The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at December 31, 2019: Number of Common Units Approved and authorized awards 3,514,000 Unrestricted units granted (1,350,538 ) Restricted units granted, net of forfeitures (399,424 ) Equity-settled phantom units granted, net of forfeitures (1,490,669 ) Awards available for future grant 273,369
Summary of equity-settled units	A summary of our equity-settled phantom unit awards for the years ended December 31, 2019 and 2018, is presented below: Number of Equity-Settled Phantom Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2017 117,495 $ 1.45 Units granted 494,500 1.74 Units vested (257,829 ) 1.63 Units forfeited (3,000 ) 1.31 Outstanding at December 31, 2018 351,166 1.73 Units granted 576,000 1.04 Units vested (338,167 ) 1.38 Units forfeited (18,000 ) 1.51 Outstanding at December 31, 2019 570,999 $ 1.25

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Estimated Fair Value of Derivative Assets and Liabilities	The following tables summarize the gross fair value by the appropriate balance sheet classification, even when the derivative financial instruments are subject to netting arrangements and qualify for net presentation in our consolidated balance sheets at December 31, 2019 and 2018: (in thousands) Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheet December 31, 2019 Assets Derivative financial instruments - long-term asset $ 1,635 $ (905 ) $ 730 Total 1,635 (905 ) 730 Liabilities Derivative financial instruments - current liability (1,944 ) — (1,944 ) Derivative financial instruments - long-term liability (905 ) 905 — Total (2,849 ) 905 (1,944 ) Net Liability $ (1,214 ) $ — $ (1,214 ) (in thousands) Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheet December 31, 2018 Assets Derivative financial instruments - current asset $ 5,705 $ (39 ) $ 5,666 Derivative financial instruments - long-term asset 2,418 — 2,418 Total 8,123 (39 ) 8,084 Liabilities Derivative financial instruments - current liability (39 ) 39 — Total (39 ) 39 — Net Asset $ 8,084 $ — $ 8,084
Impact of Derivative Financial Instruments within Condensed Consolidated Statement of Operations	The following table presents the impact of derivative financial instruments and their location within the consolidated statements of operations: Year Ended December 31, (in thousands) 2019 2018 Net settlements on matured derivatives (1) $ (949 ) $ (6,928 ) Net change in fair value of derivatives (9,297 ) 12,602 Total (loss) gain on derivatives, net $ (10,246 ) $ 5,674 (1)
Commodity Contracts	At December 31, 2019 and 2018, our commodity derivative contracts had maturities at various dates through December 2021 and were comprised of commodity price and differential swaps and collar contracts. At December 31, 2019, we had the following oil derivatives net positions: Period Covered Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls Hedged/day Index Swaps - 2020 $ 55.81 $ — $ — 1,931 NYMEX-WTI Swaps - 2021 $ 55.78 $ — $ — 672 NYMEX-WTI Collars - 2021 $ — $ 52.00 $ 58.80 672 NYMEX-WTI At December 31, 2018, we had the following oil derivatives net positions: Period Covered Differential Fixed Price Weighted Average Floor Price Total Bbls Hedged/day Index Swaps - 2019 $ — $ 56.14 1,779 NYMEX-WTI Swaps - 2019 $ (20.15 ) $ — 137 WCS-CRUDE-OIL Swaps - 2020 $ — $ 54.81 1,199 NYMEX-WTI

Fair Value Disclosures (Tables)

Fair Value Disclosures (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Schedule of fair value measurements	The following sets forth, by level within the hierarchy, the fair value of our assets and liabilities measured at fair value on a recurring basis as of December 31, 2019 and 2018: (in thousands) Level 1 Level 2 Level 3 Fair Value December 31, 2019 Derivative financial instruments - asset $ — $ 1,635 $ — $ 1,635 Derivative financial instruments - liability $ — $ 2,849 $ — $ 2,849 December 31, 2018 Derivative financial instruments - asset $ — $ 8,123 $ — $ 8,123 Derivative financial instruments - liability $ — $ 39 $ — $ 39
Schedule of changes in Level 3 fair value measurements	A summary of the changes in Level 3 fair value measurements for the periods presented are as follows: Year Ended December 31, (in thousands) 2019 2018 Balance of Level 3 at beginning of period $ — $ (401 ) Derivative deferred premiums - settlements — 401 Balance of Level 3 at end of period $ — $ —

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Changes in Asset Retirement Obligations	For the years ended December 31, 2019 and 2018, our ARO were reported as asset retirement obligations in our consolidated balance sheets. Changes in our ARO for the periods indicated are presented in the following table: Year Ended December 31, (in thousands) 2019 2018 Asset retirement obligations - beginning of period $ 26,001 $ 10,326 Liabilities incurred for new wells and interests 8,840 15,497 Liabilities settled upon plugging and abandoning wells (24 ) (138 ) Liabilities removed upon sale of wells (5,795 ) (399 ) Revision of estimates (353 ) (6 ) Accretion expense 1,596 721 Asset retirement obligations - end of period $ 30,265 $ 26,001

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2019
Class A Preferred Units [Member]
Cash Distributions - Preferred Unitholders	The following table summarizes cash distributions paid on our Class A Preferred Units during the year ended December 31, 2019: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) February 14, 2019 October 1, 2018 - December 31, 2018 $ 0.0430 $ 500 May 14, 2019 January 1, 2019 - March 31, 2019 $ 0.0430 $ 500 August 14, 2019 April 1, 2019 - June 30, 2019 $ 0.0430 $ 500 November 14, 2019 July 1, 2019 - September 30, 2019 $ 0.0430 $ 500 The following table summarizes cash distributions paid on our Class A Preferred Units during the year ended December 31, 2018: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) February 14, 2018 July 1, 2017 - December 31, 2017 $ 0.0860 $ 1,000 May 15, 2018 January 1, 2018 - March 31, 2018 $ 0.0430 $ 500 August 22, 2018 April 1, 2018 - June 30, 2018 $ 0.0430 $ 500 November 14, 2018 July 1, 2018 - September 30, 2018 $ 0.0430 $ 500
Class B Preferred Units [Member]
Cash Distributions - Preferred Unitholders	The following table summarizes cash distributions paid on our Class B Preferred Units during the year ended December 31, 2019: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) February 14, 2019 October 1, 2018 - December 31, 2018 $ 0.0306 $ 300 May 14, 2019 January 1, 2019 - March 31, 2019 $ 0.0306 $ 300 August 14, 2019 April 1, 2019 - June 30, 2019 $ 0.0306 $ 300 November 14, 2019 July 1, 2019 - September 30, 2019 $ 0.0306 $ 300 The following table summarizes cash distributions paid on our Class B Preferred Units during the year ended December 31, 2018: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) May 15, 2018 February 1, 2018 - March 31, 2018 $ 0.0204 $ 200 August 22, 2018 April 1, 2018 - June 30, 2018 $ 0.0306 $ 300 November 14, 2018 July 1, 2018 - September 30, 2018 $ 0.0306 $ 300

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2019
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The following table summarizes the related party transactions paid for the periods indicated: Year Ended December 31, (in thousands) 2019 2018 Services agreement $ 3,556 $ 2,685 Operating agreements 11,151 8,849 Oilfield services 6,213 3,941 Other agreements 320 310 Total $ 21,240 $ 15,785

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Summary of Leases	A summary of our leases is presented below: Year Ended December 31, (in thousands) Classification 2019 2018 Assets Operating Other property and equipment $ 835 $ — Total lease assets $ 835 $ — Liabilities Current operating Other current liabilities $ 430 $ — Non-current operating Other long-term liabilities 457 — Total lease liabilities $ 887 $ — Year Ended December 31, Classification 2019 2018 Operating lease expense (1)(2) G&A expense $ 259 $ 257 Weighted average remaining lease term (months) Operating leases 23 36 Weighted average discount rate Operating leases 5.7 % (3 ) (1) (2) (3)
Summary of Future Minimum Lease Payments under Non-cancellable Operating Leases	Future minimum lease payments under the non-cancellable operating leases are presented in the following table: (in thousands) Operating Leases 2020 $ 489 2021 471 Total lease maturities 960 Less: interest 73 Present value of lease liabilities $ 887

Supplementary Information (Tabl

Supplementary Information (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Supplementary Oil and Natural Gas Activities	Costs incurred in oil and natural gas property acquisitions and development activities are presented below for the periods indicated: Year Ended December 31, (in thousands) 2019 2018 Property acquisition costs Proved $ 3,167 $ 20,158 Unproved 164 1,085 Exploration — — Development 13,868 8,617 Asset retirement obligations 8,487 15,491 Total costs incurred $ 25,686 $ 45,351
Changes in Estimated Proved Oil and Natural Gas Reserves	An analysis of the change in estimated quantities of oil and natural gas reserves are presented below for the periods indicated: Oil (MBbls) Natural Gas (MMcf) MBoe Proved developed and undeveloped reserves As of December 31, 2017 18,510 6,282 19,557 Revisions of previous estimates (1) 1,484 (1,045 ) 1,310 Extensions, discoveries and other additions (2) 72 — 72 Purchases of reserves in place (3) 4,968 1,713 5,253 Sales of reserves in place (4) (133 ) (172 ) (162 ) Production (1,112 ) (457 ) (1,188 ) As of December 31, 2018 23,789 6,321 24,842 Revisions of previous estimates (1) 690 (1,527 ) 436 Extensions, discoveries and other additions — — — Purchases of reserves in place (5) 5,347 1,161 5,541 Sales of reserves in place (5) (3,704 ) (1,058 ) (3,880 ) Production (1,179 ) (676 ) (1,292 ) As of December 31, 2019 24,943 4,221 25,647 Proved developed reserves December 31, 2018 17,634 6,059 18,643 December 31, 2019 19,213 3,965 19,874 Proved undeveloped reserves December 31, 2018 6,155 262 6,199 December 31, 2019 5,730 256 5,773 (1) ( 2 ) (3 ) (4 ) ( 5 )
Standardized Measure of Discounted Future Net Cash Flow Relating to Estimated Proved Oil and Natural Gas Reserves	The standardized measure of discounted future net cash flow relating to estimated proved oil and natural gas reserves is presented below for the periods indicated: Year Ended December 31, (in thousands) 2019 2018 Future cash inflows $ 1,326,502 $ 1,494,349 Future production costs (745,748 ) (694,862 ) Future development costs, including abandonment costs (65,948 ) (92,973 ) Future net cash flow 514,806 706,514 10% discount for estimated timing of cash flow (273,602 ) (358,261 ) Standardized measure of discounted cash flow $ 241,204 $ 348,253
Changes in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves	Changes in the standardized measure of discounted future net cash flow relating to proved oil and natural gas reserves is presented below for the periods indicated: Year Ended December 31, (in thousands) 2019 2018 Standardized measure of discounted future net cash flow, beginning of year $ 348,253 $ 207,213 Changes in the year resulting from: Sales, less production costs (27,111 ) (38,316 ) Revisions of previous quantity estimates 5,691 24,035 Extensions, discoveries and improved recovery — 2,398 Net change in prices and production costs (113,400 ) 102,480 Net change in income taxes — — Changes in estimated future development costs (13,938 ) 4,534 Previously estimated development costs incurred during the year 14,947 8,428 Purchases of reserves in place 57,679 50,242 Sales of reserves in place (61,715 ) (2,714 ) Accretion of discount 34,825 20,721 Timing differences and other (4,027 ) (30,768 ) Standardized measure of discounted future net cash flow, end of year $ 241,204 $ 348,253

Basis of Presentation and Sum_4

Basis of Presentation and Summary of Significant Accounting Policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2019USD ($)Segment	Dec. 31, 2018USD ($)Segment
Summary Of Significant Accounting Policies [Line Items]
Number of operating segment | Segment	1	1
Reserves for doubtful accounts	$ 0	$ 0
Bad debts expenses	0	0
Significant natural gas imbalances	$ 0	0
Revenue, performance obligation, description of timing	one year or less
Revenue, remaining performance obligation, expected timing of satisfaction	one year or less
Revenue, practical expedient, initial application and transition, nondisclosure of transaction price allocation to remaining performance obligation	true
Interest capitalized during period	$ 0	$ 0
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Payments collection period after date of production delivered	30 days
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Payments collection period after date of production delivered	60 days

Basis of Presentation and Sum_5

Basis of Presentation and Summary of Significant Accounting Policies - Non-cash Investing and Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Non-cash investing information
Change in oil and natural gas properties - assets received in exchange	$ 38,533	$ 0
Change in oil and natural gas properties - accrued capital expenditures	1,663	348
Change in oil and natural gas properties - accrued acquisitions	(1,462)	1,506
Supplemental cash flow information
Cash paid for interest	$ 4,644	$ 5,052

Acquisitions, Divestitures an_3

Acquisitions, Divestitures and Assets Held for Sale - Acquisitions - Additional Information (Details) $ in Millions	1 Months Ended
	Jan. 31, 2018USD ($)
Pine Tree [Member]
Business Acquisition [Line Items]
Aggregate purchase price, net	$ 8.4

Acquisitions, Divestitures an_4

Acquisitions, Divestitures and Assets Held for Sale - Acquisitions of Oil Properties (Details) - Pine Tree [Member] $ in Thousands	Jan. 31, 2018USD ($)
Business Acquisition [Line Items]
Proved oil and natural gas properties	$ 8,833
Total assets acquired	8,833
Asset retirement obligation	463
Net assets acquired	$ 8,370

Acquisitions, Divestitures an_5

Acquisitions, Divestitures and Assets Held for Sale - Summary of Revenues and Expenses of Properties Acquired (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Revenues from oil and natural gas properties acquired		$ 55,501	$ 72,788
Expenses of oil and natural gas properties acquired		60,662	84,520
Pine Tree [Member]
Business Acquisition [Line Items]
Revenues from oil and natural gas properties acquired		1,349	1,116
Expenses of oil and natural gas properties acquired	[1]	$ 1,211	$ 714
[1]	Expenses include LOE, production and ad valorem taxes, accretion and depletion.

Acquisitions, Divestitures an_6

Acquisitions, Divestitures and Assets Held for Sale - Strategic Transaction - Additional Information (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Mar. 31, 2019	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Proceeds from sales of oil and natural gas properties			$ 33,453	$ 1,044
Payment of borrowings outstanding under revolving credit facility	$ 32,000		36,000	28,000
Gain (loss) on sales of oil and natural gas properties, net			$ 9,671	$ (509)
Texas Assets [Member]
Business Acquisition [Line Items]
Aggregate sale price	$ 60,000	$ 60,000
Proceeds from sales of oil and natural gas properties		32,500
Gain (loss) on sales of oil and natural gas properties, net		9,300
Oklahoma Assets [Member]
Business Acquisition [Line Items]
Assets purchased under asset acquisition		$ 27,500

Acquisitions, Divestitures an_7

Acquisitions, Divestitures and Assets Held for Sale - Divestiture Information (Details) - Texas Assets [Member] - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Divestiture [Line Items]
Divestiture oil and gas revenue		$ 4,688	$ 25,861
Divestiture oil and gas expense	[1]	$ 3,358	$ 39,214
[1]	(1) Expenses include LOE, production and ad valorem taxes, accretion, depletion, impairment and dry hole costs.

Acquisitions, Divestitures an_8

Acquisitions, Divestitures and Assets Held for Sale - Divestitures - Additional Information (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Jan. 31, 2018
Divestiture [Line Items]
Impairment of proved oil and natural gas properties held for sale		$ 100,000
Gain (loss) on sales of oil and natural gas properties, net		$ 9,671,000	$ (509,000)
Nolan County [Member]
Divestiture [Line Items]
Aggregate sale price				$ 1,500,000
Impairment of proved oil and natural gas properties held for sale	$ 300,000
Assets held-for-sale, fair value	$ 1,500,000
Gain (loss) on sales of oil and natural gas properties, net			$ 0

Acquisitions, Divestitures an_9

Acquisitions, Divestitures and Assets Held for Sale - Assets Held for Sale - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Divestiture [Line Items]
Assets held for sale	$ 365	$ 430
Southern Oklahoma
Divestiture [Line Items]
Assets held for sale	400
Impairment expense of assets held for sale	$ 100

Equity Awards - Awards availabl

Equity Awards - Awards available for future grant (Details) - Long-Term Incentive Plan [Member]	Dec. 31, 2019shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Approved and authorized awards	3,514,000
Unrestricted units granted	(1,350,538)
Restricted units granted, net of forfeitures	(399,424)
Equity-settled phantom units granted, net of forfeitures	(1,490,669)
Awards available for future grant	273,369

Equity Awards - Additional Info

Equity Awards - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Long-Term Incentive Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation expense	$ 0.7	$ 0.7

Equity Awards - Unrestricted Un

Equity Awards - Unrestricted Units - Additional Information (Details) - Unrestricted Common Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units granted	50,000	87,832
Average grant date fair value per unit, granted	$ 1.04	$ 1.79

Equity Awards - Equity-Settled

Equity Awards - Equity-Settled Phantom Units - Additional Information (Details) - Equity-Settled Phantom Units [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation costs		$ 0.3
Weighted average period, unrecognized costs		13 months
Units granted	576,000	494,500
Tranche Two [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	2 years	2 years
Units granted	510,000	450,000
Tranche Three [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years	3 years
Units granted	66,000	44,500
Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	2 years
Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years

Equity Awards - Equity-Settle_2

Equity Awards - Equity-Settled Phantom Units (Details) - Equity-Settled Phantom Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Number of units
Outstanding, beginning of period	351,166	117,495
Units granted	576,000	494,500
Units vested	(338,167)	(257,829)
Units forfeited	(18,000)	(3,000)
Outstanding, end of period	570,999	351,166
Weighted Average Grant Date Fair Value per Phantom Unit
Average fair value per unit, outstanding, beginning of period	$ 1.73	$ 1.45
Average grant date fair value per unit, granted	1.04	1.74
Average grant date fair value per unit, vested	1.38	1.63
Average grant date fair value per unit, forfeited	1.51	1.31
Average fair value per unit, outstanding, end of period	$ 1.25	$ 1.73

Derivative Financial Instrume_3

Derivative Financial Instruments - Additional information (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Fair value	$ (1,214)	$ 8,084

Derivative Financial Instrume_4

Derivative Financial Instruments - Summary of Gross Fair Value by Appropriate Balance Sheet Classification (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Assets
Derivative Asset, Fair Value, Gross Asset	$ 1,635	$ 8,123
Gross Amounts Offset	(905)	(39)
Net Amount presented - Balance Sheet	730	8,084
Liabilities
Gross Amounts of Recognized Liabilities	(2,849)	(39)
Gross Amounts Offset	905	39
Net Amount presented - Balance Sheet	(1,944)	0
Gross Amounts of Recognized Liabilities	(2,849)	(39)
Gross Amount of Recognized Assets and Liabilities	(1,214)	8,084
Gross Amounts Offset	905	39
Gross Amounts Offset	0	0
Net Amount presented - Balance Sheet	(1,944)	0
Net Assets (Liability) Presented - Balance Sheet	(1,214)	8,084
Derivative Asset, Fair Value, Gross Asset	1,635	8,123
Gross Amounts Offset	(905)	(39)
Net Amount presented - Balance Sheet	730	8,084
Current Asset [Member]
Assets
Derivative Asset, Fair Value, Gross Asset		5,705
Gross Amounts Offset		(39)
Net Amount presented - Balance Sheet		5,666
Liabilities
Derivative Asset, Fair Value, Gross Asset		5,705
Gross Amounts Offset		(39)
Net Amount presented - Balance Sheet		5,666
Long Term Asset [Member]
Assets
Derivative Asset, Fair Value, Gross Asset	1,635	2,418
Gross Amounts Offset	(905)	0
Net Amount presented - Balance Sheet	730	2,418
Liabilities
Derivative Asset, Fair Value, Gross Asset	1,635	2,418
Gross Amounts Offset	(905)	0
Net Amount presented - Balance Sheet	730	2,418
Current Liability [Member]
Liabilities
Gross Amounts of Recognized Liabilities	(1,944)	(39)
Gross Amounts Offset	0	39
Net Amount presented - Balance Sheet	(1,944)	0
Gross Amounts of Recognized Liabilities	(1,944)	(39)
Gross Amounts Offset	0	39
Net Amount presented - Balance Sheet	(1,944)	$ 0
Long Term Liability [Member]
Liabilities
Gross Amounts of Recognized Liabilities	(905)
Gross Amounts Offset	905
Net Amount presented - Balance Sheet	0
Gross Amounts of Recognized Liabilities	(905)
Gross Amounts Offset	905
Net Amount presented - Balance Sheet	$ 0

Derivative Financial Instrume_5

Derivative Financial Instruments - Impact of Derivative Financial Instruments within Condensed Consolidated Statement of Operations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Net settlements on matured derivatives	[1]	$ (949)	$ (6,928)
Net change in fair value of derivatives		(9,297)	12,602
Total (loss) gain on derivatives, net		$ (10,246)	$ 5,674
[1]	The settlement amount does not include premiums paid attributable to contracts that matured during the respective period.

Derivative Financial Instrume_6

Derivative Financial Instruments - Commodity Contracts (Details) - $ / bbl	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Swap [Member] | Period Covered-2020 [Member]
Derivative [Line Items]
Weighted Average Fixed Price	55.81
Weighted Average Floor Price		54.81
Total Bbls Hedged/day	1,931	1,199
Derivative, Underlying Basis	NYMEX-WTI	NYMEX-WTI
Swap [Member] | Period Covered-2021 [Member]
Derivative [Line Items]
Weighted Average Fixed Price	55.78
Total Bbls Hedged/day	672
Derivative, Underlying Basis	NYMEX-WTI
Swap [Member] | Period Covered-2019 [Member]
Derivative [Line Items]
Weighted Average Floor Price		56.14
Total Bbls Hedged/day		1,779
Derivative, Underlying Basis		NYMEX-WTI
Swap [Member] | Period Covered-2019 [Member]
Derivative [Line Items]
Total Bbls Hedged/day		137
Derivative, Underlying Basis		WCS-CRUDE-OIL
Differential Fixed Price		(20.15)
Collars [Member] | Period Covered-2021 [Member]
Derivative [Line Items]
Weighted Average Floor Price	52
Weighted Average Ceiling Price	58.80
Total Bbls Hedged/day	672
Derivative, Underlying Basis	NYMEX-WTI

Fair Value Disclosures - Assets

Fair Value Disclosures - Assets and Liabilities Measured at Fair Value on Recurring Basis and Nonrecurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments - asset	$ 730	$ 8,084
Derivative financial instruments - liability	1,944	0
Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments - asset	1,635	8,123
Derivative financial instruments - liability	2,849	39
Level 1 [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments - asset	0	0
Derivative financial instruments - liability	0	0
Level 2 [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments - asset	1,635	8,123
Derivative financial instruments - liability	2,849	39
Level 3 [Member] | Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments - asset	0	0
Derivative financial instruments - liability	$ 0	$ 0

Fair Value Disclosures - Summar

Fair Value Disclosures - Summary of Changes in assets (liabilities) - Level 3 (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance of Level 3 at beginning of period	$ 0	$ (401)
Derivative deferred premiums - settlements	0	401
Balance of Level 3 at end of period	$ 0	$ 0

Fair Value Disclosures - Additi

Fair Value Disclosures - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Impairment expense	$ 384	$ 31,160
Impairment expense related to assets held for sale	$ 100
Measurement Input, Discount Rate [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Fair Value Inputs, Discount Rate	0.10

Asset Retirement Obligations -

Asset Retirement Obligations - Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation [Roll Forward]
Asset retirement obligations - beginning of period	$ 26,001	$ 10,326
Liabilities incurred for new wells and interests	8,840	15,497
Liabilities settled upon plugging and abandoning wells	(24)	(138)
Liabilities removed upon sale of wells	(5,795)	(399)
Revision of estimates	(353)	(6)
Accretion expense	1,596	721
Asset retirement obligations - end of period	$ 30,265	$ 26,001

Debt - Additional Information (

Debt - Additional Information (Details) - Revolving Credit Facility [Member]	Dec. 06, 2019USD ($)	Jan. 31, 2018USD ($)	Mar. 31, 2020	Dec. 31, 2019USD ($)	Jun. 30, 2020	Dec. 31, 2019USD ($)	Mar. 28, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 19, 2018USD ($)
Line of Credit Facility Line Items
Revolving credit facility				$ 68,000,000		$ 68,000,000		$ 93,000,000
Revolving credit facility maturity date	May 1, 2021					May 31, 2021
Minimum secured loan percentage on lien proved reserves						90.00%
Average effective rate						5.56%
Unused portion of borrowing base, percentage fee						0.50%
Line of credit facility, maximum borrowing capacity	$ 95,000,000	$ 125,000,000					$ 110,000,000		$ 135,000,000
Minimum liquidity percentage for cash distributions to the preferred unit holders		20.00%
Borrowing cap	$ 85,000,000
Federal Funds Effective Swap Rate [Member]
Line of Credit Facility Line Items
Debt instrument, percentage points added to reference rate						0.50%
LIBOR [Member]
Line of Credit Facility Line Items
Debt instrument, percentage points added to reference rate						1.00%
Benchmark rate replacement to address the transition	2021
Minimum [Member]
Line of Credit Facility Line Items
Debt instrument, percentage points added to reference rate						1.75%
Unused portion of borrowing base, percentage fee						2.75%
Consolidated Funded Indebtedness to Consolidated EBITDAX	1			1
Minimum [Member] | Required to Maintain [Member]
Line of Credit Facility Line Items
Consolidated Funded Indebtedness to Consolidated EBITDAX			1		1
Minimum [Member] | LIBOR [Member]
Line of Credit Facility Line Items
Debt instrument, percentage points added to reference rate						2.75%
Maximum [Member]
Line of Credit Facility Line Items
Debt instrument, percentage points added to reference rate						2.75%
Unused portion of borrowing base, percentage fee						3.75%
Consolidated Funded Indebtedness to Consolidated EBITDAX	3			4
Maximum [Member] | Required to Maintain [Member]
Line of Credit Facility Line Items
Consolidated Funded Indebtedness to Consolidated EBITDAX			3.75		3.5
Maximum [Member] | LIBOR [Member]
Line of Credit Facility Line Items
Debt instrument, percentage points added to reference rate						3.75%

Commitment and Contingencies -

Commitment and Contingencies - Additional Information (Details)	12 Months Ended
	Dec. 31, 2019USD ($)
Commitments Contingencies And Litigation [Line Items]
Liability recorded due to change in severance plan	$ 0
Minimum [Member]
Commitments Contingencies And Litigation [Line Items]
Employee Termination Expenses	300,000
Maximum [Member]
Commitments Contingencies And Litigation [Line Items]
Employee Termination Expenses	$ 700,000

Equity - Additional Information

Equity - Additional Information (Details) - USD ($)	May 05, 2015	Dec. 31, 2019	Dec. 31, 2018
Class of Stock [Line Items]
Limited partners, units outstanding		30,824,291	30,436,124
Maximum proceeds under equity distribution agreement - suspended	$ 50,000,000
Mid-Con Energy Partners LP [Member]
Class of Stock [Line Items]
Limited partnership interest		98.80%	98.80%

Equity - Preferred Units - Addi

Equity - Preferred Units - Additional Information (Details) $ / shares in Units, $ in Thousands	Jan. 31, 2018USD ($)$ / sharesshares	Aug. 11, 2016USD ($)$ / sharesshares	Dec. 31, 2019USD ($)Class	Dec. 31, 2018USD ($)
Preferred Units [Member]
Class of Stock [Line Items]
Number of class of preferred units issued | Class			2
Days after quarter end distribution paid			45 days
Preferred Units [Member] | Cash Dividends [Member]
Class of Stock [Line Items]
Dividend rate (percentage)			8.00%
Preferred Units [Member] | In Kind Dividends [Member]
Class of Stock [Line Items]
Dividend rate (percentage)			10.00%
Class A Preferred Units [Member]
Class of Stock [Line Items]
Preferred Units, Issued | shares		11,627,906
Proceeds from sale of convertible preferred units, gross		$ 25,000
Price per share for preferred units (in dollars per share) | $ / shares		$ 2.15
Proceeds from sale of convertible preferred units, net of offering costs		$ 24,600
Net proceeds allocated, fair value basis, to Preferred Units		18,600
Allocation of value to beneficial conversion feature of convertible preferred units		$ 6,000
Accretion of beneficial conversion			$ 1,200	$ 1,200
Preferred units distribution accrued			$ 500
Preferred units distribution payable date to be paid month and year			2020-02
Class B Preferred Units [Member]
Class of Stock [Line Items]
Proceeds from sale of convertible preferred units, net of offering costs				14,847
Allocation of value to beneficial conversion feature of convertible preferred units				686
Preferred units distribution accrued			$ 300
Preferred units distribution payable date to be paid month and year			2020-02
Class B Preferred Units [Member] | Private Placement [Member]
Class of Stock [Line Items]
Preferred Units, Issued | shares	9,803,921
Proceeds from sale of convertible preferred units, gross	$ 15,000
Proceeds from sale of convertible preferred units, net of offering costs	14,900
Net proceeds allocated, fair value basis, to Preferred Units	14,200
Allocation of value to beneficial conversion feature of convertible preferred units	$ 700
Accretion of beneficial conversion			$ 200	$ 200
Price per share for preferred units | $ / shares	$ 1.53

Equity - Cash Distributions Pre

Equity - Cash Distributions Preferred Unitholders (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 14, 2019	Aug. 14, 2019	May 14, 2019	Feb. 14, 2019	Nov. 14, 2018	Aug. 22, 2018	May 15, 2018	Feb. 14, 2018	Dec. 31, 2019	Dec. 31, 2018
Class A Preferred Units [Member] | October 1, 2018 - December 31, 2018 [Member]
Preferred Units [Line Items]
Date Paid									Feb. 14, 2019
Distribution per Unit				$ 0.0430
Total Distributions				$ 500
Class A Preferred Units [Member] | January 1, 2019 - March 31, 2019 [Member]
Preferred Units [Line Items]
Date Paid									May 14, 2019
Distribution per Unit			$ 0.0430
Total Distributions			$ 500
Class A Preferred Units [Member] | April 1, 2019 - June 30, 2019 [Member]
Preferred Units [Line Items]
Date Paid									Aug. 14, 2019
Distribution per Unit		$ 0.0430
Total Distributions		$ 500
Class A Preferred Units [Member] | July 1, 2019 - September 30, 2019 [Member]
Preferred Units [Line Items]
Date Paid									Nov. 14, 2019
Distribution per Unit	$ 0.0430
Total Distributions	$ 500
Class A Preferred Units [Member] | July 1, 2017 - December 31, 2017 [Member]
Preferred Units [Line Items]
Date Paid										Feb. 14, 2018
Distribution per Unit								$ 0.0860
Total Distributions								$ 1,000
Class A Preferred Units [Member] | January 1, 2018 - March 31, 2018 [Member]
Preferred Units [Line Items]
Date Paid										May 15, 2018
Distribution per Unit							$ 0.0430
Total Distributions							$ 500
Class A Preferred Units [Member] | April 1, 2018 - June 30, 2018 [Member]
Preferred Units [Line Items]
Date Paid										Aug. 22, 2018
Distribution per Unit						$ 0.0430
Total Distributions						$ 500
Class A Preferred Units [Member] | July 1, 2018 - September 30, 2018 [Member]
Preferred Units [Line Items]
Date Paid										Nov. 14, 2018
Distribution per Unit					$ 0.0430
Total Distributions					$ 500
Class B Preferred Units [Member] | October 1, 2018 - December 31, 2018 [Member]
Preferred Units [Line Items]
Date Paid									Feb. 14, 2019
Distribution per Unit				$ 0.0306
Total Distributions				$ 300
Class B Preferred Units [Member] | January 1, 2019 - March 31, 2019 [Member]
Preferred Units [Line Items]
Date Paid									May 14, 2019
Distribution per Unit			$ 0.0306
Total Distributions			$ 300
Class B Preferred Units [Member] | April 1, 2019 - June 30, 2019 [Member]
Preferred Units [Line Items]
Date Paid									Aug. 14, 2019
Distribution per Unit		$ 0.0306
Total Distributions		$ 300
Class B Preferred Units [Member] | July 1, 2019 - September 30, 2019 [Member]
Preferred Units [Line Items]
Date Paid									Nov. 14, 2019
Distribution per Unit	$ 0.0306
Total Distributions	$ 300
Class B Preferred Units [Member] | April 1, 2018 - June 30, 2018 [Member]
Preferred Units [Line Items]
Date Paid										Aug. 22, 2018
Distribution per Unit						$ 0.0306
Total Distributions						$ 300
Class B Preferred Units [Member] | July 1, 2018 - September 30, 2018 [Member]
Preferred Units [Line Items]
Date Paid										Nov. 14, 2018
Distribution per Unit					$ 0.0306
Total Distributions					$ 300
Class B Preferred Units [Member] | February 1, 2018 - March 31, 2018 [Member]
Preferred Units [Line Items]
Date Paid										May 15, 2018
Distribution per Unit							$ 0.0204
Total Distributions							$ 200

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Details) - Mid-Con Energy Operating [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Services agreement	$ 3,556	$ 2,685
Operating agreements	11,151	8,849
Oilfield services	6,213	3,941
Other agreements	320	310
Total	$ 21,240	$ 15,785

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - Mid-Con Energy Operating [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Related Party Transaction [Line Items]
Other transactions of related party	$ 6.9	$ 3.7
Joint interest billing payable	7.8	3.7
Operating services and other miscellaneous items payable	0.8	1.2
Oil and natural gas revenue receivable	$ 1.7	$ 1.2

Credit Risk - Additional Inform

Credit Risk - Additional Information (Detail) - Customer Concentration Risk [Member]	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Sales Revenue, Net [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	76.00%	83.00%
Accounts Receivable [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	89.00%	89.00%

Leases - Additional Information

Leases - Additional Information (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Jan. 01, 2019
Lessee Lease Description [Line Items]
Lease assets	$ 835
Lease liabilities	$ 887
ASC 842 [Member]
Lessee Lease Description [Line Items]
Lease assets		$ 1,200
Lease liabilities		$ 1,300

Leases - Summary of Leases (Det

Leases - Summary of Leases (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Assets
Operating		$ 835
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]		us-gaap:PropertyPlantAndEquipmentOther
Total lease assets		$ 835
Liabilities
Current operating		$ 430
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]		us-gaap:OtherLiabilitiesCurrent
Non-current operating		$ 457
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]		us-gaap:OtherLiabilitiesNoncurrent
Total lease liabilities		$ 887
Operating leases, Weighted average remaining lease term (months)		23 months	36 months
Operating leases, Weighted average discount rate		5.70%
G&A expense [Member]
Lessee Lease Description [Line Items]
Operating lease expense	[1],[2]	$ 259	$ 257
[1]	Includes short-term leases.
[2]	There is not a material difference between cash paid and amortized expense.

Leases - Summary of Future Mini

Leases - Summary of Future Minimum Lease Payments under Non-cancellable Operating Leases (Details) $ in Thousands	Dec. 31, 2019USD ($)
Leases [Abstract]
2020	$ 489
2021	471
Total lease maturities	960
Less: interest	73
Present value of lease liabilities	$ 887

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - Subsequent Event [Member] - USD ($) $ / shares in Units, $ in Millions	Mar. 23, 2020	Feb. 14, 2020	Jan. 23, 2020	Jan. 29, 2020
Subsequent Event [Line Items]
Distributions, date to be paid		Feb. 14, 2020
Distributions payable, date of record		Feb. 7, 2020
Reverse stock split conversion ratio	0.01
Class A Preferred Units [Member]
Subsequent Event [Line Items]
Distribution per Unit		$ 0.0430
Preferred Units Distributions Declared		$ 0.5
Class B Preferred Units [Member] | Additional Preferred Units [Member]
Subsequent Event [Line Items]
Distribution per Unit		$ 0.0306
Preferred Units Distributions Declared		$ 0.3
Unrestricted Common Units [Member]
Subsequent Event [Line Items]
Units authorized				32,666
Southern Oklahoma
Subsequent Event [Line Items]
Proceed from net cash settlement asset held for sale			$ 0.4

Supplementary Information - Sup

Supplementary Information - Supplementary Oil and Natural Gas Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Property acquisition costs
Proved	$ 3,167	$ 20,158
Unproved	164	1,085
Exploration	0	0
Development	13,868	8,617
Asset retirement obligations	8,487	15,491
Total costs incurred	$ 25,686	$ 45,351

Supplementary Information - Cha

Supplementary Information - Changes in Estimated Proved Oil and Natural Gas Reserves (Detail)		12 Months Ended
		Dec. 31, 2019MMcfeMBoeMBblsMMcf		Dec. 31, 2018MMcfeMBoeMBblsMMcf
Proved Developed and Undeveloped Reserves, Gas [Roll Forward]
Revisions of previous estimates				504
Purchases of reserves in place		5,541		5,253
Beginning balance		24,842		19,557
Revisions of previous estimates	[1]	436		1,310
Extensions, discoveries and other additions	[2]			72
Purchases of reserves in place		5,541	[3]	5,253	[4]
Sales of reserves in place		(3,880)	[3]	(162)	[5]
Production		(1,292)		(1,188)
Ending balance		25,647		24,842
Proved developed reserves, MBoe		19,874		18,643
Proved developed reserves, MBoe		5,773		6,199
Oil
Proved Developed and Undeveloped Reserves, Oil [Roll Forward]
Beginning balance | MBbls		23,789		18,510
Revisions of previous estimates | MBbls	[1]	690		1,484
Extensions, discoveries and other additions | MBbls	[2]			72
Purchases of reserves in place | MBbls		5,347	[3]	4,968	[4]
Sales of reserves in place | MBbls		(3,704)	[3]	(133)	[5]
Production | MBbls		(1,179)		(1,112)
Ending balance | MBbls		24,943		23,789
Proved developed reserves, Oil | MBbls		19,213		17,634
Proved undeveloped reserves, Oil | MBbls		5,730		6,155
Natural Gas
Proved Developed and Undeveloped Reserves, Gas [Roll Forward]
Beginning balance | MMcfe		6,321		6,282
Revisions of previous estimates | MMcfe	[1]	(1,527)		(1,045)
Purchases of reserves in place | MMcfe		1,161	[3]	1,713	[4]
Sales of reserves in place | MMcf		(1,058)	[3]	(172)	[5]
Production | MMcfe		(676)		(457)
Ending balance | MMcfe		4,221		6,321
Proved developed reserves, Gas | MMcf		3,965		6,059
Proved developed reserves, Gas | MMcf		256		262
[1]	Revisions represent changes in the previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such a commodity prices, operating costs or development costs.
[2]	Extension of our Hardrock Field in the Texas core area as a result of drilling one successful step out well in 2018.
[3]	Represents the purchase and sale of proved reserves as part of the Strategic Transaction.
[4]	Represents the purchase of proved reserves as part of our Oklahoma and Wyoming acquisitions.
[5]	Decrease due to the sale of several small properties in the Texas core area.

Supplementary Information - Add

Supplementary Information - Additional Information (Detail)		12 Months Ended
		Dec. 31, 2019MMcfeMBoe$ / bbl$ / MMBTU$ / Mcf		Dec. 31, 2018MMcfeMBoe$ / bbl$ / MMBTU$ / Mcf
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Effect of Commodity Price		1,700		1,975
Proved Developed and Undeveloped Reserve Net Downward Revision of Previous Estimate Energy		2,136		1,169
Proved Developed and Undeveloped Reserves, Improved Recovery				72
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate				504
Sales of reserves in place		3,880	[1]	162	[2]
Purchases of reserves in place		5,541		5,253
Future net cash flows, annual discount rate		10.00%
Oil
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Representative SEC Price | $ / bbl		55.69		65.56
Average adjusted prices utilized in calculating proved reserves | $ / bbl		52.90		62.17
Natural Gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate | MMcfe	[3]	(1,527)		(1,045)
Purchases of reserves in place | MMcfe		1,161	[1]	1,713	[4]
Representative SEC Price | $ / MMBTU		2.58		3.10
Average adjusted prices utilized in calculating proved reserves | $ / Mcf		1.68		2.43
[1]	Represents the purchase and sale of proved reserves as part of the Strategic Transaction.
[2]	Decrease due to the sale of several small properties in the Texas core area.
[3]	Revisions represent changes in the previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such a commodity prices, operating costs or development costs.
[4]	Represents the purchase of proved reserves as part of our Oklahoma and Wyoming acquisitions.

Supplementary Information - Sta

Supplementary Information - Standardized Measure of Discounted Future Net Cash Flow Relating to Estimated Proved Oil and Natural Gas Reserves (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Future cash inflows	$ 1,326,502	$ 1,494,349
Future production costs	(745,748)	(694,862)
Future development costs, including abandonment costs	(65,948)	(92,973)
Future net cash flow	514,806	706,514
10% discount for estimated timing of cash flow	(273,602)	(358,261)
Standardized measure of discounted cash flow	$ 241,204	$ 348,253	$ 207,213

Supplementary Information - C_2

Supplementary Information - Changes in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure of discounted future net cash flow, beginning of year	$ 348,253	$ 207,213
Changes in the year resulting from:
Sales, less production costs	(27,111)	(38,316)
Revisions of previous quantity estimates	5,691	24,035
Extensions, discoveries and improved recovery	0	2,398
Net change in prices and production costs	(113,400)	102,480
Net change in income taxes	0	0
Changes in estimated future development costs	(13,938)	4,534
Previously estimated development costs incurred during the year	14,947	8,428
Purchases of reserves in place	57,679	50,242
Sales of reserves in place	(61,715)	(2,714)
Accretion of discount	34,825	20,721
Timing differences and other	(4,027)	(30,768)
Standardized measure of discounted future net cash flow, end of year	$ 241,204	$ 348,253