Energy Resources 12 10-K 22 Mar 23 2022 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2022	Mar. 22, 2023	Jun. 30, 2022
Document Information Line Items
Entity Registrant Name	Energy Resources 12, L.P.
Document Type	10-K
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		11,031,579
Entity Public Float			$ 0
Amendment Flag	false
Entity Central Index Key	0001696088
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Well-known Seasoned Issuer	No
Document Period End Date	Dec. 31, 2022
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
ICFR Auditor Attestation Flag	false
Document Annual Report	true
Document Transition Report	false
Entity File Number	000-55916
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	81-4805237
Entity Address, Address Line One	120 W 3rd Street, Suite 220
Entity Address, City or Town	Fort Worth
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	76102
City Area Code	817
Local Phone Number	882-9192
Title of 12(g) Security	Common Units of Limited Partnership Interest
Entity Interactive Data Current	Yes
Auditor Name	Ernst & Young LLP
Auditor Location	Richmond, Virginia
Auditor Firm ID	42

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Assets
Cash and cash equivalents	$ 18,442,414	$ 13,058,237
Accounts receivable and other current assets	9,360,950	6,107,403
Total Current Assets	27,803,364	19,165,640
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $65,100,662 and $51,325,366, respectively	179,376,326	181,409,033
Total Assets	207,179,690	200,574,673
Liabilities
Accounts payable and accrued expenses	4,449,340	3,033,067
Total Current Liabilities	4,449,340	3,033,067
Asset retirement obligations	695,889	743,583
Total Liabilities	5,145,229	3,776,650
Partners’ Equity
Limited partners' interest (11,031,579 common units issued and outstanding, respectively)	202,034,676	196,798,238
General partner's interest	(215)	(215)
Total Partners’ Equity	202,034,461	196,798,023
Total Liabilities and Partners’ Equity	$ 207,179,690	$ 200,574,673

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Oil and natural gas properties, successful efforts method, accumulated depreciation, depletion and amortization (in Dollars)	$ 65,100,662	$ 51,325,366
Limited partners' interest, common units issued	11,031,579	11,031,579
Limited partners' interest, common units outstanding	11,031,579	11,031,579

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Revenues
Oil	$ 47,366,846	$ 46,375,794
Natural gas	5,981,108	5,238,149
Natural gas liquids	4,800,447	6,295,858
Total revenue	58,148,401	57,909,801
Operating costs and expenses
Production expenses	16,367,549	17,593,947
Production taxes	4,698,786	4,400,790
General and administrative expenses	2,393,441	2,383,557
Depreciation, depletion, amortization and accretion	13,720,213	15,285,464
Total operating costs and expenses	37,179,989	39,663,758
Operating income (loss)	20,968,412	18,246,043
Interest income (expense), net	148,920	(380)
Loss on derivatives, net	0	(1,382,905)
Total other income (expense), net	148,920	(1,383,285)
Net income	$ 21,117,332	$ 16,862,758
Basic and diluted net income per common unit (in Dollars per share)	$ 1.91	$ 1.53
Weighted average common units outstanding - basic and diluted (in Shares)	11,031,579	11,031,579

Consolidated Statements of Part

Consolidated Statements of Partners' Equity - USD ($)	Total	Limited Partner [Member]	General Partner [Member]
Balance at Dec. 31, 2020	$ 195,998,356	$ 195,998,571	$ (215)
Balance (in Shares) at Dec. 31, 2020		11,031,579
Distributions declared and paid to common units	(15,698,091)	$ (15,698,091)
Estimated state tax withholding for limited partners	(365,000)	(365,000)
Net income	16,862,758	16,862,758
Balance at Dec. 31, 2021	$ 196,798,023	$ 196,798,238	(215)
Balance (in Shares) at Dec. 31, 2021	11,031,579	11,031,579
Balance at Dec. 31, 2020	$ 195,998,356	$ 195,998,571	(215)
Balance (in Shares) at Dec. 31, 2020		11,031,579
Estimated state tax withholding for limited partners	800,000
Balance at Dec. 31, 2022	$ 202,034,461	$ 202,034,676	(215)
Balance (in Shares) at Dec. 31, 2022	11,031,579	11,031,579
Balance at Dec. 31, 2021	$ 196,798,023	$ 196,798,238	(215)
Balance (in Shares) at Dec. 31, 2021	11,031,579	11,031,579
Distributions declared and paid to common units	$ (15,401,894)	$ (15,401,894)
Estimated state tax withholding for limited partners	(479,000)	(479,000)
Net income	21,117,332	21,117,332
Balance at Dec. 31, 2022	$ 202,034,461	$ 202,034,676	$ (215)
Balance (in Shares) at Dec. 31, 2022	11,031,579	11,031,579

Consolidated Statements of Pa_2

Consolidated Statements of Partners' Equity (Parentheticals) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
General Partner [Member]
Distributions declared and paid per unit	$ 1.396164	$ 1.423014

Consolidated Statement of Cash

Consolidated Statement of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Cash flow from operating activities:
Net income	$ 21,117,332	$ 16,862,758
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion	13,720,213	15,285,464
(Gain) loss on mark-to-market of derivatives		(594,632)
Changes in operating assets and liabilities:
Accounts receivable and other current assets	(3,253,547)	(478,377)
Accounts payable and accrued expenses	(102,461)	(57,123)
Net cash flow provided by operating activities	31,481,537	31,018,090
Cash flow from investing activities:
Additions to oil and natural gas properties	(10,695,466)	(5,338,602)
Net cash flow used in investing activities	(10,695,466)	(5,338,602)
Cash flow from financing activities:
Distributions paid to limited partners	(15,401,894)	(15,698,091)
Net cash flow used in financing activities	(15,401,894)	(15,698,091)
Increase in cash and cash equivalents	5,384,177	9,981,397
Cash and cash equivalents, beginning of period	13,058,237	3,076,840
Cash and cash equivalents, end of period	18,442,414	13,058,237
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$ 2,201,924	$ 1,162,189

Partnership Organization

Partnership Organization	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]	Note 1. Partnership Organization Energy Resources 12, L.P. (together with its wholly-owned subsidiary, the “Partnership”) is a Delaware limited partnership formed to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties. The initial capitalization of the Partnership of $1,000 occurred on December 30, 2016. The Partnership completed its best-efforts offering in October 2019 with a total of approximately 11.0 million common units sold for gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million. As of December 31, 2022, the Partnership owned an approximate 5.7% non-operated working interest in 403 producing wells, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”). The Partnership also owns an estimated approximate 0.2% non-operated working interest in 8 wells in various stages of the drilling and completion process, and possible future development locations in the Bakken Assets. The Bakken Assets, which are a part of the Bakken shale formation in the Greater Williston Basin, are operated by 12 third-party operators on behalf of the Partnership and other working interest owners. The general partner of the Partnership is Energy Resources 12 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership. The Partnership’s fiscal year ends on December 31.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	Note 2. Summary of Significant Accounting Policies Basis of Presentation The accompanying financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”). Cash and Cash Equivalents Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits. Fair Value of Other Financial Instruments The carrying value of the Partnership’s other financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and accrued expenses, reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments. Property and Depreciation, Depletion and Amortization The Partnership accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of oil and natural gas properties are depleted using the unit-of-production method on a field basis based on estimated proved developed and/or undeveloped oil, natural gas and NGL reserves. No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties. The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions. Impairment The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of the properties exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an impairment expense equal to the difference between the carrying value and the fair value of the properties, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. The underlying commodity prices used in the determination of estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates, including appropriate escalators, are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment. Use of Estimates The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Of these estimates and assumptions, management considers the estimation of oil, natural gas and NGL reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as depreciation, depletion and amortization (“DD&A”) and impairment calculations. On an annual basis, the Partnership’s independent consulting petroleum engineer, with assistance from the Partnership, prepares estimates of oil, natural gas and NGL reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the Securities and Exchange Commission (“SEC”), the reserve estimates were based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period excluding escalations based upon future conditions. For impairment purposes, projected NYMEX forward strip prices for oil, natural gas and NGL as estimated by management are used. Oil, natural gas and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future oil, natural gas and NGL pricing assumptions are used by management to prepare estimates of oil, natural gas and NGL reserves used in formulating management’s overall operating decisions. The Partnership does not operate its oil and natural gas properties and, therefore, receives actual oil, natural gas and NGL sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case, the most current available production data is gathered from the appropriate operators, and oil, natural gas and NGL index prices local to each well are used to estimate the accrual of revenue on these wells. The oil, natural gas and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, natural gas and NGLs. These variables could lead to an over or under accrual of oil, natural gas and NGL sales at the end of any particular quarter. However, the Partnership adjusts the estimated accruals of revenue to actual production in the period actual production is determined. Revenue Recognition The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Accounts receivable and other current assets in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers. Accounts Receivable and Concentration of Credit Risk Substantially all of the Partnership’s accounts receivable are due from the operators of the Partnership’s oil and natural gas properties in North Dakota (the operators have accounts receivable from purchasers of oil, natural gas and NGLs). Oil, natural gas and NGL sales receivables are generally unsecured. This industry and location concentration has the potential to impact the Partnership’s overall exposure to credit risk, in that the purchasers of the Partnership’s oil, natural gas and NGLs and the operators of the properties the Partnership has an interest in may be similarly affected by changes in economic, industry or other conditions. At December 31, 2022 and 2021, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible and the Partnership’s operators do not have a history of non-payment. For the years ended December 31, 2022 and 2021, approximately 91% and 92% of the Partnership’s total revenue was generated through sales by four of its 12 operators, respectively. All oil and natural gas producing activities of the Partnership are in North Dakota and represent substantially all of the business activities of the Partnership. Accounting for Asset Retirement Obligations The Partnership has significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. The removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance. The following table shows the activity for the years ended December 31, 2022 and 2021 relating to the Partnership’s asset retirement obligations: Balance as of December 31, 2020 $ 624,089 Well additions 22,995 Accretion 26,321 Revisions 70,178 Balance as of December 31, 2021 743,583 Well additions 26,748 Accretion 16,958 Revisions (91,400 ) Balance as of December 31, 2022 $ 695,889 Income Tax The Partnership is taxed as a partnership for federal and state income tax purposes. Typically, the Partnership has not recorded a provision for income taxes since the liability for such taxes is that of each of the partners rather than the Partnership. In mid-2022, the Partnership was contacted by the state of North Dakota, which asserted that the Partnership has an obligation to make tax payments on behalf of certain non-resident partners. Discussions with the state of North Dakota are ongoing, and a resolution may be reached that entails the Partnership making a payment of taxes on behalf of certain limited partners to the state. Therefore, the Partnership has recorded an estimate of North Dakota tax withholding on behalf of these certain non-resident limited partners for the tax years of 2021 and 2022 of approximately $0.8 million. The Partnership’s income tax returns are subject to examination by the federal and state taxing authorities, and changes, if any, could adjust the individual income tax of the partners. The Partnership has evaluated whether any material tax position taken will more likely than not be sustained upon examination by the appropriate taxing authority and believes that all such material tax positions taken are supportable by existing laws and related interpretations. Environmental Costs As the Partnership is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Partnership does not believe the existence of current environmental laws or interpretations thereof will materially hinder or adversely affect the Partnership’s business operations; however, there can be no assurances of future effects on the Partnership of new laws or interpretations thereof. Since the Partnership does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with the Partnership being responsible for its proportionate share of the costs involved. Environmental liabilities are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At December 31, 2022 and 2021, there were no such costs accrued. Net Income per Common Unit Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the years ended December 31, 2022 and 2021. As a result, basic and diluted outstanding common units were the same. The Incentive Distribution Rights (as discussed in Note 4) are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 4) would occur.

Oil and Natural Gas Investments

Oil and Natural Gas Investments	12 Months Ended
	Dec. 31, 2022
Oil and Gas Property [Abstract]
Oil and Gas Properties [Text Block]	Note 3. Oil and Natural Gas Investments On February 1, 2018, the Partnership completed its first purchase (“Acquisition No. 1”) in the Bakken Assets for approximately $90.5 million, including all closing costs and assumed liabilities. On August 31, 2018, the Partnership completed its second purchase of an additional non-operated working interest in the Bakken Assets for approximately $81.3 million, including all closing costs and assumed liabilities. As of December 31, 2022, the Partnership’s ownership of the Bakken Assets consisted of an approximate 5.7% non-operated working interest in 403 producing wells, and an estimated approximate 0.2% non-operated working interest in 8 wells in various stages of the drilling and completion process. From September 1, 2017, the effective date of Acquisition No. 1, to December 31, 2022, the Partnership has participated in the drilling of 209 wells, of which 199 have been completed at December 31, 2022. The Partnership incurred approximately $11.7 million and $4.4 million in capital drilling and completion costs for the years ended December 31, 2022 and 2021, respectively. The Partnership anticipates less than $1 million of capital expenditures will be incurred in 2023 to complete the 8 wells in process at December 31, 2022; however, estimated capital expenditures could be different from amounts actually invested. Non-consent wells Pursuant to the terms of the American Association of Professional Landmen Model Form Operating Agreement or North Dakota statute, each of which may govern operations between an operator and a non-operated working interest owner (“interest owner”), like the Partnership, an operator must notify an interest owner of its intention to drill a new well through submittal of a formal well proposal. The interest owner has the option to elect to participate in the drilling, completion and operating of the well and pay its proportionate share of all costs, or the interest owner may elect to non-consent the proposed well under the terms of the operating agreement or statute and bear no cost. If the interest owner elects to non-consent the proposed well, the interest owner is not obligated to pay any portion of the drilling, completion and operating expenses; however, the interest owner is then subject to a non-consent penalty under the terms of the operating agreement or North Dakota statute. Through its 2018 acquisitions, the Partnership acquired approximately 59 wells designated as non-consent wells, whereby a previous interest owner did not consent to participate in the drilling and completion of those wells. As a result, the Partnership is currently subject to non-consent penalties ranging from 200%-400%, meaning in general terms, the Partnership will remain in non-consent status and will not receive any revenue from these wells until the wells have satisfied the contractual or statutory penalties of 2-4 times payout of the expenses related to drilling, completion and operating the well. The Partnership may receive revenue or be responsible for operating and/or abandonment costs from all or a portion of these wells if the wells generate enough revenue to exceed the non-consent penalties described above.

Capital Contribution and Partne

Capital Contribution and Partners' Equity	12 Months Ended
	Dec. 31, 2022
Partners' Capital Notes [Abstract]
Partners' Capital Notes Disclosure [Text Block]	Note 4. Capital Contribution and Partners Equity At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990, the General Partner received Incentive Distribution Rights (defined below) and has been and will be reimbursed for its documented third-party out-of-pocket expenses incurred in organizing the Partnership and offering the common units. The Partnership completed its best-efforts offering of common units as of the close of business on October 24, 2019. As of the conclusion of the offering, the Partnership had completed the sale of approximately 11.0 million common units for total gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million. Under the agreement with David Lerner Associates, Inc. (the “Managing Dealer”), the Managing Dealer received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering as outlined in the prospectus based on the performance of the Partnership. Based on the common units sold through the conclusion of the offering on October 24, 2019, the Dealer Manager Incentive Fees are approximately $8.7 million, subject to Payout (defined below). Prior to “Payout,” all distributions made by the Partnership, if any, will be paid to the holders of common units. Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs. The Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”) provides that “Payout”, which is defined below, occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount. All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows: ● First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest. ● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest. All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above. For the year ended December 31, 2022, the Partnership declared and paid distributions of $1.396164 per common unit, or $15.4 million. For the year ended December 31, 2021, the Partnership declared and paid distributions of $1.423014 per common unit, or $15.7 million.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2022
Related Party Transactions [Abstract]
Related Party Transactions Disclosure [Text Block]	Note 5. Related Parties The Class A voting members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer and David S. McKenney, Chief Financial Officer. Messrs. Knight and McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy 11 GP, LLC, the general partner of Energy 11, L.P. (“Energy 11”), a limited partnership that also invests in producing and non-producing oil and gas properties on-shore in the United States. The Class B non-voting members of the General Partner are affiliates of Anthony F. Keating, III and Michael J. Mallick, the Co-Chief Operating Officers of Energy 11’s general partner. The Partnership has, and is expected to continue to engage in, significant transactions with related parties. These transactions cannot be construed to be at arm’s length and the results of the Partnership’s operations may be different than if conducted with non-related parties. The General Partner’s Board of Directors oversees and reviews the Partnership’s related party relationships and is required to approve any significant modifications to any existing related party transactions, as well as any new significant related party transactions. The Partnership will reimburse the General Partner for any costs incurred by the General Partner for certain expenses, which include general and administrative costs. The Partnership has also agreed to pay the General Partner an advisory fee to manage the day-to-day affairs of the Partnership, including serving as an investment advisor and consultant in connection with the acquisition, development, operation and disposition of oil and gas properties and other assets of the Partnership. In accordance with the limited partner agreement, subsequent to the Partnership’s first asset purchase, which occurred on February 1, 2018, the Partnership is required to pay quarterly an annual fee of 0.5% of the total gross equity proceeds raised by the Partnership in its best-efforts offering. The management fee paid to the General Partner for the years ended December 31, 2022 and 2021 was approximately $1.1 million in both years. The management fee paid to the General Partner is included in General and administrative expenses on the consolidated statements of operations. For the years ended December 31, 2022 and 2021, approximately $165,000 and $133,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership, respectively. At December 31, 2022 and 2021, approximately $57,000 and $43,000, respectively, was due to a member of the General Partner and is included in Accounts payable and accrued expenses in the consolidated balance sheets. On December 1, 2020, the Partnership entered into an Administrative Services Agreement (the “ASA”) with Regional Energy Investors, L.P. d/b/a Regional Energy Management (the “Administrator”) and Energy 11, whereby the Administrator will provide administrative, operating and professional services necessary and useful to the Partnership. The ASA became effective January 1, 2021, and the Initial Term of the ASA will extend until the earlier of (a) five years or (b) when the Partnership and/or Energy 11 ceases to own its respective oil and natural gas assets. Provided the ASA is not terminated by any party via 60-day written notice at the conclusion of the Initial Term, the ASA will be automatically renewed for additional one-year periods. If a party to the ASA materially breaches the terms and conditions of the ASA and the breach has not been cured with 30 days of written notification of said breach, the ASA may be terminated with immediate effect. Costs and expenses attributable to the services performed by the Administrator under the ASA will be reimbursed by the Partnership. All Administrator costs and expenses will be accumulated (based on actual costs incurred with no mark-up or profit to the Administrator) and approved by the Partnership prior to reimbursement. Costs and expenses to be reimbursed under the ASA may include, but are not limited to, employee wages and benefits – including one-half of the annual compensation and basic health benefits of the president of Energy 11’s general partner (of which the General Partner agreed to pay as the president is an employee of the Administrator), rent for office space and network and information technology support. Other expenses, such as business travel costs and accounting, legal or banking services, may not be incurred by the Administrator on behalf of the Partnership without prior express written consent of the Partnership. For the years ended December 31, 2022 and 2021, approximately $618,000 and $591,000 of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator, respectively. Under the ASA, the General Partner agreed to pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. Therefore, one-half of the management fee for the years ended December 31, 2022 and 2021 described above was paid by the General Partner to the Administrator. The Administrator is owned by entities that are controlled by Messrs. Keating and Mallick.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2022
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Note 6. Subsequent Events In January 2023, the Partnership declared and paid $1.2 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units. In February 2023, the Partnership declared and paid $1.2 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

Supplementary Information on Oi

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)	12 Months Ended
	Dec. 31, 2022
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Gas Exploration and Production Industries Disclosures [Text Block]	Note 7. Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) Aggregate Capitalized Costs and Costs Incurred The aggregate amount of capitalized costs of oil, natural gas and NGL properties and related accumulated depreciation, depletion and amortization as of December 31, 2022 and 2021 is as follows: 2022 2021 Producing properties $ 173,338,198 $ 161,615,609 Non-producing 71,138,790 71,118,790 244,476,988 232,734,399 Accumulated depreciation, depletion and amortization (65,100,662 ) (51,325,366 ) Net capitalized costs $ 179,376,326 $ 181,409,033 For the years ended December 31, 2022 and 2021, the Partnership incurred the following costs in oil and natural gas producing activities: 2022 2021 Development costs $ 11,742,590 $ 4,427,940 Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves The following unaudited information regarding the Partnership’s oil, natural gas and NGL reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB. Proved oil and natural gas reserves are those quantities of oil, natural gas and NGLs which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. The independent consulting petroleum engineering firm of Pinnacle Energy of Oklahoma City, OK, prepared estimates of the Partnership’s oil, natural gas and NGL reserves as of December 31, 2022, 2021 and 2020. The Partnership’s net proved oil, NGL and natural gas reserves, all of which are located in the contiguous United States, as of December 31, 2022, 2021 and 2020 have been estimated by the Partnership’s independent consulting petroleum engineering firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with SEC rules and regulations along with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history. For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate. Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available. “Revisions of previous estimates” in the table below represent changes in previous reserve estimates, either upward or downward, resulting from a change in economic factors, such as commodity prices, operating costs or development costs, or resulting from information obtained from the Partnership’s production history. The rollforward of net quantities of proved developed and undeveloped oil, natural gas and NGL reserves are summarized as follows: Proved Reserves Oil Natural Gas NGLs (Bbls) (Mcf) (Bbls) Total (BOE) December 31, 2020 17,065,540 16,978,759 2,224,690 22,120,022 Acquisition - - - - Extensions, discoveries and other additions (1) 616 4,131 - 1,305 Revisions of previous estimates (2) (6,403,447 ) (3,852,738 ) (28,435 ) (7,074,004 ) Production (706,981 ) (1,255,604 ) (200,166 ) (1,116,414 ) December 31, 2021 9,955,728 11,874,548 1,996,089 13,930,908 Acquisition - - - - Extensions, discoveries and other additions (3) 7,228 7,069 1,670 10,076 Revisions of previous estimates (4) (1,417,243 ) (40,881 ) (235,088 ) (1,659,145 ) Production (503,925 ) (927,779 ) (141,495 ) (800,050 ) December 31, 2022 8,041,788 10,912,957 1,621,176 11,481,790 (1) In 2021, extensions, discoveries and other additions of 1 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets. (2) Revisions to previous estimates decreased proved reserves by a net amount of 7,074 MBOE. These revisions result from 5,487 MBOE of downward adjustments attributable to changes in the future drill schedule and 1,665 MBOE of downward adjustments attributable to well performance, offset by 78 MBOE of upward adjustments caused by changes in oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2021 to December 31, 2020. (3) In 2022, extensions, discoveries and other additions of 10 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets. (4) Revisions to previous estimates decreased proved reserves by a net amount of 1,659 MBOE. These revisions result from 967 MBOE of downward adjustments attributable to well performance and 836 MBOE of downward adjustments attributable to changes in the future drill schedule, offset by 144 MBOE of upward adjustments caused by changes in oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2022 to December 31, 2021. In accordance with SEC Regulation S-X, Rule 4-10, as amended, the Partnership uses the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month within the 12-month period prior to the end of the reporting period. The average realized oil, natural gas and NGL prices, including the effect of price differential adjustments, used in computing the Partnership’s reserves as of December 31, 2022 were $94.41 per barrel of oil, $6.54 per MMcf of natural gas and $20.67 per barrel of NGL. The average realized oil, natural gas and NGL prices, including the effect of price differential adjustments, used in computing the Partnership’s reserves as of December 31, 2021 were $65.11 per barrel of oil, $3.29 per MMcf of natural gas and $15.97 per barrel of NGL. Net quantities of proved developed and proved undeveloped reserves at December 31, 2022, 2021 and 2020 are summarized in the table below. Oil Natural Gas NGLs (Bbls) (Mcf) (Bbls) Total (BOE) Proved developed reserves: December 31, 2020 6,881,782 9,202,098 1,210,323 9,625,788 December 31, 2021 4,709,922 7,944,532 1,376,457 7,410,468 December 31, 2022 4,213,426 7,986,085 1,222,792 6,767,232 Proved undeveloped reserves: December 31, 2020 10,183,758 7,776,661 1,014,367 12,494,235 December 31, 2021 5,245,806 3,930,016 619,632 6,520,441 December 31, 2022 3,828,362 2,926,872 398,384 4,714,558 The following details the changes in proved undeveloped reserves (PUD) for 2021 and 2022 (in BOE): BOE Proved undeveloped reserves, December 31, 2020 12,494,235 Revisions of previous estimates (1) (5,490,323 ) Extensions, discoveries and other additions (2) 1,305 Conversion to proved developed reserves (3) (484,776 ) Proved undeveloped reserves, December 31, 2021 6,520,441 Revisions of previous estimates (4) (876,492 ) Extensions, discoveries and other additions (5) 10,076 Conversion to proved developed reserves (6) (939,467 ) Proved undeveloped reserves, December 31, 2022 4,714,558 (1) The annual review of the PUDs resulted in a negative revision of approximately 5,490 MBOE. This revision was the result of 5,487 MBOE of downward adjustments attributable to changes in the future drill schedule, and 35 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield, offset by 32 MBOE of upward adjustments caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2021 to December 31, 2020. (2) In 2021, extensions, discoveries and other additions of 1 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets. (3) The Partnership converted 20 wells to proved developed reserves during 2021 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 485 MBOE. (4) The annual review of the PUDs resulted in a negative revision of approximately 876 MBOE. This revision was the result of 836 MBOE of downward adjustments attributable to changes in the future drill schedule and 40 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2022 to December 31, 2021. (5) In 2022, extensions, discoveries and other additions of 10 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets. (6) The Partnership converted 12 wells to proved developed reserves during 2022 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 939 MBOE. The Partnership anticipates all current PUD locations will be drilled and converted to PDP within five years of the date they were added. PUD locations and associated reserves which are no longer projected to be drilled within five years from the date they were first booked as proved undeveloped reserves have been removed as revisions at the time that determination was made. Standardized Measure of Discounted Future Net Cash Flows Accounting standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Partnership has followed these guidelines, which are briefly discussed below. Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for such year. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect the Partnership’s expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process. 2022 2021 (in thousands) (in thousands) Future cash inflows $ 864,173 $ 719,186 Future production costs (369,596 ) (240,407 ) Future development costs (36,554 ) (38,447 ) Future net cash flows 458,023 440,332 10% annual discount (230,729 ) (225,456 ) Standardized measure of discounted future net cash flows $ 227,294 $ 214,876 Changes in the standardized measure of discounted future net cash flows are as follows: 2022 2021 (in thousands) (in thousands) Standardized measure at beginning of period $ 214,876 $ 68,013 Changes resulting from: Extensions, discoveries and other additions 238 15 Sales of oil, natural gas and NGLs, net of production costs (37,082 ) (35,915 ) Net changes in prices and production costs 86,000 221,910 Development costs incurred during the period 11,743 4,428 Revisions to previous estimates (60,149 ) (91,061 ) Accretion of discount 21,517 6,811 Change in estimated future development costs (9,849 ) 40,675 Standardized measure of discounted future net cash flows $ 227,294 $ 214,876

Accounting Policies, by Policy

Accounting Policies, by Policy (Policies)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Basis of Accounting, Policy [Policy Text Block]	Basis of Presentation The accompanying financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”).
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits.
Fair Value of Financial Instruments, Policy [Policy Text Block]	Fair Value of Other Financial Instruments The carrying value of the Partnership’s other financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and accrued expenses, reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments.
Oil and Gas Properties Policy [Policy Text Block]	Property and Depreciation, Depletion and Amortization The Partnership accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The capitalized costs of oil and natural gas properties are depleted using the unit-of-production method on a field basis based on estimated proved developed and/or undeveloped oil, natural gas and NGL reserves. No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.
Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]	Impairment The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of the properties exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an impairment expense equal to the difference between the carrying value and the fair value of the properties, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. The underlying commodity prices used in the determination of estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates, including appropriate escalators, are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.
Use of Estimates, Policy [Policy Text Block]	Use of Estimates The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Of these estimates and assumptions, management considers the estimation of oil, natural gas and NGL reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as depreciation, depletion and amortization (“DD&A”) and impairment calculations. On an annual basis, the Partnership’s independent consulting petroleum engineer, with assistance from the Partnership, prepares estimates of oil, natural gas and NGL reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the Securities and Exchange Commission (“SEC”), the reserve estimates were based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period excluding escalations based upon future conditions. For impairment purposes, projected NYMEX forward strip prices for oil, natural gas and NGL as estimated by management are used. Oil, natural gas and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future oil, natural gas and NGL pricing assumptions are used by management to prepare estimates of oil, natural gas and NGL reserves used in formulating management’s overall operating decisions. The Partnership does not operate its oil and natural gas properties and, therefore, receives actual oil, natural gas and NGL sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case, the most current available production data is gathered from the appropriate operators, and oil, natural gas and NGL index prices local to each well are used to estimate the accrual of revenue on these wells. The oil, natural gas and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, natural gas and NGLs. These variables could lead to an over or under accrual of oil, natural gas and NGL sales at the end of any particular quarter. However, the Partnership adjusts the estimated accruals of revenue to actual production in the period actual production is determined.
Revenue [Policy Text Block]	Revenue Recognition The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Accounts receivable and other current assets in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.
Concentration Risk, Credit Risk, Policy [Policy Text Block]	Accounts Receivable and Concentration of Credit Risk
Asset Retirement Obligation [Policy Text Block]	Accounting for Asset Retirement Obligations The Partnership has significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. The removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance. The following table shows the activity for the years ended December 31, 2022 and 2021 relating to the Partnership’s asset retirement obligations: Balance as of December 31, 2020 $ 624,089 Well additions 22,995 Accretion 26,321 Revisions 70,178 Balance as of December 31, 2021 743,583 Well additions 26,748 Accretion 16,958 Revisions (91,400 ) Balance as of December 31, 2022 $ 695,889
Income Tax, Policy [Policy Text Block]	Income Tax The Partnership is taxed as a partnership for federal and state income tax purposes. Typically, the Partnership has not recorded a provision for income taxes since the liability for such taxes is that of each of the partners rather than the Partnership. In mid-2022, the Partnership was contacted by the state of North Dakota, which asserted that the Partnership has an obligation to make tax payments on behalf of certain non-resident partners. Discussions with the state of North Dakota are ongoing, and a resolution may be reached that entails the Partnership making a payment of taxes on behalf of certain limited partners to the state. Therefore, the Partnership has recorded an estimate of North Dakota tax withholding on behalf of these certain non-resident limited partners for the tax years of 2021 and 2022 of approximately $0.8 million. The Partnership’s income tax returns are subject to examination by the federal and state taxing authorities, and changes, if any, could adjust the individual income tax of the partners. The Partnership has evaluated whether any material tax position taken will more likely than not be sustained upon examination by the appropriate taxing authority and believes that all such material tax positions taken are supportable by existing laws and related interpretations.
Environmental Costs, Policy [Policy Text Block]	Environmental Costs As the Partnership is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Partnership does not believe the existence of current environmental laws or interpretations thereof will materially hinder or adversely affect the Partnership’s business operations; however, there can be no assurances of future effects on the Partnership of new laws or interpretations thereof. Since the Partnership does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with the Partnership being responsible for its proportionate share of the costs involved. Environmental liabilities are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At December 31, 2022 and 2021, there were no such costs accrued.
Earnings Per Share, Policy [Policy Text Block]	Net Income per Common Unit Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the years ended December 31, 2022 and 2021. As a result, basic and diluted outstanding common units were the same. The Incentive Distribution Rights (as discussed in Note 4) are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 4) would occur.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Schedule of Asset Retirement Obligations [Table Text Block]	The following table shows the activity for the years ended December 31, 2022 and 2021 relating to the Partnership’s asset retirement obligations: Balance as of December 31, 2020 $ 624,089 Well additions 22,995 Accretion 26,321 Revisions 70,178 Balance as of December 31, 2021 743,583 Well additions 26,748 Accretion 16,958 Revisions (91,400 ) Balance as of December 31, 2022 $ 695,889

Supplementary Information on _2

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2022
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]	The aggregate amount of capitalized costs of oil, natural gas and NGL properties and related accumulated depreciation, depletion and amortization as of December 31, 2022 and 2021 is as follows: 2022 2021 Producing properties $ 173,338,198 $ 161,615,609 Non-producing 71,138,790 71,118,790 244,476,988 232,734,399 Accumulated depreciation, depletion and amortization (65,100,662 ) (51,325,366 ) Net capitalized costs $ 179,376,326 $ 181,409,033
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]	For the years ended December 31, 2022 and 2021, the Partnership incurred the following costs in oil and natural gas producing activities: 2022 2021 Development costs $ 11,742,590 $ 4,427,940
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]	The rollforward of net quantities of proved developed and undeveloped oil, natural gas and NGL reserves are summarized as follows: Proved Reserves Oil Natural Gas NGLs (Bbls) (Mcf) (Bbls) Total (BOE) December 31, 2020 17,065,540 16,978,759 2,224,690 22,120,022 Acquisition - - - - Extensions, discoveries and other additions (1) 616 4,131 - 1,305 Revisions of previous estimates (2) (6,403,447 ) (3,852,738 ) (28,435 ) (7,074,004 ) Production (706,981 ) (1,255,604 ) (200,166 ) (1,116,414 ) December 31, 2021 9,955,728 11,874,548 1,996,089 13,930,908 Acquisition - - - - Extensions, discoveries and other additions (3) 7,228 7,069 1,670 10,076 Revisions of previous estimates (4) (1,417,243 ) (40,881 ) (235,088 ) (1,659,145 ) Production (503,925 ) (927,779 ) (141,495 ) (800,050 ) December 31, 2022 8,041,788 10,912,957 1,621,176 11,481,790 (1) In 2021, extensions, discoveries and other additions of 1 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets. (2) Revisions to previous estimates decreased proved reserves by a net amount of 7,074 MBOE. These revisions result from 5,487 MBOE of downward adjustments attributable to changes in the future drill schedule and 1,665 MBOE of downward adjustments attributable to well performance, offset by 78 MBOE of upward adjustments caused by changes in oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2021 to December 31, 2020. (3) In 2022, extensions, discoveries and other additions of 10 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets. (4) Revisions to previous estimates decreased proved reserves by a net amount of 1,659 MBOE. These revisions result from 967 MBOE of downward adjustments attributable to well performance and 836 MBOE of downward adjustments attributable to changes in the future drill schedule, offset by 144 MBOE of upward adjustments caused by changes in oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2022 to December 31, 2021. Oil Natural Gas NGLs (Bbls) (Mcf) (Bbls) Total (BOE) Proved developed reserves: December 31, 2020 6,881,782 9,202,098 1,210,323 9,625,788 December 31, 2021 4,709,922 7,944,532 1,376,457 7,410,468 December 31, 2022 4,213,426 7,986,085 1,222,792 6,767,232 Proved undeveloped reserves: December 31, 2020 10,183,758 7,776,661 1,014,367 12,494,235 December 31, 2021 5,245,806 3,930,016 619,632 6,520,441 December 31, 2022 3,828,362 2,926,872 398,384 4,714,558 BOE Proved undeveloped reserves, December 31, 2020 12,494,235 Revisions of previous estimates (1) (5,490,323 ) Extensions, discoveries and other additions (2) 1,305 Conversion to proved developed reserves (3) (484,776 ) Proved undeveloped reserves, December 31, 2021 6,520,441 Revisions of previous estimates (4) (876,492 ) Extensions, discoveries and other additions (5) 10,076 Conversion to proved developed reserves (6) (939,467 ) Proved undeveloped reserves, December 31, 2022 4,714,558 (1) The annual review of the PUDs resulted in a negative revision of approximately 5,490 MBOE. This revision was the result of 5,487 MBOE of downward adjustments attributable to changes in the future drill schedule, and 35 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield, offset by 32 MBOE of upward adjustments caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2021 to December 31, 2020. (2) In 2021, extensions, discoveries and other additions of 1 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets. (3) The Partnership converted 20 wells to proved developed reserves during 2021 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 485 MBOE. (4) The annual review of the PUDs resulted in a negative revision of approximately 876 MBOE. This revision was the result of 836 MBOE of downward adjustments attributable to changes in the future drill schedule and 40 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2022 to December 31, 2021. (5) In 2022, extensions, discoveries and other additions of 10 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets. (6) The Partnership converted 12 wells to proved developed reserves during 2022 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 939 MBOE.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]	The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect the Partnership’s expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process. 2022 2021 (in thousands) (in thousands) Future cash inflows $ 864,173 $ 719,186 Future production costs (369,596 ) (240,407 ) Future development costs (36,554 ) (38,447 ) Future net cash flows 458,023 440,332 10% annual discount (230,729 ) (225,456 ) Standardized measure of discounted future net cash flows $ 227,294 $ 214,876
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]	Changes in the standardized measure of discounted future net cash flows are as follows: 2022 2021 (in thousands) (in thousands) Standardized measure at beginning of period $ 214,876 $ 68,013 Changes resulting from: Extensions, discoveries and other additions 238 15 Sales of oil, natural gas and NGLs, net of production costs (37,082 ) (35,915 ) Net changes in prices and production costs 86,000 221,910 Development costs incurred during the period 11,743 4,428 Revisions to previous estimates (60,149 ) (91,061 ) Accretion of discount 21,517 6,811 Change in estimated future development costs (9,849 ) 40,675 Standardized measure of discounted future net cash flows $ 227,294 $ 214,876

Partnership Organization (Detai

Partnership Organization (Details) shares in Millions		12 Months Ended	25 Months Ended
	Dec. 30, 2016 USD ($)	Dec. 31, 2022	Oct. 24, 2019 USD ($) shares
Partnership Organization (Details) [Line Items]
Limited Liability Company or Limited Partnership, Business, Formation State	Delaware
Partners' Capital Account, Contributions (in Dollars)	$ 1,000
Number of Operators		12
Bakken Assets [Member]
Partnership Organization (Details) [Line Items]
Number of Operators		12
Bakken Assets [Member] | Non-operated Completed Wells [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net		5.70%
Oil, Productive Well, Number of Wells, Net		403
Bakken Assets [Member] | Non-operated Wells in the Process of Drilling [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net		0.20%
Oil and Gas, Present Activity, Well in Process of Drilling		8
Best-Efforts Offering [Member]
Partnership Organization (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares) | shares			11
Proceeds from Issuance of Common Limited Partners Units (in Dollars)			$ 218,000,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units (in Dollars)			$ 204,300,000

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details) - USD ($)	12 Months Ended		24 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2022
Summary of Significant Accounting Policies (Details) [Line Items]
Number of Operators	12
Estimated State Tax Withholding For Limited Partners (in Dollars)	$ (479,000)	$ (365,000)	$ 800,000
Revenue Benchmark [Member] | Customer Concentration Risk [Member] | Four Operators [Member]
Summary of Significant Accounting Policies (Details) [Line Items]
Concentration Risk, Percentage	91%	92%
Number of Operators	4	4

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) - Schedule of Asset Retirement Obligations - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Schedule Of Asset Retirement Obligations Abstract
Balance	$ 743,583	$ 624,089
Well additions	26,748	22,995
Accretion	16,958	26,321
Revisions	(91,400)	70,178
Balance	$ 695,889	$ 743,583

Oil and Natural Gas Investmen_2

Oil and Natural Gas Investments (Details)			12 Months Ended			64 Months Ended
	Aug. 31, 2018 USD ($)	Feb. 01, 2018 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2018	Dec. 31, 2022
Oil and Natural Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number			12	20
Costs Incurred, Development Costs (in Dollars)			$ 11,742,590	$ 4,427,940
Non-consent well description					Pursuant to the terms of the American Association of Professional Landmen Model Form Operating Agreement or North Dakota statute, each of which may govern operations between an operator and a non-operated working interest owner (“interest owner”), like the Partnership, an operator must notify an interest owner of its intention to drill a new well through submittal of a formal well proposal. The interest owner has the option to elect to participate in the drilling, completion and operating of the well and pay its proportionate share of all costs, or the interest owner may elect to non-consent the proposed well under the terms of the operating agreement or statute and bear no cost. If the interest owner elects to non-consent the proposed well, the interest owner is not obligated to pay any portion of the drilling, completion and operating expenses; however, the interest owner is then subject to a non-consent penalty under the terms of the operating agreement or North Dakota statute. Through its 2018 acquisitions, the Partnership acquired approximately 59 wells designated as non-consent wells, whereby a previous interest owner did not consent to participate in the drilling and completion of those wells. As a result, the Partnership is currently subject to non-consent penalties ranging from 200%-400%, meaning in general terms, the Partnership will remain in non-consent status and will not receive any revenue from these wells until the wells have satisfied the contractual or statutory penalties of 2-4 times payout of the expenses related to drilling, completion and operating the well. The Partnership may receive revenue or be responsible for operating and/or abandonment costs from all or a portion of these wells if the wells generate enough revenue to exceed the non-consent penalties described above.
Number of Wells Designated as Non-Consent Wells					59
Minimum [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Non-consent penalty range					200%
Maximum [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Non-consent penalty range					400%
Non-operated Completed Wells [Member] | Bakken Assets [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net			5.70%
Oil, Productive Well, Number of Wells, Net			403			403
Non-operated Wells in the Process of Drilling [Member] | Bakken Assets [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net			0.20%
Oil, Productive Well, Number of Wells, Net			8			8
Acquisition No. 1 [Member] | Bakken Assets [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Business Combination, Consideration Transferred (in Dollars)		$ 90,500,000
Wells Drilled						209
Oil and Gas, Development Well Drilled, Net Productive, Number						199
Costs Incurred, Development Costs (in Dollars)			$ 11,700,000	$ 4,400,000
Capital Expenditures Drilling and Completion of Wells (in Dollars)			$ 1,000,000
Acquisition No. 2 [Member] | Bakken Assets [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Business Combination, Consideration Transferred (in Dollars)	$ 81,300,000

Capital Contribution and Part_2

Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions		12 Months Ended			25 Months Ended
	Dec. 30, 2016	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2017	Oct. 24, 2019
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Contributions	$ 1,000
Partners' Capital Account, Return of Contribution Upon Minimum Offering				$ 990
Partners' Capital Account, Description of Units Sold		Under the agreement with David Lerner Associates, Inc. (the “Managing Dealer”), the Managing Dealer received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering as outlined in the prospectus based on the performance of the Partnership.
Managing Dealer, Selling Commissions, Percentage		6%
Managing Dealer, Maximum Contingent Incentive Fee on Gross Proceeds, Percentage		4%
Managing Dealer, Maximum Contingent Incentive Fee on Gross Proceeds		$ 8,700,000
Key Provisions of Operating or Partnership Agreement, Description		The Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”) provides that “Payout”, which is defined below, occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount. All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:    ● First, (i) to the Record Holders of the Incentive Distribution Rights, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.     ● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest.  All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share)		$ 1.396164	$ 1.423014
Distribution Made to Limited Partner, Cash Distributions Paid		$ 15,401,894	$ 15,698,091
Best-Efforts Offering [Member]
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares)					11
Proceeds from Issuance of Common Limited Partners Units					$ 218,000,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units					$ 204,300,000

Related Parties (Details)

Related Parties (Details) - USD ($)		12 Months Ended
	Dec. 01, 2020	Dec. 31, 2022	Dec. 31, 2021
Related Parties (Details) [Line Items]
Related Party Transaction, Description of Transaction		subsequent to the Partnership’s first asset purchase, which occurred on February 1, 2018, the Partnership is required to pay quarterly an annual fee of 0.5% of the total gross equity proceeds raised by the Partnership in its best-efforts offering.
General Partner [Member]
Related Parties (Details) [Line Items]
Selling, General and Administrative Expense		$ 165,000	$ 133,000
Other Liabilities, Current		57,000	43,000
Affiliated Entity [Member]
Related Parties (Details) [Line Items]
Selling, General and Administrative Expense		618,000	$ 591,000
Administrative Service Agreement [Member]
Related Parties (Details) [Line Items]
Related Party, Administrative Service Agreement	Under the ASA, the General Partner agreed to pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA
Management Fee [Member] | General Partner [Member]
Related Parties (Details) [Line Items]
Selling, General and Administrative Expense		$ 1,100,000

Subsequent Events (Details)

Subsequent Events (Details) - Subsequent Event [Member] - USD ($) $ / shares in Units, $ in Millions	1 Months Ended
	Feb. 28, 2023	Jan. 31, 2023
Subsequent Events (Details) [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid	$ 1.2	$ 1.2
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.107397	$ 0.107397

Supplementary Information on _3

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) Mcfe in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2022 Boe		Dec. 31, 2022 $ / bbl	Dec. 31, 2022 $ / Mcf	Dec. 31, 2022 Mcfe	Dec. 31, 2021 Boe $ / bbl $ / Mcf
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		(876,492)	[1]				(5,490,323)	[2]
Oil and Gas, Development Well Drilled, Net Productive, Number	12						20
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)		(939,467)	[3]				(484,776)	[4]
Measurement Input, Discount Rate [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Future Cash Flows Measurement Input	10%						10%
Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		(1,659,000)					7,074,000
Proved Undeveloped Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		(876,000)					(5,490,000)
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)		(939,000)					(485,000)
Adjustments Related to Well Performance [Member] | Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		967,000					1,665,000
Adjustments Related to Well Performance [Member] | Adjustments Related to Changes in Future Drill Schedule [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)							5,487,000
Changes in Natural Gas Shrink [Member] | Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)						40	(78,000)
Changes in Natural Gas Shrink [Member] | Proved Undeveloped Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)							(5,487,000)
Adjustments Related to Successful Drilling [Member] | Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		10,000
Adjustments Related to Changes in Future Drill Schedule [Member] | Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		836,000				836
Adjustments Related to Changes in Future Drill Schedule [Member] | Proved Undeveloped Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)							32,000
Adjustments Related to Prices [Member] | Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		144,000
Adjustments Related to Prices [Member] | Proved Undeveloped Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)							(35,000)
Including Effects of Price Differential Adjustments [Member] | Oil [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Average Sale Price (in Dollars per Barrel (of Oil)) | $ / bbl				94.41			65.11
Including Effects of Price Differential Adjustments [Member] | Natural Gas [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Average Sale Price (in Dollars per Barrel (of Oil)) | $ / Mcf					6.54		3.29
Including Effects of Price Differential Adjustments [Member] | Natural Gas Liquids [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Average Sale Price (in Dollars per Barrel (of Oil)) | $ / bbl				20.67			15.97
Acquisition No. 1 [Member] | Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Purchase of Mineral in Place (Energy)							1,000
[1]The annual review of the PUDs resulted in a negative revision of approximately 876 MBOE. This revision was the result of 836 MBOE of downward adjustments attributable to changes in the future drill schedule and 40 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2022 to December 31, 2021.[2]The annual review of the PUDs resulted in a negative revision of approximately 5,490 MBOE. This revision was the result of 5,487 MBOE of downward adjustments attributable to changes in the future drill schedule, and 35 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield, offset by 32 MBOE of upward adjustments caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2021 to December 31, 2020.[3]The Partnership converted 12 wells to proved developed reserves during 2022 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 939 MBOE.[4]The Partnership converted 20 wells to proved developed reserves during 2021 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 485 MBOE.

Supplementary Information on _4

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
	$ 244,476,988	$ 232,734,399
Accumulated depreciation, depletion and amortization	(65,100,662)	(51,325,366)
Net capitalized costs	179,376,326	181,409,033
Producing Properties [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized Costs, Proved Properties	173,338,198	161,615,609
Non-Producing Properties [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized Costs, Proved Properties	$ 71,138,790	$ 71,118,790

Supplementary Information on _5

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Cost Incurred In Oil And Gas Property Acquisition Exploration And Development Activities Disclosure Abstract
Development costs	$ 11,742,590	$ 4,427,940

Supplementary Information on _6

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	12 Months Ended
	Dec. 31, 2022 Boe bbl Mcf		Dec. 31, 2021 Boe bbl Mcf		Dec. 31, 2020 Boe bbl Mcf	Dec. 31, 2019 Boe bbl Mcf
Reserve Quantities [Line Items]
Balance	13,930,908		22,120,022
Proved developed reserves:
Balance proved developed reserves (in Barrels of Oil Equivalent) | Boe	6,767,232		7,410,468		9,625,788
Proved undeveloped reserves:
Balance proved undeveloped reserves (in Barrels of Oil Equivalent) | Boe			4,714,558		6,520,441	12,494,235
Balance proved undeveloped reserves (in Barrels of Oil Equivalent) | Boe	4,714,558		6,520,441		12,494,235
Revisions of previous estimates (in Barrels of Oil Equivalent) | Boe	(876,492)	[1]	(5,490,323)	[2]
Extensions, discoveries and other additions (in Barrels of Oil Equivalent) | Boe	10,076	[3]	1,305	[4]
Conversion to proved developed reserves (in Barrels of Oil Equivalent) | Boe	(939,467)	[5]	(484,776)	[6]
Acquisition	0
Extensions, discoveries and other additions	10,076	[7]	1,305	[8]
Revisions of previous estimates	(1,659,145)	[9]	(7,074,004)	[10]
Production	(800,050)		(1,116,414)
Balance	11,481,790		13,930,908
Oil [Member]
Reserve Quantities [Line Items]
Balance	9,955,728		17,065,540
Proved developed reserves:
Balance proved developed reserves	4,213,426		4,709,922		6,881,782
Proved undeveloped reserves:
Balance proved undeveloped reserves			3,828,362		5,245,806	10,183,758
Acquisition	0
Extensions, discoveries and other additions	7,228	[7]	616	[8]
Revisions of previous estimates	(1,417,243)	[9]	(6,403,447)	[10]
Production	(503,925)		(706,981)
Balance	8,041,788		9,955,728
Natural Gas [Member]
Reserve Quantities [Line Items]
Balance | Mcf	11,874,548		16,978,759
Proved developed reserves:
Balance proved developed reserves | Mcf	7,986,085		7,944,532		9,202,098
Proved undeveloped reserves:
Balance proved undeveloped reserves | Mcf			2,926,872		3,930,016	7,776,661
Acquisition | Mcf	0
Extensions, discoveries and other additions | Mcf	7,069	[7]	4,131	[8]
Revisions of previous estimates | Mcf	(40,881)	[9]	(3,852,738)	[10]
Production | Mcf	(927,779)		(1,255,604)
Balance | Mcf	10,912,957		11,874,548
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Balance	1,996,089		2,224,690
Proved developed reserves:
Balance proved developed reserves	1,222,792		1,376,457		1,210,323
Proved undeveloped reserves:
Balance proved undeveloped reserves			398,384		619,632	1,014,367
Acquisition	0
Extensions, discoveries and other additions	1,670	[7]	0	[8]
Revisions of previous estimates	(235,088)	[9]	(28,435)	[10]
Production	(141,495)		(200,166)
Balance	1,621,176		1,996,089
Acquisition No. 1 [Member]
Proved undeveloped reserves:
Acquisition			0
Acquisition No. 1 [Member] | Oil [Member]
Proved undeveloped reserves:
Acquisition			0
Acquisition No. 1 [Member] | Natural Gas [Member]
Proved undeveloped reserves:
Acquisition | Mcf			0
Acquisition No. 1 [Member] | Natural Gas Liquids [Member]
Proved undeveloped reserves:
Acquisition			0
[1]The annual review of the PUDs resulted in a negative revision of approximately 876 MBOE. This revision was the result of 836 MBOE of downward adjustments attributable to changes in the future drill schedule and 40 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2022 to December 31, 2021.[2]The annual review of the PUDs resulted in a negative revision of approximately 5,490 MBOE. This revision was the result of 5,487 MBOE of downward adjustments attributable to changes in the future drill schedule, and 35 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield, offset by 32 MBOE of upward adjustments caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2021 to December 31, 2020.[3]In 2022, extensions, discoveries and other additions of 10 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.[4]In 2021, extensions, discoveries and other additions of 1 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.[5]The Partnership converted 12 wells to proved developed reserves during 2022 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 939 MBOE.[6]The Partnership converted 20 wells to proved developed reserves during 2021 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 485 MBOE.[7]In 2022, extensions, discoveries and other additions of 10 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.[8]In 2021, extensions, discoveries and other additions of 1 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.[9]Revisions to previous estimates decreased proved reserves by a net amount of 1,659 MBOE. These revisions result from 967 MBOE of downward adjustments attributable to well performance and 836 MBOE of downward adjustments attributable to changes in the future drill schedule, offset by 144 MBOE of upward adjustments caused by changes in oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2022 to December 31, 2021.[10]Revisions to previous estimates decreased proved reserves by a net amount of 7,074 MBOE. These revisions result from 5,487 MBOE of downward adjustments attributable to changes in the future drill schedule and 1,665 MBOE of downward adjustments attributable to well performance, offset by 78 MBOE of upward adjustments caused by changes in oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2021 to December 31, 2020.

Supplementary Information on _7

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Standardized Measure Of Discounted Future Cash Flows Relating To Proved Reserves Disclosure Abstract
Future cash inflows	$ 864,173	$ 719,186
Future production costs	(369,596)	(240,407)
Future development costs	(36,554)	(38,447)
Future net cash flows	458,023	440,332
10% annual discount	(230,729)	(225,456)
Standardized measure of discounted future net cash flows	$ 227,294	$ 214,876	$ 68,013

Supplementary Information on _8

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure (Parentheticals)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Measurement Input, Discount Rate [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Annual discount	10%	10%

Supplementary Information on _9

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Schedule Of Changes In Standardized Measure Of Discounted Future Net Cash Flows Abstract
Standardized measure at beginning of period	$ 214,876	$ 68,013
Extensions, discoveries and other additions	238	15
Sales of oil, natural gas and NGLs, net of production costs	(37,082)	(35,915)
Net changes in prices and production costs	86,000	221,910
Development costs incurred during the period	11,743	4,428
Revisions to previous estimates	(60,149)	(91,061)
Accretion of discount	21,517	6,811
Change in estimated future development costs	(9,849)	40,675
Standardized measure of discounted future net cash flows	$ 227,294	$ 214,876