Energy 11 10-K 31 Mar 23 2022 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2022	Mar. 31, 2023	Jun. 30, 2022
Document Information Line Items
Entity Registrant Name	ENERGY 11, L.P.
Document Type	10-K
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		18,973,474
Entity Public Float			$ 0
Amendment Flag	false
Entity Central Index Key	0001581552
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	000-55615
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-3070515
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	$ 3,053,120	$ 912,828
Accounts receivable	17,173,549	15,118,535
Other current assets, net	317,248	317,497
Total Current Assets	20,543,917	16,348,860
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $119,045,055 and $98,150,833, respectively	353,519,338	325,032,321
Other assets	23,654	165,578
Total Assets	374,086,909	341,546,759
Liabilities
Accounts payable and accrued expenses	15,170,168	9,847,984
Derivative liability	3,173,965	1,264,935
Total Current Liabilities	18,344,133	11,112,919
Revolving credit facility	22,600,000	23,000,000
Asset retirement obligations	1,966,738	1,791,341
Derivative liability - noncurrent		1,099,388
Total Liabilities	42,910,871	37,003,648
Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)	331,177,765	304,544,838
General partner's interest	(1,727)	(1,727)
Class B units (62,500 units issued and outstanding, respectively)	0	0
Total Partners’ Equity	331,176,038	304,543,111
Total Liabilities and Partners’ Equity	$ 374,086,909	$ 341,546,759

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, accumulated depreciation, depletion and amortization (in Dollars)	$ 119,045,055	$ 98,150,833
Limited partners' interest, common units issued	18,973,474	18,973,474
Limited partners' interest, common units outstanding	18,973,474	18,973,474
Class B Units, units issued	62,500	62,500
Class B Units, units outstanding	62,500	62,500

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Revenues
Oil	$ 94,755,037	$ 61,396,251
Natural gas	8,625,891	5,511,526
Natural gas liquids	8,649,864	7,190,386
Total revenue	112,030,792	74,098,163
Operating costs and expenses
Production expenses	17,706,793	11,619,322
Production taxes	9,108,473	5,700,579
General and administrative expenses	2,074,306	1,516,357
Depreciation, depletion, amortization and accretion	20,974,139	22,473,437
Total operating costs and expenses	49,863,711	41,309,695
Operating income	62,167,081	32,788,468
Loss on derivatives, net	(7,272,374)	(2,943,983)
Interest expense, net	(1,456,700)	(1,794,835)
Total other expense, net	(8,729,074)	(4,738,818)
Net income	$ 53,438,007	$ 28,049,650
Basic and diluted net income per common unit (in Dollars per share)	$ 2.82	$ 1.48
Weighted average common units outstanding - basic and diluted (in Shares)	18,973,474	18,973,474

Consolidated Statements of Part

Consolidated Statements of Partners' Equity - USD ($)	Total	Capital Unit, Class B [Member] Member Units [Member]	Limited Partner [Member]	General Partner [Member]
Balance at Dec. 31, 2020	$ 280,345,822		$ 280,347,549	$ (1,727)
Balance (in Shares) at Dec. 31, 2020		62,500	18,973,474
Distributions declared and paid to common units	(3,602,361)		$ (3,602,361)
Estimated state tax withholding for limited partners	(250,000)		(250,000)
Net income	28,049,650		28,049,650
Balance at Dec. 31, 2021	$ 304,543,111		$ 304,544,838	(1,727)
Balance (in Shares) at Dec. 31, 2021	18,973,474	62,500	18,973,474
Balance at Dec. 31, 2020	$ 280,345,822		$ 280,347,549	(1,727)
Balance (in Shares) at Dec. 31, 2020		62,500	18,973,474
Estimated state tax withholding for limited partners	600,000
Balance at Dec. 31, 2022	$ 331,176,038		$ 331,177,765	(1,727)
Balance (in Shares) at Dec. 31, 2022	18,973,474	62,500	18,973,474
Balance at Dec. 31, 2021	$ 304,543,111		$ 304,544,838	(1,727)
Balance (in Shares) at Dec. 31, 2021	18,973,474	62,500	18,973,474
Distributions declared to common units	$ (26,490,080)		$ (26,490,080)
Distributions declared and paid to common units	(23,870,186)
Estimated state tax withholding for limited partners	(315,000)		(315,000)
Net income	53,438,007		53,438,007
Balance at Dec. 31, 2022	$ 331,176,038		$ 331,177,765	$ (1,727)
Balance (in Shares) at Dec. 31, 2022	18,973,474	62,500	18,973,474

Consolidated Statements of Pa_2

Consolidated Statements of Partners' Equity (Parentheticals) - Capital Unit, Class B [Member] - Member Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Distributions declared and paid to common units, per unit		$ 0.189863
Distributions declared to common units	$ 1.396164

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Cash flow from operating activities:
Net income (loss)	$ 53,438,007	$ 28,049,650
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion	20,974,139	22,473,437
Loss on mark-to-market of derivatives	668,714	1,761,563
Non-cash expenses	141,924	202,897
Changes in operating assets and liabilities:
Accounts receivable	(2,055,014)	(9,227,564)
Other assets	249	(26,331)
Accounts payable and accrued expenses	1,573,440	240,592
Net cash flow provided by operating activities	74,741,459	43,474,244
Cash flow from investing activities:
Additions to oil and natural gas properties	(48,330,981)	(18,020,757)
Net cash flow used in investing activities	(48,330,981)	(18,020,757)
Cash flow from financing activities:
Cash paid for loan costs	0	(402,117)
Proceeds from BancFirst revolving credit facility	13,600,000	40,063,389
Payments on BancFirst revolving credit facility	(14,000,000)	(17,063,389)
Proceeds from (payments on) Simmons revolving credit facility	0	(40,000,000)
Payments on affiliate term loan	0	(6,000,000)
Distributions paid to limited partners	(23,870,186)	(3,602,361)
Net cash flow provided by (used in) financing activities	(24,270,186)	(27,004,478)
Increase (decrease) in cash, cash equivalents and restricted cash	2,140,292	(1,550,991)
Cash, cash equivalents and restricted cash, beginning of period	912,828	2,463,819
Cash, cash equivalents and restricted cash, end of period	3,053,120	912,828
Interest paid	1,260,325	1,553,451
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$ 8,544,187	$ 7,589,409

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 11, 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 July 9, 2013. The Partnership completed its best-efforts offering on April 24, 2017 with a total of approximately 19 million common units sold for gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million. As of December 31, 2022, the Partnership owns an approximate 24% non-operated working interest in 293 producing wells, an estimated approximate 12% non-operated working interest in 6 wells in various stages of the drilling and completion process and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). Chord Energy Corporation (“Chord”, NASDAQ: CHRD), the product of a merger between Whiting Petroleum Corporation and Oasis Petroleum Inc., is one of the largest producers in the basin and operates substantially all of the Sanish Field Assets. The general partner of the Partnership is Energy 11 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 consolidated financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”). The consolidated financial statements include the accounts of the Partnership and its subsidiaries. Cash, Cash Equivalents and Restricted 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. 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 our 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 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 Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the 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 Oil, natural gas and natural gas liquids revenue receivable 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 For the year ended December 31, 2022, the Partnership’s oil, natural gas and NGL sales were through two operators. Substantially all the Partnership’s accounts receivable is due from Chord, the largest operator of the Partnership’s oil and natural gas properties in North Dakota (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, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible. Chord is the current operator of 99% of the Partnership’s producing properties. 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. Asset Retirement Obligation 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 $ 1,564,105 Well additions 139,343 Accretion 87,893 Revisions in estimated cash flows - Balance as of December 31, 2021 1,791,341 Well additions 95,480 Accretion 97,588 Revisions in estimated cash flows (17,671 ) Balance as of December 31, 2022 $ 1,966,738 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 $0.6 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 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 Class B Units and Incentive Distribution Rights are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 7) would occur.

Oil and Gas Investments

Oil and Gas Investments	12 Months Ended
	Dec. 31, 2022
Oil and Gas Property [Abstract]
Oil and Gas Properties [Text Block]	Note 3. Oil and Gas Investments On December 18, 2015, the Partnership completed its first purchase in the Sanish field, acquiring an approximate 11% non-operated working interest in the Sanish Field Assets for approximately $159.6 million. On January 11, 2017, the Partnership closed on its second purchase in the Sanish field, acquiring an additional approximate 11% non-operated working interest in the Sanish Field Assets for approximately $128.5 million. On March 31, 2017, the Partnership closed on its third purchase in the Sanish field, acquiring an additional approximate average 10.5% non-operated working interest in 82 of the Partnership’s then 216 existing producing wells and 150 of the Partnership’s then 253 future development locations in the Sanish Field Assets for approximately $52.4 million. Since the beginning of 2018, the Partnership has elected to participate in the drilling and completion of 86 new wells in the Sanish field, of which 80 of those 86 wells have been completed and were producing at December 31, 2022. The Partnership has 6 wells that are in-process as of December 31, 2022, which are expected to be completed during the first quarter of 2023. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 86 wells is approximately $119 million, of which approximately $116 million had been incurred as of December 31, 2022. The Partnership estimates the approximate $2 to $4 million in capital expenditures to fully pay for its recently-completed wells along with the remaining 6 wells in various stages of drilling and completion will be incurred through the first quarter of 2023 based on the best available information regarding current capital investment plans from its operators. However, many factors outside the Partnership’s control make it difficult to predict the amount and timing of capital expenditures and estimated capital expenditures could be significantly different from amounts actually invested.

Debt

Debt	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Debt Disclosure [Text Block]	Note 4. Debt Revolving Credit Facilities In November 2017, the Partnership, as the borrower, entered into a loan agreement (the “Simmons Loan Agreement”) between and among the Partnership and Simmons Bank, as administrative agent and the lenders party thereto. Through various amendments, the Simmons Loan Agreement provided for a revolving credit facility (“Simmons Credit Facility”) with a commitment amount of $40 million, subject to borrowing base restrictions, that was to mature on July 31, 2021. The Simmons Credit Facility had an interest rate of 4.25% and outstanding borrowings of $40 million as of May 13, 2021. On May 13, 2021, the Partnership and its wholly-owned subsidiary, as borrowers, entered into a loan agreement (“BF Loan Agreement”) with BancFirst, as administrative agent for the lenders (the “Lender”), which provides for a revolving credit facility (“BF Credit Facility”) with an approved maximum credit amount (“Maximum Credit Amount”) of $60 million, subject to borrowing base restrictions. The Partnership paid an origination fee of 0.50% of the Maximum Credit Amount, or $300,000, and is subject to an additional fee of 0.25% on any incremental increase to the borrowing base. Total capitalized loan costs were approximately $400,000 and are being amortized over the life of the BF Credit Facility. Approximately $166,000 million of the deferred loan costs remain unamortized as of December 31, 2022; approximately $142,000 are included in Other current assets, net and the other approximate $24,000 is recorded in Other assets on the Partnership’s consolidated balance sheet. The Partnership also is required to pay an annual fee to the Lender of $30,000, and an unused facility fee of 0.25% on the unused portion of the Revolving Credit Facility, based on borrowings outstanding during a quarter. The maturity date is March 1, 2024. At closing, the Partnership borrowed approximately $40 million. The proceeds were used to pay the $40 million outstanding balance and accrued interest on the Simmons Credit Facility described above. Any further advances under the BF Credit Facility are to be used to fund capital expenditures for the development of the Partnership’s undrilled acreage. Under the terms of the BF Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The BF Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells. Under the BF Loan Agreement, the initial borrowing base was $60 million. The Partnership’s borrowing base is reduced by a Monthly Commitment Reduction, which is currently stipulated to be $1 million. Therefore, as of December 31, 2022, the borrowing base was $41 million. The borrowing base and Monthly Commitment Reduction are subject to redetermination semi-annually, on March 1 and September 1, based upon the Lender’s analysis of the Partnership’s proven oil and natural gas reserves. In conjunction with the Lender’s March 1 redetermination analysis, the Partnership and Lender agreed to amend the BF Loan Agreement, including establishing a fixed borrowing base of $30 million and eliminating the Monthly Commitment Reduction. See additional information in Note 9. Subsequent Events. The Lender is also permitted to cause the borrowing base to be redetermined up to two times during a 12-month period. Outstanding borrowings under the BF Credit Facility cannot exceed the lesser of the borrowing base or the Maximum Credit Amount at any time. The interest rate is equal to the Wall Street Journal Prime Rate plus 0.50%, with a floor of 4.00%. Also, the BF Loan Agreement requires to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production under certain conditions. As amended in August 2022, the Partnership is not required to enter into future hedging transactions as long as the Partnership maintains a BF Credit Facility utilization rate of less than or equal to 20% of the Partnership’s PV-9 (defined as the net present value, discounted at 9% per annum), as calculated by the Lender during the Lender’s scheduled semi-annual redeterminations described above. However, the Partnership must hedge at least 50% of its rolling 12-month projected future production if the Partnership’s utilization of the BF Credit Facility is greater than 20% but less than or equal to 30% of PV-9, and at least 50% of its rolling 24-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is greater than 30% of PV-9. Based on the Partnership’s utilization of the BF Credit Facility and Lender’s current calculation of PV-9, the Partnership was not subject to any additional hedging requirements under the amended BF Loan Agreement as of December 31, 2022. See Note 6. Risk Management for more information on the Partnership’s risk management program as required under the BF Loan Agreement. The BF Credit Facility contains prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants include: ● A minimum ratio of trailing 12-month EBITDAX to debt service coverage of 1.20 to 1.0 ● A minimum ratio of current assets to current liabilities of 1.00 to 1.00 As amended in March 2023, the Partnership is permitted to make distributions to its limited partners so long as the Partnership is in compliance with its debt service coverage ratio and no other event of default has occurred. The March 2023 amendment to the BF Loan Agreement eliminated the restriction on the Partnership’s ability to pay limited partner distributions if the outstanding balance of the BF Credit Facility was greater than 50% of the lesser of (i) the Maximum Credit Amount or (ii) the current borrowing base (“Restricted Payment Clause”). See additional information in Note 9. Subsequent Events.. At December 31, 2022, the outstanding balance on the BF Credit Facility was approximately $22.6 million, and the interest rate was 8.00%. The Partnership was in compliance with its applicable covenants at December 31, 2022. As of December 31, 2022 and 2021, the outstanding balances on the BF Credit Facility were approximately $22.6 million and $23.0 million, respectively, which approximated the fair market value. The Partnership estimated the fair value of its credit facility by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Fair Value Disclosures [Text Block]	Note 5. Fair Value of Financial Instruments The Partnership follows authoritative guidance related to fair value measurement and disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement using market participant assumptions at the measurement date. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The three levels are defined as follows: ● Level 1: Quoted prices in active markets for identical assets ● Level 2: Significant other observable inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, either directly or indirectly, for substantially the full term of the financial instrument ● Level 3: Significant unobservable inputs The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and the consideration of factors specific to the asset or liability. The Partnership’s policy is to recognize transfers in or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Partnership has consistently applied the valuation techniques discussed above for all periods presented. During the years ended December 31, 2022 and 2021, there were no transfers in or out of Level 1, Level 2, or Level 3 assets and liabilities measured on a recurring basis. As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2022 and 2021. Fair Value Measurements at December 31, 2022 Quoted Prices in Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current liabilities $ - $ (3,173,965 ) $ - Total $ - $ (3,173,965 ) $ - Fair Value Measurements at December 31, 2021 Quoted Prices in Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current liabilities $ - $ (1,264,935 ) $ - Commodity derivatives - noncurrent liabilities $ - $ (1,099,388 ) $ - Total $ - $ (2,364,323 ) $ - The Level 2 instruments presented in the table above consist of Partnership’s costless collar commodity derivative instruments. The fair value of the Partnership’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated by the Partnership using various methodologies and significant observable inputs, including quoted market prices in active markets and quotes from third parties, among other things. The Partnership also performed an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Partnership assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually-required payments. Additionally, the Partnership considered that the counterparty is of substantial credit quality and had the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. See additional detail in Note 6. Risk Management. Fair Value of Other Financial Instruments The carrying value of the Partnership’s cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities 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. In addition, see Note 4. Debt for the fair value discussion on the Partnership’s debt.

Risk Management

Risk Management	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	Note 6. Risk Management Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. The Partnership periodically utilizes derivative contracts to manage the commodity price risk on the Partnership’s future oil production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations. In accordance with the amended Simmons Loan Agreement discussed in Note 4. Debt, the Partnership was required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 2020 through February 2021. In July 2021, the Partnership began its risk management program required under the BF Loan Agreement (see Note 4. Debt) by entering into costless collar derivative contracts for the period from July 2021 to September 2023. The Partnership generally uses costless collar derivative contracts, which establish floor and ceiling prices on future anticipated production. The Partnership did not pay or receive a premium related to the costless collars into which it entered to remain compliant with each loan agreement, and the contracts are settled monthly. As of December 31, 2022, the Partnership’s derivative instruments were in a loss position. The Partnership has recognized a total liability of approximately $3.2 million, of which the full balance has been recorded as current in Derivative liability on the Partnership’s consolidated balance sheet as of December 31, 2022. The Partnership’s derivative instruments were also in a loss position as of December 31, 2021. The Partnership recognized a total liability of approximately $2.4 million, of which $1.3 million has been recorded as current in Derivative liability and $1.1 million has been recorded as Derivative liability – noncurrent on the Partnership’s consolidated balance sheet as of December 31, 2021. These current and noncurrent derivative liabilities as of December 31, 2022 and 2021 approximate fair value. The Partnership did not designate its derivative instruments as hedges for accounting purposes and did not enter into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The following table presents the settlement losses of matured derivative instruments and non-cash mark-to-market losses for the periods presented. Year Ended Year Ended Settlements on matured derivatives $ (6,603,660 ) $ (1,182,420 ) Loss on mark-to-market of derivatives, net (668,714 ) (1,761,563 ) Loss on derivatives $ (7,272,374 ) $ (2,943,983 ) Settlements on matured derivatives reflect realized gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash, unrealized) gains or losses represent the change in fair value of derivative instruments which were held at period-end. Unrealized gains or losses do not represent actual settlements or payments made to or from the counterparty. The table below summarizes the Partnership’s outstanding derivative contracts (costless collars – purchased put options and written call options) on the Partnership’s future oil and natural gas production. Settlement Period Basis Product Volume Weighted Average Floor / Ceiling Prices ($) 01/2023 - 09/2023 NYMEX Oil (bbls) 224,000 50.00 / 69.72 02/2023 - 09/2023 Henry Hub Gas (MMbtu) 275,000 2.00 / 4.30 The Partnership’s outstanding derivative instrument is covered by an International Swap Dealers Association Master Agreement (“ISDA”) entered into with the counterparty. The ISDA may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately. The Partnership has netting arrangements with the counterparty that provide for offsetting payables against receivables from separate derivative instruments. The use of derivative instruments involves the risk that the Partnership’s counterparty will be unable to meet the financial terms of such instruments.

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 7. 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 was 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 on April 24, 2017. As of the conclusion of the offering on April 24, 2017, the Partnership had completed the sale of approximately 19.0 million common units for total gross proceeds of $374.2 million and proceeds net of offerings costs of $349.6 million. Under the agreement with the Dealer Manager, the Dealer Manager received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager will also be paid a contingent incentive fee, which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold based on the performance of the Partnership. Based on the common units sold in the best-efforts offering, the total contingent fee is approximately $15.0 million. Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units. Accordingly, the Partnership will not make any distributions or record any liability with respect to the Incentive Distribution Rights (owned by the General Partner), the Class B units or the contingent, incentive payments to the Dealer Manager until an event that triggers Payout occurs. The Partnership Agreement provides that Payout 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, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement; ● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%). 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. In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to market volatility caused by the onset of the COVID-19 pandemic and the impact on the Partnership’s operating cash flows. Further, the Partnership was restricted in making distributions to limited partners under its credit agreements with Simmons Bank (paid off in full in May 2021) and BancFirst (entered in May 2021) until certain conditions within those credit agreements had been met. The Partnership successfully met the required conditions under its BancFirst credit agreement to resume distributions to limited partners in November 2021. The outstanding balance on the BF Credit Facility increased to an amount greater than 50% of the applicable borrowing base during the third quarter of 2022, which required the Partnership to obtain a temporary waiver of the Restricted Payment Clause within the BF Loan Agreement from the Lender in September 2022 to make distributions to its limited partners for the months of September 2022, October 2022 and November 2022. The Partnership declared a distribution of $0.138082 per common unit, or approximately $2.6 million, in December 2022. The distribution was accrued as of December 31, 2022, included in Accounts payable and accrued expenses on the Partnership’s consolidated balance sheet, and was paid in January 2023. Prior to the distribution payment made in January 2023, the Partnership had made an approximate $2.6 million principal payment on the BF Credit Facility to bring the Partnership in compliance with the Restricted Payment Clause at time of payment. The Restricted Payment Clause was eliminated from the BF Loan Agreement in the March 2023 amendment to the BF Loan Agreement, as described in Note 9. Subsequent Events. For the year ended December 31, 2022, the Partnership paid distributions of $1.258082 per common unit, or $23.9 million. For the year ended December 31, 2021, the Partnership declared and paid distributions of $0.189863 per common unit, or $3.6 million. The Partnership accumulates unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are required to be paid before final Payout occurs, as defined above. As of December 31, 2022, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.387671 per common unit, or approximately $45 million.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2022
Related Party Transactions [Abstract]
Related Party Transactions Disclosure [Text Block]	Note 8. Related Parties The members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer, David S. McKenney, Chief Financial Officer, Anthony F. Keating, III, Co-Chief Operating Officer and Michael J. Mallick, Co-Chief Operating Officer. Mr. Knight and Mr. McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy Resources 12 GP, LLC, the general partner of Energy Resources 12, L.P. (“ER12”), a limited partnership that also invests in producing and non-producing oil and natural gas properties on-shore in the United States. Entities owned by Messrs. Keating and Mallick own non-voting, Class B units in the general partner of ER12. 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. For the years ended December 31, 2022 and 2021, approximately $165,000 and $135,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At December 31, 2022 and 2021, approximately $57,000 and $44,000, respectively, was due to a member of the General Partner; these costs are 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 ER12, whereby the Administrator will provide administrative, operating and professional services necessary and useful to the Partnership. The Administrator will also assist the General Partner with the day-to-day operations of 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 ER12 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, 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 $634,000 and $586,000 of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator, respectively. Under the ASA, the Administrator will also assist Energy Resources 12 GP, LLC, the general partner of ER12 (“ER12’s General Partner”), with the day-to-day operations of ER12. ER12 currently pays ER12’s General Partner an annual management fee of 0.5% of the total gross equity proceeds raised by ER12 in its best-efforts offering. Under the ASA, ER12’s General Partner will pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. This fee is only applicable to ER12 and does not apply to the Partnership. The Administrator is owned by entities that are controlled by Messrs. Keating and Mallick. E11 Incentive Holdings, LLC (“Incentive Holdings”) was the owner of all Class B units outstanding (62,500) as of March 31, 2017. During the second quarter of 2017, Incentive Holdings transferred substantially all of its assets; on April 5, 2017, Incentive Holdings transferred 18,125 of the 62,500 Class B units to E11 Incentive Carry Vehicle, LLC, an affiliate of Incentive Holdings, for de minimis consideration. On April 6, 2017, the remaining 44,375 Class B units were acquired by Regional Energy Incentives, LP in exchange for approximately $98,000. Regional Energy Incentives, LP is owned by entities that are controlled by Messrs. Keating, Mallick and McKenney. The Class B units entitle the holder to certain distribution rights after Payout, as described in Note 7. Capital Contribution and Partners’ Equity.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2022
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Note 9. Subsequent Events In January 2023, the Partnership paid approximately $2.6 million, or $0.138082 per outstanding common unit, in distributions to its holders of common units. In January 2023, the Partnership declared a monthly cash distribution to its holders of common units of $0.117671 per outstanding common unit for the month of January 2023. The distribution of approximately $2.2 million was paid on February 3, 2023 to common unit holders on record as of January 31, 2023. In February 2023, the Partnership declared a monthly cash distribution to its holders of common units of $0.12 per outstanding common unit for the month of February 2023. The distribution of approximately $2.3 million was paid on March 3, 2023 to common unit holders on record as of February 28, 2023. In March 2023, the Partnership and its Lender of the BF Credit Facility entered into an amendment to the BF Loan Agreement, resulting in the following changes effective as of the date of the amendment: (i) the borrowing base is fixed at $30 million; (ii) the Monthly Commitment Reduction, previously stipulated to be $1 million, has been eliminated; and (iii) the Restricted Payment Clause, which previously required the Partnership’s outstanding balance to be at or below 50% of the effective borrowing base to make distributions, has been eliminated.

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 10. Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) Aggregate Capitalized Costs 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 $ 296,175,283 $ 246,974,543 Non-producing 176,389,110 176,208,611 472,564,393 423,183,154 Accumulated depreciation, depletion and amortization (119,045,055 ) (98,150,833 ) Net capitalized costs $ 353,519,338 $ 325,032,321 Costs Incurred 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 $ 49,381,239 $ 24,217,681 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 14,414,175 16,798,230 2,628,494 19,842,374 Acquisition - - - - Extensions, discoveries and other additions (1) 1,484,190 1,680,394 241,907 2,006,163 Revisions of previous estimates (2) 1,169,401 3,581,458 301,081 2,067,393 Production (967,069 ) (1,159,929 ) (164,851 ) (1,325,243 ) December 31, 2021 16,100,697 20,900,153 3,006,631 22,590,687 Acquisition - - - - Extensions, discoveries and other additions (3) 1,266,835 1,125,029 160,090 1,614,430 Revisions of previous estimates (4) 4,719,015 3,782,400 508,067 5,857,482 Production (1,054,619 ) (1,329,995 ) (190,503 ) (1,466,788 ) December 31, 2022 21,031,928 24,477,587 3,484,285 28,595,811 (1) In 2021, extensions, discoveries and other additions of 2,006 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets. (2) Revisions to previous estimates increased proved reserves by a net amount of 2,067 MBOE. These revisions result from 2,758 MBOE of upward adjustments attributable to changes in the future drill schedule, offset by 691 MBOE of downward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2021 to December 31, 2020. (3) In 2022, extensions, discoveries and other additions of 1,614 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets. (4) Revisions to previous estimates increased proved reserves by a net amount of 5,857 MBOE. These revisions result from 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and 164 MBOE of upward adjustments attributable caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2022 to December 31, 2021, offset by 2,484 MBOE of downward adjustments attributable to well performance 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 $90.51 per barrel of oil, $6.75 per MMcf of natural gas and $40.28 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 $60.08 per barrel of oil, $3.72 per MMcf of natural gas and $26.62 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 10,688,857 12,992,674 2,029,392 14,883,695 December 31, 2021 11,197,370 15,350,678 2,207,738 15,963,554 December 31, 2022 12,959,918 16,547,639 2,355,866 18,073,724 Proved undeveloped reserves: December 31, 2020 3,725,318 3,805,556 599,102 4,958,679 December 31, 2021 4,903,327 5,549,475 798,893 6,627,133 December 31, 2022 8,072,010 7,929,948 1,128,419 10,522,087 The following details the changes in proved undeveloped reserves (PUD) for 2021 and 2022: BOE Proved undeveloped reserves, December 31, 2020 4,958,679 Revisions of previous estimates (1) 2,852,020 Extensions, discoveries and other additions (2) 2,006,163 Conversion to proved developed reserves (3) (3,189,729 ) Proved undeveloped reserves acquired - Proved undeveloped reserves, December 31, 2021 6,627,133 Revisions of previous estimates (4) 7,803,541 Extensions, discoveries and other additions (5) 1,614,430 Conversion to proved developed reserves (6) (5,523,017 ) Proved undeveloped reserves acquired - Proved undeveloped reserves, December 31, 2022 10,522,087 (1) The annual review of the PUDs resulted in a positive revision of approximately 2,852 MBOE. This revision was the result of 2,758 MBOE of upward adjustments attributable to changes in the future drill schedule and 94 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2021 to December 31, 2020. (2) In 2021, extensions, discoveries and other additions of 2,006 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets. (3) The Partnership completed 23 new wells during 2021; therefore, the Partnership converted these 23 wells to proved developed reserves during 2021, which resulted in a downward adjustment to PUDs of 3,190 MBOE. (4) The annual review of the PUDs resulted in a positive revision of approximately 7,804 MBOE. This revision was the result of 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and offset by 373 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 1,614 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets. (6) The Partnership completed 27 new wells during 2022; therefore, the Partnership converted these 27 wells to proved developed reserves during 2022, which resulted in a downward adjustment to PUDs of 5,523 MBOE. Based upon current information from its operators, 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 Future cash inflows $ 2,209,148,928 $ 1,125,263,104 Future production costs (586,350,144 ) (365,741,504 ) Future development costs (110,237,400 ) (63,988,780 ) Future net cash flows 1,512,561,384 695,532,820 10% annual discount (864,351,720 ) (387,348,180 ) Standardized measure of discounted future net cash flows $ 648,209,664 $ 308,184,640 Changes in the standardized measure of discounted future net cash flows are as follows: 2022 2021 Standardized measure at beginning of period $ 308,184,640 $ 72,886,760 Changes resulting from: Acquisition of reserves - - Extensions, discoveries and other additions 49,126,990 25,896,564 Sales of oil, natural gas and NGLs, net of production costs (85,215,526 ) (56,778,262 ) Net changes in prices and production costs 240,520,851 167,970,653 Development costs incurred during the period 49,381,239 24,217,681 Revisions to previous estimates 150,980,130 96,257,622 Accretion of discount 30,861,199 7,298,783 Change in estimated future development costs (95,629,859 ) (29,565,161 ) Standardized measure of discounted future net cash flows $ 648,209,664 $ 308,184,640

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 consolidated financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”). The consolidated financial statements include the accounts of the Partnership and its subsidiaries.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash, Cash Equivalents and Restricted 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.
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. 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 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 our 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 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 Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the 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 Oil, natural gas and natural gas liquids revenue receivable 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 For the year ended December 31, 2022, the Partnership’s oil, natural gas and NGL sales were through two operators. Substantially all the Partnership’s accounts receivable is due from Chord, the largest operator of the Partnership’s oil and natural gas properties in North Dakota (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, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible. Chord is the current operator of 99% of the Partnership’s producing properties. 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.
Asset Retirement Obligation [Policy Text Block]	Asset Retirement Obligation 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 $ 1,564,105 Well additions 139,343 Accretion 87,893 Revisions in estimated cash flows - Balance as of December 31, 2021 1,791,341 Well additions 95,480 Accretion 97,588 Revisions in estimated cash flows (17,671 ) Balance as of December 31, 2022 $ 1,966,738
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 $0.6 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 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 Class B Units and Incentive Distribution Rights are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 7) 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 $ 1,564,105 Well additions 139,343 Accretion 87,893 Revisions in estimated cash flows - Balance as of December 31, 2021 1,791,341 Well additions 95,480 Accretion 97,588 Revisions in estimated cash flows (17,671 ) Balance as of December 31, 2022 $ 1,966,738

Fair Value of Financial Instr_2

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2022 and 2021. Fair Value Measurements at December 31, 2022 Quoted Prices in Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current liabilities $ - $ (3,173,965 ) $ - Total $ - $ (3,173,965 ) $ - Fair Value Measurements at December 31, 2021 Quoted Prices in Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current liabilities $ - $ (1,264,935 ) $ - Commodity derivatives - noncurrent liabilities $ - $ (1,099,388 ) $ - Total $ - $ (2,364,323 ) $ -

Risk Management (Tables)

Risk Management (Tables)	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	The Partnership did not designate its derivative instruments as hedges for accounting purposes and did not enter into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The following table presents the settlement losses of matured derivative instruments and non-cash mark-to-market losses for the periods presented. Year Ended Year Ended Settlements on matured derivatives $ (6,603,660 ) $ (1,182,420 ) Loss on mark-to-market of derivatives, net (668,714 ) (1,761,563 ) Loss on derivatives $ (7,272,374 ) $ (2,943,983 )
Schedule of Derivative Instruments [Table Text Block]	The table below summarizes the Partnership’s outstanding derivative contracts (costless collars – purchased put options and written call options) on the Partnership’s future oil and natural gas production. Settlement Period Basis Product Volume Weighted Average Floor / Ceiling Prices ($) 01/2023 - 09/2023 NYMEX Oil (bbls) 224,000 50.00 / 69.72 02/2023 - 09/2023 Henry Hub Gas (MMbtu) 275,000 2.00 / 4.30

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 $ 296,175,283 $ 246,974,543 Non-producing 176,389,110 176,208,611 472,564,393 423,183,154 Accumulated depreciation, depletion and amortization (119,045,055 ) (98,150,833 ) Net capitalized costs $ 353,519,338 $ 325,032,321
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 $ 49,381,239 $ 24,217,681
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 14,414,175 16,798,230 2,628,494 19,842,374 Acquisition - - - - Extensions, discoveries and other additions (1) 1,484,190 1,680,394 241,907 2,006,163 Revisions of previous estimates (2) 1,169,401 3,581,458 301,081 2,067,393 Production (967,069 ) (1,159,929 ) (164,851 ) (1,325,243 ) December 31, 2021 16,100,697 20,900,153 3,006,631 22,590,687 Acquisition - - - - Extensions, discoveries and other additions (3) 1,266,835 1,125,029 160,090 1,614,430 Revisions of previous estimates (4) 4,719,015 3,782,400 508,067 5,857,482 Production (1,054,619 ) (1,329,995 ) (190,503 ) (1,466,788 ) December 31, 2022 21,031,928 24,477,587 3,484,285 28,595,811 (1) In 2021, extensions, discoveries and other additions of 2,006 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets. (2) Revisions to previous estimates increased proved reserves by a net amount of 2,067 MBOE. These revisions result from 2,758 MBOE of upward adjustments attributable to changes in the future drill schedule, offset by 691 MBOE of downward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2021 to December 31, 2020. (3) In 2022, extensions, discoveries and other additions of 1,614 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets. (4) Revisions to previous estimates increased proved reserves by a net amount of 5,857 MBOE. These revisions result from 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and 164 MBOE of upward adjustments attributable caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2022 to December 31, 2021, offset by 2,484 MBOE of downward adjustments attributable to well performance 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 10,688,857 12,992,674 2,029,392 14,883,695 December 31, 2021 11,197,370 15,350,678 2,207,738 15,963,554 December 31, 2022 12,959,918 16,547,639 2,355,866 18,073,724 Proved undeveloped reserves: December 31, 2020 3,725,318 3,805,556 599,102 4,958,679 December 31, 2021 4,903,327 5,549,475 798,893 6,627,133 December 31, 2022 8,072,010 7,929,948 1,128,419 10,522,087 BOE Proved undeveloped reserves, December 31, 2020 4,958,679 Revisions of previous estimates (1) 2,852,020 Extensions, discoveries and other additions (2) 2,006,163 Conversion to proved developed reserves (3) (3,189,729 ) Proved undeveloped reserves acquired - Proved undeveloped reserves, December 31, 2021 6,627,133 Revisions of previous estimates (4) 7,803,541 Extensions, discoveries and other additions (5) 1,614,430 Conversion to proved developed reserves (6) (5,523,017 ) Proved undeveloped reserves acquired - Proved undeveloped reserves, December 31, 2022 10,522,087 (1) The annual review of the PUDs resulted in a positive revision of approximately 2,852 MBOE. This revision was the result of 2,758 MBOE of upward adjustments attributable to changes in the future drill schedule and 94 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2021 to December 31, 2020. (2) In 2021, extensions, discoveries and other additions of 2,006 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets. (3) The Partnership completed 23 new wells during 2021; therefore, the Partnership converted these 23 wells to proved developed reserves during 2021, which resulted in a downward adjustment to PUDs of 3,190 MBOE. (4) The annual review of the PUDs resulted in a positive revision of approximately 7,804 MBOE. This revision was the result of 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and offset by 373 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 1,614 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets. (6) The Partnership completed 27 new wells during 2022; therefore, the Partnership converted these 27 wells to proved developed reserves during 2022, which resulted in a downward adjustment to PUDs of 5,523 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 Future cash inflows $ 2,209,148,928 $ 1,125,263,104 Future production costs (586,350,144 ) (365,741,504 ) Future development costs (110,237,400 ) (63,988,780 ) Future net cash flows 1,512,561,384 695,532,820 10% annual discount (864,351,720 ) (387,348,180 ) Standardized measure of discounted future net cash flows $ 648,209,664 $ 308,184,640
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 Standardized measure at beginning of period $ 308,184,640 $ 72,886,760 Changes resulting from: Acquisition of reserves - - Extensions, discoveries and other additions 49,126,990 25,896,564 Sales of oil, natural gas and NGLs, net of production costs (85,215,526 ) (56,778,262 ) Net changes in prices and production costs 240,520,851 167,970,653 Development costs incurred during the period 49,381,239 24,217,681 Revisions to previous estimates 150,980,130 96,257,622 Accretion of discount 30,861,199 7,298,783 Change in estimated future development costs (95,629,859 ) (29,565,161 ) Standardized measure of discounted future net cash flows $ 648,209,664 $ 308,184,640

Partnership Organization (Detai

Partnership Organization (Details) shares in Millions			12 Months Ended		46 Months Ended
	Dec. 18, 2015	Jul. 09, 2013 USD ($)	Dec. 31, 2022	Dec. 31, 2020	Apr. 24, 2017 USD ($) shares
Partnership Organization (Details) [Line Items]
Limited Liability Company or Limited Partnership, Business, Formation State		Delaware
Partners' Capital Account, Contributions (in Dollars)		$ 1,000
Non-operated Completed Wells [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net	11%		24%
Oil, Productive Well, Number of Wells, Net			293
Non-operated Wells in the Process of Drilling [Member]
Partnership Organization (Details) [Line Items]
Oil and Gas, Present Activity, Well in Process of Drilling			6
Non-operated Wells in the Process of Drilling [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net				12%
Oil and Gas, Present Activity, Well in Process of Drilling				6
Best-Efforts Offering [Member]
Partnership Organization (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares) | shares					19
Proceeds from Issuance of Common Limited Partners Units (in Dollars)					$ 374,200,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units (in Dollars)					$ 349,600,000

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]
Estimated State Tax Withholding For Limited Partners (in Dollars)	$ (315,000)	$ (250,000)	$ 600,000
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0	0
Revenue Benchmark [Member] | Customer Concentration Risk [Member] | Whiting Petroleum [Member]
Summary of Significant Accounting Policies (Details) [Line Items]
Concentration Risk, Percentage	99%

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	$ 1,791,341	$ 1,564,105
Well additions	95,480	139,343
Accretion	97,588	87,893
Revisions in estimated cash flows	(17,671)	0
Balance	$ 1,966,738	$ 1,791,341

Oil and Gas Investments (Detail

Oil and Gas Investments (Details)				1 Months Ended	12 Months Ended			60 Months Ended
	Mar. 31, 2017	Jan. 11, 2017 USD ($)	Dec. 18, 2015 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2022
Oil and Gas Investments (Details) [Line Items]
Wells in Various Stages of Drilling and Completion Process					6
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					$ 119,000,000
Costs Incurred, Development Costs (in Dollars)					116,000,000
Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member]
Oil and Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					2
Sanish Field Located in Mountrail County, North Dakota [Member] | Maximum [Member]
Oil and Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					$ 4,000,000
Non-operated Completed Wells [Member]
Oil and Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number					27	23		80
Non-operated Completed Wells [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net			11%		24%
Oil, Productive Well, Number of Wells, Net					293			293
Non-operated Wells in the Process of Drilling [Member]
Oil and Gas Investments (Details) [Line Items]
Oil and Gas, Present Activity, Well in Process of Drilling					6			6
Non-operated Wells in the Process of Drilling [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net							12%
Oil and Gas, Present Activity, Well in Process of Drilling							6
Acquisition No. 1 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Business Combination, Consideration Transferred (in Dollars)			$ 159,600,000
Acquisition No. 2 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net		11%
Business Combination, Consideration Transferred (in Dollars)		$ 128,500,000
Acquisition No. 3 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net	10.50%
Business Combination, Consideration Transferred (in Dollars)				$ 52,400,000
Number of Producing Partnership Wells Acquired	82
Oil, Productive Well, Number of Wells, Net	216			216
Number of Future Development Partnership Locations Acquired	150
Gas and Oil Area Undeveloped, Net	253
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Wells Elected to Participate in Drilling								86

Debt (Details)

Debt (Details) - USD ($)			1 Months Ended	12 Months Ended
	May 13, 2021	Nov. 21, 2017	Jan. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt (Details) [Line Items]
Long-Term Line of Credit				$ 22,600,000	$ 23,000,000
Repayments of Lines of Credit			$ 2,600,000	14,000,000	17,063,389
Line of Credit Facility, Fair Value of Amount Outstanding				$ 22,600,000	$ 23,000,000
Revolving Credit Facility [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount	$ 60,000,000	$ 40,000,000
Debt Instrument, Maturity Date	Mar. 01, 2024	Jul. 31, 2021
Long-Term Debt, Percentage Bearing Variable Interest, Percentage Rate	4.25%			8%
Long-Term Line of Credit	$ 40,000,000			$ 22,600,000
Debt Instrument, Fee	origination fee of 0.50% of the Maximum Credit Amount, or $300,000, and is subject to an additional fee of 0.25% on any incremental increase to the borrowing base
Debt Issuance Costs, Gross	$ 400,000
Unamortized Debt Issuance Expense	166,000
Debt Issuance Costs, Noncurrent, Net	142,000
Debt Issuance Costs, Current, Net	$ 24,000
Line of Credit Facility, Commitment Fee Description	The Partnership also is required to pay an annual fee to the Lender of $30,000, and an unused facility fee of 0.25% on the unused portion of the Revolving Credit Facility, based on borrowings outstanding during a quarter
Proceeds from Lines of Credit	$ 40,000,000
Repayments of Lines of Credit	$ 40,000,000
Line of Credit Facility, Collateral	The BF Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells
Line of Credit Facility, Borrowing Capacity, Description	Under the BF Loan Agreement, the initial borrowing base was $60 million. The Partnership’s borrowing base is reduced by a Monthly Commitment Reduction, which is currently stipulated to be $1 million. Therefore, as of December 31, 2022, the borrowing base was $41 million. The borrowing base and Monthly Commitment Reduction are subject to redetermination semi-annually, on March 1 and September 1, based upon the Lender’s analysis of the Partnership’s proven oil and natural gas reserves. In conjunction with the Lender’s March 1 redetermination analysis, the Partnership and Lender agreed to amend the BF Loan Agreement, including establishing a fixed borrowing base of $30 million and eliminating the Monthly Commitment Reduction. See additional information in Note 9. Subsequent Events. The Lender is also permitted to cause the borrowing base to be redetermined up to two times during a 12-month period
Line of Credit Facility, Covenant Compliance				The Partnership was in compliance with its applicable covenants at December 31, 2022.
Revolving Credit Facility [Member] | Prime Rate [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
Debt Instrument, Minimum Interest Rate	4%

Fair Value of Financial Instr_3

Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Inputs, Level 1 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current liabilities	$ 0	$ 0
Commodity derivatives - noncurrent liabilities		0
Total	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current liabilities	(3,173,965)	(1,264,935)
Commodity derivatives - noncurrent liabilities		(1,099,388)
Total	(3,173,965)	(2,364,323)
Fair Value, Inputs, Level 3 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current liabilities	0	0
Commodity derivatives - noncurrent liabilities		0
Total	$ 0	$ 0

Risk Management (Details)

Risk Management (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Discussion of Price Risk Derivative Risk Management Policy	Debt, the Partnership was required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 2020 through February 2021.
Derivative Liability	$ 3,200,000	$ 2,400,000
Derivative Liability, Current	$ 3,173,965	1,264,935
Derivative Liability, Noncurrent		$ 1,099,388

Risk Management (Details) - Sch

Risk Management (Details) - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Schedule Of Derivative Instruments In Statement Of Financial Position Fair Value Abstract
Settlements on matured derivatives, net	$ (6,603,660)	$ (1,182,420)
Loss on mark-to-market of derivatives, net	(668,714)	(1,761,563)
Loss on derivatives, net	$ (7,272,374)	$ (2,943,983)

Risk Management (Details) - S_2

Risk Management (Details) - Schedule of Derivative Instruments - Price Risk Derivative [Member]	12 Months Ended
	Dec. 31, 2022 $ / bbl bbl
Costless Collar Agreements 1 [Member]
Derivative [Line Items]
Basis	NYMEX
Product	Oil (bbls)
Volume | bbl	224,000
Floor Price	50
Ceiling Price	69.72
Costless Collar Agreements 3 [Member]
Derivative [Line Items]
Basis	Henry Hub
Product	Gas (MMbtu)
Volume | bbl	275,000
Floor Price	2
Ceiling Price	4.3

Capital Contribution and Part_2

Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions		1 Months Ended		12 Months Ended		46 Months Ended
	Jul. 09, 2013	Jan. 31, 2023	Dec. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Apr. 24, 2017
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Contributions	$ 1,000
Distributions to organizational limited partner	$ 990
Managing Dealer, Selling Commissions, Percentage				6%
Managing Dealer, Maximum Contingent Incentive Fee on Gross Proceeds, Percentage				4%
Maximum Contingent Offering Costs, Selling Commissions and Marketing Expenses			$ 15,000,000	$ 15,000,000
Key Provisions of Operating or Partnership Agreement, Description				The Partnership Agreement provides that Payout 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, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement;   ● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%).
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share)			$ 0.138082	$ 1.258082	$ 0.189863
Distribution Made to Limited Partner, Cash Distributions Paid			$ 2,600,000	$ 23,870,186	$ 3,602,361
Repayments of Lines of Credit		$ 2,600,000		$ 14,000,000	$ 17,063,389
Annualized Rate Of Retun				7%
Distribution At Payout To Limited Partner Per Common Unit (in Dollars per share)				$ 2.387671
Distribution At Payout To Limited Partner				$ 45,000,000
Best-Efforts Offering [Member]
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares)						19
Proceeds from Issuance of Common Limited Partners Units						$ 374,200,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units						$ 349,600,000

Related Parties (Details)

Related Parties (Details) - USD ($)				12 Months Ended
	Jan. 01, 2020	Apr. 06, 2017	Apr. 05, 2017	Dec. 31, 2022	Dec. 31, 2021	Mar. 31, 2017
Related Parties (Details) [Line Items]
Class B Units, Units Outstanding (in Shares)				62,500	62,500
E11 Incentive Holdings [Member]
Related Parties (Details) [Line Items]
Class B Units, Units Outstanding (in Shares)						62,500
Units transferred to E11 Incentive Carry Vehicle, LP for minimis Consideration [Member] | E11 Incentive Holdings [Member]
Related Parties (Details) [Line Items]
Class B Units, transferred (in Shares)			18,125
Units Sold to Regional Energy Incentives, LP [Member] | E11 Incentive Holdings [Member]
Related Parties (Details) [Line Items]
Class B Units, Units Sold (in Shares)		44,375
Class B Units, Total Sales Price for Sale of Capital Units		$ 98,000
General Partner [Member]
Related Parties (Details) [Line Items]
Selling, General and Administrative Expense				$ 165,000	$ 135,000
Other Liabilities, Current				57,000	44,000
Affiliated Entity [Member]
Related Parties (Details) [Line Items]
Selling, General and Administrative Expense				$ 634,000	$ 586,000
Administrative Service Agreement [Member]
Related Parties (Details) [Line Items]
Related Party, Administrative Service Agreement	Under the ASA, the Administrator will also assist Energy Resources 12 GP, LLC, the general partner of ER12 (“ER12’s General Partner”), with the day-to-day operations of ER12. ER12 currently pays ER12’s General Partner an annual management fee of 0.5% of the total gross equity proceeds raised by ER12 in its best-efforts offering. Under the ASA, ER12’s General Partner will pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. This fee is only applicable to ER12 and does not apply to the Partnership. The Administrator is owned by entities that are controlled by Messrs. Keating and Mallick.

Subsequent Events (Details)

Subsequent Events (Details) - Subsequent Event [Member] - USD ($) $ / shares in Units, $ in Millions	1 Months Ended
	Mar. 31, 2023	Feb. 28, 2023	Jan. 31, 2023
Subsequent Events (Details) [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid			$ 2.6
Distribution Made to Limited Partner, Distributions Paid, Per Unit			$ 0.138082
Dividend Declared [Member]
Subsequent Events (Details) [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid		$ 2.3	$ 2.2
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0.12	$ 0.117671
Revolving Credit Facility [Member]
Subsequent Events (Details) [Line Items]
Line of Credit Facility, Description	the Partnership and its Lender of the BF Credit Facility entered into an amendment to the BF Loan Agreement, resulting in the following changes effective as of the date of the amendment: (i) the borrowing base is fixed at $30 million; (ii) the Monthly Commitment Reduction, previously stipulated to be $1 million, has been eliminated; and (iii) the Restricted Payment Clause, which previously required the Partnership’s outstanding balance to be at or below 50% of the effective borrowing base to make distributions, has been eliminated

Supplementary Information on _3

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details)	12 Months Ended				60 Months Ended
	Dec. 31, 2022 Boe $ / bbl $ / MMcf		Dec. 31, 2021 Boe $ / bbl $ / MMcf		Dec. 31, 2022
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)	7,803,541	[1]	2,852,020	[2]
Number of Proved Developed Non-producing Wells Converted to Producing	27		23
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)	(5,523,017)	[3]	(3,189,729)	[4]
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)	5,857,000		(2,067,000)
Proved Reserves [Member] | Adjustment 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)	8,177,000		(2,758,000)
Proved Reserves [Member] | Adjustments Related to Prices [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)	164,000		(691,000)
Proved Reserves [Member] | Adjustments Related to Successful Drilling [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)	1,614,000		2,006,000
Proved Reserves [Member] | Adjustments Related to Well Performance [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)	(2,484,000)
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)	7,804,000		2,852,000
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)			3,190,000
Proved Undeveloped Reserves [Member] | Adjustment 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)			2,758,000
Proved Undeveloped Reserves [Member] | Adjustments Related to Natural Gas Shrink [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)	373,000		94,000
Non-operated Completed Wells [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number	27		23		80
Non-operated Completed Wells [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, Net (Energy), Period Increase (Decrease)	5,523,000
Including Effect 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	90.51		60.08
Including Effect 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)) | $ / MMcf	6.75		3.72
Including Effect 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	40.28		26.62
[1]The annual review of the PUDs resulted in a positive revision of approximately 7,804 MBOE. This revision was the result of 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and offset by 373 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 positive revision of approximately 2,852 MBOE. This revision was the result of 2,758 MBOE of upward adjustments attributable to changes in the future drill schedule and 94 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2021 to December 31, 2020.[3]The Partnership completed 27 new wells during 2022; therefore, the Partnership converted these 27 wells to proved developed reserves during 2022, which resulted in a downward adjustment to PUDs of 5,523 MBOE.[4]The Partnership completed 23 new wells during 2021; therefore, the Partnership converted these 23 wells to proved developed reserves during 2021, which resulted in a downward adjustment to PUDs of 3,190 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]
Proved Properties	$ 472,564,393	$ 423,183,154
Accumulated depreciation, depletion and amortization	(119,045,055)	(98,150,833)
Net capitalized costs	353,519,338	325,032,321
Producing Properties [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved Properties	296,175,283	246,974,543
Non-Producing Properties [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved Properties	$ 176,389,110	$ 176,208,611

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	$ 49,381,239	$ 24,217,681

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
Reserve Quantities [Line Items]
Balance	22,590,687		19,842,374
Proved developed reserves:
Balance, Proved Developed Reserves (in Barrels of Oil Equivalent) | Boe	18,073,724		15,963,554		14,883,695
Proved undeveloped reserves:
Balance, Proved Undeveloped Reserves (in Barrels of Oil Equivalent) | Boe	10,522,087		6,627,133		4,958,679
Balance, Proved Undeveloped Reserves (in Barrels of Oil Equivalent) | Boe	10,522,087		6,627,133		4,958,679
Revisions of previous estimates (in Barrels of Oil Equivalent) | Boe	7,803,541	[1]	2,852,020	[2]
Extensions, discoveries and other additions (in Barrels of Oil Equivalent) | Boe	1,614,430	[3]	2,006,163	[4]
Conversion to proved developed reserves (in Barrels of Oil Equivalent) | Boe	(5,523,017)	[5]	(3,189,729)	[6]
Proved undeveloped reserves acquired (in Barrels of Oil Equivalent) | Boe	0		0
Acquisition	0		0
Extensions, discoveries and other additions	1,614,430	[7]	2,006,163	[8]
Revisions of previous estimates	5,857,482	[9]	2,067,393	[10]
Production	(1,466,788)		(1,325,243)
Balance	28,595,811		22,590,687
Oil [Member]
Reserve Quantities [Line Items]
Balance	16,100,697		14,414,175
Proved developed reserves:
Balance, Proved Developed Reserves	12,959,918		11,197,370		10,688,857
Proved undeveloped reserves:
Balance, Proved Undeveloped Reserves	8,072,010		4,903,327		3,725,318
Acquisition	0		0
Extensions, discoveries and other additions	1,266,835	[7]	1,484,190	[8]
Revisions of previous estimates	4,719,015	[9]	1,169,401	[10]
Production	(1,054,619)		(967,069)
Balance	21,031,928		16,100,697
Natural Gas [Member]
Reserve Quantities [Line Items]
Balance | Mcf	20,900,153		16,798,230
Proved developed reserves:
Balance, Proved Developed Reserves | Mcf	16,547,639		15,350,678		12,992,674
Proved undeveloped reserves:
Balance, Proved Undeveloped Reserves | Mcf	7,929,948		5,549,475		3,805,556
Acquisition | Mcf	0		0
Extensions, discoveries and other additions | Mcf	1,125,029	[7]	1,680,394	[8]
Revisions of previous estimates | Mcf	3,782,400	[9]	3,581,458	[10]
Production | Mcf	(1,329,995)		(1,159,929)
Balance | Mcf	24,477,587		20,900,153
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Balance	3,006,631		2,628,494
Proved developed reserves:
Balance, Proved Developed Reserves	2,355,866		2,207,738		2,029,392
Proved undeveloped reserves:
Balance, Proved Undeveloped Reserves	1,128,419		798,893		599,102
Acquisition	0		0
Extensions, discoveries and other additions	160,090	[7]	241,907	[8]
Revisions of previous estimates	508,067	[9]	301,081	[10]
Production	(190,503)		(164,851)
Balance	3,484,285		3,006,631
[1]The annual review of the PUDs resulted in a positive revision of approximately 7,804 MBOE. This revision was the result of 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and offset by 373 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 positive revision of approximately 2,852 MBOE. This revision was the result of 2,758 MBOE of upward adjustments attributable to changes in the future drill schedule and 94 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2021 to December 31, 2020.[3]In 2022, extensions, discoveries and other additions of 1,614 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.[4]In 2021, extensions, discoveries and other additions of 2,006 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.[5]The Partnership completed 27 new wells during 2022; therefore, the Partnership converted these 27 wells to proved developed reserves during 2022, which resulted in a downward adjustment to PUDs of 5,523 MBOE.[6]The Partnership completed 23 new wells during 2021; therefore, the Partnership converted these 23 wells to proved developed reserves during 2021, which resulted in a downward adjustment to PUDs of 3,190 MBOE.[7]In 2022, extensions, discoveries and other additions of 1,614 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.[8]In 2021, extensions, discoveries and other additions of 2,006 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator of the Sanish Field Assets.[9]Revisions to previous estimates increased proved reserves by a net amount of 5,857 MBOE. These revisions result from 8,177 MBOE of upward adjustments attributable to changes in the future drill schedule and 164 MBOE of upward adjustments attributable caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2022 to December 31, 2021, offset by 2,484 MBOE of downward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2022 to December 31, 2021.[10]Revisions to previous estimates increased proved reserves by a net amount of 2,067 MBOE. These revisions result from 2,758 MBOE of upward adjustments attributable to changes in the future drill schedule, offset by 691 MBOE of downward adjustments attributable to well performance 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 ($)	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	$ 2,209,148,928	$ 1,125,263,104
Future production costs	(586,350,144)	(365,741,504)
Future development costs	(110,237,400)	(63,988,780)
Future net cash flows	1,512,561,384	695,532,820
10% annual discount	(864,351,720)	(387,348,180)
Standardized measure of discounted future net cash flows	$ 648,209,664	$ 308,184,640	$ 72,886,760

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 ($)	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	$ 308,184,640	$ 72,886,760
Acquisition of reserves	0	0
Extensions, discoveries and other additions	49,126,990	25,896,564
Sales of oil, natural gas and NGLs, net of production costs	(85,215,526)	(56,778,262)
Net changes in prices and production costs	240,520,851	167,970,653
Development costs incurred during the period	49,381,239	24,217,681
Revisions to previous estimates	150,980,130	96,257,622
Accretion of discount	30,861,199	7,298,783
Change in estimated future development costs	(95,629,859)	(29,565,161)
Standardized measure of discounted future net cash flows	$ 648,209,664	$ 308,184,640