Energy 11 10-Q 13 Nov 23 2023 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2023	Nov. 13, 2023
Document Information Line Items
Entity Registrant Name	Energy 11, L.P.
Document Type	10-Q
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		18,973,474
Amendment Flag	false
Entity Central Index Key	0001581552
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Period End Date	Sep. 30, 2023
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q3
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Document Quarterly 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(b) Security	None
Entity Interactive Data Current	Yes

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Sep. 30, 2023	Dec. 31, 2022
Assets
Cash and cash equivalents	$ 341,325	$ 3,053,120
Accounts receivable	15,575,780	17,173,549
Other current assets, net	219,601	317,248
Total Current Assets	16,136,706	20,543,917
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $138,956,698 and $119,045,055, respectively	342,378,757	353,519,338
Other assets	0	23,654
Total Assets	358,515,463	374,086,909
Liabilities
Revolving credit facility	7,000,000	0
Accounts payable and accrued expenses	9,493,149	15,170,168
Derivative liability	513,275	3,173,965
Total Current Liabilities	17,006,424	18,344,133
Revolving credit facility	0	22,600,000
Asset retirement obligations	2,048,293	1,966,738
Total Liabilities	19,054,717	42,910,871
Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)	339,462,473	331,177,765
General partner's interest	(1,727)	(1,727)
Class B Units (62,500 units issued and outstanding, respectively)	0	0
Total Partners’ Equity	339,460,746	331,176,038
Total Liabilities and Partners’ Equity	$ 358,515,463	$ 374,086,909

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - USD ($)	Sep. 30, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Oil and natural gas properties, accumulated depreciation, depletion and amortization (in Dollars)	$ 138,956,698	$ 119,045,055
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 ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Revenues
Oil	$ 21,325,216	$ 27,811,323	$ 67,345,791	$ 69,253,619
Natural gas	837,361	2,886,757	2,984,405	6,932,072
Natural gas liquids	1,913,593	2,278,848	5,793,553	6,717,097
Total revenue	24,076,170	32,976,928	76,123,749	82,902,788
Operating costs and expenses
Production expenses	6,405,176	4,402,718	20,605,740	12,838,368
Production taxes	1,931,082	2,602,071	6,029,821	6,363,511
General and administrative expenses	297,531	480,776	1,381,386	1,556,868
Depreciation, depletion, amortization and accretion	6,519,826	5,777,217	19,992,113	14,856,872
Total operating costs and expenses	15,153,615	13,262,782	48,009,060	35,615,619
Operating income	8,922,555	19,714,146	28,114,689	47,287,169
Gain (loss) on derivatives, net	(770,882)	4,300,050	1,252,427	(6,808,453)
Interest expense, net	(227,611)	(411,333)	(1,021,277)	(915,543)
Total other income (expense), net	(998,493)	3,888,717	231,150	(7,723,996)
Net income	$ 7,924,062	$ 23,602,863	$ 28,345,839	$ 39,563,173
Basic and diluted net income per common unit (in Dollars per share)	$ 0.42	$ 1.24	$ 1.49	$ 2.09
Weighted average common units outstanding - basic and diluted (in Shares)	18,973,474	18,973,474	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, 2021	$ 304,543,111		$ 304,544,838	$ (1,727)
Balance (in Shares) at Dec. 31, 2021		62,500	18,973,474
Distributions declared and paid to common units	(6,113,083)		$ (6,113,083)
Net income	3,944,795		3,944,795
Balance at Mar. 31, 2022	302,374,823		$ 302,376,550	(1,727)
Balance (in Shares) at Mar. 31, 2022		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		62,500	18,973,474
Distributions declared and paid to common units	(19,867,559)
Net income	39,563,173
Balance at Sep. 30, 2022	324,238,725		$ 324,240,452	(1,727)
Balance (in Shares) at Sep. 30, 2022		62,500	18,973,474
Balance at Mar. 31, 2022	302,374,823		$ 302,376,550	(1,727)
Balance (in Shares) at Mar. 31, 2022		62,500	18,973,474
Distributions declared and paid to common units	(6,622,520)		$ (6,622,520)
Net income	12,015,515		12,015,515
Balance at Jun. 30, 2022	307,767,818		$ 307,769,545	(1,727)
Balance (in Shares) at Jun. 30, 2022		62,500	18,973,474
Distributions declared and paid to common units	(7,131,956)		$ (7,131,956)
Net income	23,602,863		23,602,863
Balance at Sep. 30, 2022	324,238,725		$ 324,240,452	(1,727)
Balance (in Shares) at Sep. 30, 2022		62,500	18,973,474
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
Distributions declared to common units	$ (6,786,261)		$ (6,786,261)
Net income	12,999,267		12,999,267
Balance at Mar. 31, 2023	337,389,044		$ 337,390,771	(1,727)
Balance (in Shares) at Mar. 31, 2023		62,500	18,973,474
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
Distributions declared and paid to common units	$ (20,410,772)
Net income	28,345,839
Balance at Sep. 30, 2023	$ 339,460,746		$ 339,462,473	(1,727)
Balance (in Shares) at Sep. 30, 2023	18,973,474	62,500	18,973,474
Balance at Mar. 31, 2023	$ 337,389,044		$ 337,390,771	(1,727)
Balance (in Shares) at Mar. 31, 2023		62,500	18,973,474
Distributions declared to common units	(6,640,716)		$ (6,640,716)
Adjustment to state tax withholding for limited partners	6,562		6,562
Net income	7,422,510		7,422,510
Balance at Jun. 30, 2023	338,177,400		$ 338,179,127	(1,727)
Balance (in Shares) at Jun. 30, 2023		62,500	18,973,474
Distributions declared and paid to common units	(6,600,000)
Distributions declared to common units	(6,640,716)		$ (6,640,716)
Net income	7,924,062		7,924,062
Balance at Sep. 30, 2023	$ 339,460,746		$ 339,462,473	$ (1,727)
Balance (in Shares) at Sep. 30, 2023	18,973,474	62,500	18,973,474

Consolidated Statements of Pa_2

Consolidated Statements of Partners' Equity (Parentheticals) - Limited Partner [Member] - $ / shares	3 Months Ended
	Sep. 30, 2023	Jun. 30, 2023	Mar. 31, 2023	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022
Distributions declared and paid to common units, per unit				$ 0.375891	$ 0.349041	$ 0.322191
Distributions declared to common units, per unit	$ 0.35	$ 0.35	$ 0.357671

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Cash flow from operating activities:
Net income (loss)	$ 7,924,062	$ 23,602,863	$ 28,345,839	$ 39,563,173
Depreciation, depletion, amortization and accretion	6,519,826	5,777,217	19,992,113	14,856,872
Loss on mark-to-market of derivatives	(513,828)	(6,227,340)	(3,033,037)	1,167,463
Non-cash expenses			106,443	106,443
Accounts receivable			1,597,770	(8,042,546)
Other assets			14,858	(62,218)
Accounts payable and accrued expenses			435,294	1,886,910
Net cash flow provided by operating activities			47,459,280	49,476,097
Cash flow from investing activities:
Additions to oil and natural gas properties			(14,160,303)	(33,096,053)
Net cash flow used in investing activities			(14,160,303)	(33,096,053)
Cash flow from financing activities:
Proceeds from BancFirst revolving credit facility			0	13,100,000
Payments on BancFirst revolving credit facility			(15,600,000)	(7,000,000)
Distributions paid to limited partners	(6,600,000)	(7,131,956)	(20,410,772)	(19,867,559)
Net cash flow provided by (used in) financing activities			(36,010,772)	(13,767,559)
Increase (decrease) in cash, cash equivalents and restricted cash			(2,711,795)	2,612,485
Cash, cash equivalents and restricted cash, beginning of period			3,053,120	912,828
Cash, cash equivalents and restricted cash, end of period	$ 341,325	$ 3,525,313	341,325	3,525,313
Interest paid			825,731	757,134
Accrued capital expenditures related to additions to oil and natural gas properties			$ 3,153,861	$ 15,685,423

Partnership Organization

Partnership Organization	9 Months Ended
	Sep. 30, 2023
Accounting Policies [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]	Note 1. Partnership Organization Energy 11, L.P. (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 19.0 million common units sold for gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million. As of September 30, 2023, the Partnership owned an approximate 24% non-operated working interest in 295 producing wells, an estimated approximate 14% non-operated working interest in four 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”), 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	9 Months Ended
	Sep. 30, 2023
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	Note 2. Summary of Significant Accounting Policies Basis of Presentation The accompanying unaudited financial statements have been prepared in accordance with the instructions for Article 10 of SEC Regulation S-X. Accordingly, they do not include all of the information required by generally accepted accounting principles (“GAAP”) in the United States. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. These unaudited financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements included in its 2022 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 2023 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2023. 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. Use of Estimates The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Revenue Recognition The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Accounts receivable 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 quarter ended September 30, 2023, 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 Sanish Field Assets (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 September 30, 2023 and 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. 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. The Partnership reached a resolution with the state of North Dakota that entailed the Partnership making a payment of taxes on behalf of certain non-resident limited partners to the state for the tax years of 2021 and 2022. The Partnership made a payment of approximately $243,000 (approximately $0.013 per common unit) in May 2023 that settled the 2021 tax year. The Partnership anticipates that the estimate recorded at December 31, 2022 of approximately $315,000 for the 2022 tax year will be settled and paid in the fourth quarter of 2023. 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. Net Income Per Common Unit Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three and nine months ended September 30, 2023. As a result, basic and diluted outstanding common units were the same. The Class B units and Incentive Distribution Rights, as defined below, are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 8) will occur.

Oil and Natural Gas Investments

Oil and Natural Gas Investments	9 Months Ended
	Sep. 30, 2023
Oil and Gas Property [Abstract]
Oil and Gas Properties [Text Block]	Note 3. Oil and Natural 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 82 have been completed and were producing at September 30, 2023. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 86 wells is approximately $121 million, of which approximately $120 million was incurred as of September 30, 2023. The Partnership estimates the approximate $1 million in capital expenditures to fully pay for its recently completed wells along with the remaining four (4) wells in various stages of drilling and completion will be incurred through the fourth 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	9 Months Ended
	Sep. 30, 2023
Debt Disclosure [Abstract]
Debt Disclosure [Text Block]	Note 4. Debt Revolving Credit Facility 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 $0.4 million and are being amortized over the life of the BF Credit Facility. Approximately $59,000 of the deferred loan costs remain unamortized as of September 30, 2023; these costs are included in Other current assets, net 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 Partnership’s previous credit facility. 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 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 September 1, 2023 redetermination analysis, the Lender confirmed the fixed borrowing base of $30 million and there would be no required Monthly Commitment Reduction. 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 the Partnership 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 hedging requirements under the amended BF Loan Agreement as of September 30, 2023. See Note 7. 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 1.00 ● A minimum ratio of current assets to current liabilities of 1.00 to 1.00 (“Current Ratio”) 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. As amended in June 2023, beginning with the quarter ended June 30, 2023, the Partnership is permitted to exclude all loans outstanding under the BF Loan Agreement (i.e., the “BF Credit Facility”) in total current liabilities when calculating the Current Ratio. At September 30, 2023, the outstanding balance on the BF Credit Facility was approximately $7.0 million, and the interest rate was 9.00%. The Partnership was in compliance with all covenants as of September 30, 2023. At September 30, 2023 and December 31, 2022, the outstanding balances on the BF Credit Facility of approximately $7.0 million and $22.6 million, respectively, approximated the fair market value of the BF Credit Facility. 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.

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2023
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation Disclosure [Text Block]	Note 5. Asset Retirement Obligations The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement costs in oil and natural gas properties in the period in which the asset 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 changes in the aggregate ARO are as follows: 2023 2022 Balance at January 1 $ 1,966,738 $ 1,791,341 Well additions 1,086 73,508 Accretion 80,469 71,993 Revisions - 111,264 Balance at September 30 $ 2,048,293 $ 2,048,106

Fair Value of Financial Instrum

Fair Value of Financial Instruments	9 Months Ended
	Sep. 30, 2023
Fair Value Disclosures [Abstract]
Fair Value Disclosures [Text Block]	Note 6. 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 three and nine months ended September 30, 2023 and 2022, 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 September 30, 2023 and December 31, 2022. Fair Value Measurements at September 30, 2023 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity derivatives - current liabilities $ - $ (513,275 ) $ - Total $ - $ (513,275 ) $ - Fair Value Measurements at December 31, 2022 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity derivatives - current liabilities $ - $ (3,173,965 ) $ - Total $ - $ (3,173,965 ) $ - 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, using various methodologies and significant observable inputs. The fair value of the commodity derivatives noted above are included in the Partnership’s consolidated balance sheets at September 30, 2023 and December 31, 2022. See additional detail in Note 7. Risk Management. Fair Value of Other Financial Instruments The carrying value of the Partnership’s other financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and accrued 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.

Risk Management

Risk Management	9 Months Ended
	Sep. 30, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	Note 7. 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. Therefore, 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 July 2021, the Partnership began its risk management program required under the BF Loan Agreement (see Note 4. Debt). To meet BF Loan Agreement requirements, the Partnership entered in to costless collar derivative contracts for the period from July 2021 to September 2023; costless collar contracts 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 the BF Loan Agreement, and the contracts were settled monthly. With the settlement of the September oil and natural gas production contracts during the third quarter of 2023, the Partnership is currently not required to hedge future production under the BF Loan Agreement; therefore, the Partnership has no outstanding derivative contracts as of September 30, 2023. The Partnership’s derivative liability as of September 30, 2023 of approximately $0.5 million represents the settlement loss on the September 2023 oil contract. The Partnership’s derivative instruments were also in a loss position as of December 31, 2022, so the Partnership recognized a current Derivative liability of approximately $3.2 million on the Partnership’s consolidated balance sheet. 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 gains (losses) for the periods presented. Three Months Ended September 30, 2023 Three Months Ended September 30, 2022 Nine Months Ended September 30, 2023 Nine Months Ended September 30, 2022 Settlement loss on matured derivatives $ (1,284,710 ) $ (1,927,290 ) $ (1,780,610 ) $ (5,640,990 ) Gain (loss) on mark-to-market of derivatives, net 513,828 6,227,340 3,033,037 (1,167,463 ) Gain (loss) on derivatives, net $ (770,882 ) $ 4,300,050 $ 1,252,427 $ (6,808,453 ) Settlements on matured derivatives above reflect realized 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 above 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 Partnership’s derivative instruments were covered by International Swap Dealers Association Master Agreements (“ISDA”) entered into with the counterparty. The ISDA provides that as a result of certain circumstances, such as cross-defaults, a counterparty may have required all outstanding derivative instruments under an ISDA to be settled immediately. The Partnership had netting arrangements with its counterparties that provided for offsetting payables against receivables from separate derivative instruments. The use of derivative instruments involved the risk that the Partnership’s counterparty may have been unable to meet the financial terms of such instruments.

Capital Contribution and Partne

Capital Contribution and Partners' Equity	9 Months Ended
	Sep. 30, 2023
Partners' Capital Notes [Abstract]
Partners' Capital Notes Disclosure [Text Block]	Note 8. 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, and the General Partner received Incentive Distribution Rights (defined below). 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 offering costs of $349.6 million. Under the agreement with David Lerner Associates, Inc. (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 through the best-efforts offering, the total contingent fee is a maximum of 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 with respect to the Incentive Distribution Rights or with respect to Class B units and will not make the contingent incentive payments to the Dealer Manager, until 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 unit, regardless of the amount paid for the 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. For the three and nine months ended September 30, 2023, the Partnership paid distributions of $0.350000 and $1.075753 per common unit, or $6.6 million and $20.4 million, respectively. In addition, the Partnership declared a monthly cash distribution to its holders of common units of $0.12 per common unit for the month of September 2023. The declared distribution of approximately $2.3 million, which is included in Accounts payable and accrued expenses on the Partnership’s balance sheet as of September 30, 2023, was paid on October 4, 2023 to the common unit holders on record as of September 30, 2023. For the three and nine months ended September 30, 2022, the Partnership paid distributions of $0.375891 and $1.047123, or $7.1 million and $19.9 million, respectively. 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 described in Income Tax

Related Parties

Related Parties	9 Months Ended
	Sep. 30, 2023
Related Party Transactions [Abstract]
Related Party Transactions Disclosure [Text Block]	Note 9. Related Parties The members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer and David S. McKenney, Chief Financial 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 gas properties on-shore in the United States. 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 three and nine months ended September 30, 2023, approximately $68,000 and $172,000 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 September 30, 2023, approximately $68,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses in the consolidated balance sheets. For the three and nine months ended September 30, 2022, approximately $32,000 and $108,000 of general and administrative costs were incurred by a member of the General Partner and have been reimbursed by the Partnership. 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 was to provide administrative, operating and professional services necessary and useful to the Partnership. The Administrator also was to assist the General Partner with the day-to-day operations of the Partnership. The Administrator is owned by entities that are controlled by Anthony F. Keating, III and Michael J. Mallick, the now former Co-Chief Operating Officers of the General Partner. The ASA became effective January 1, 2021. On April 5, 2023, the Partnership and ER12 entered into an agreement (the “Agreement”) with Messrs. Knight, McKenney, Keating and Mallick, and various affiliates of each, including the Administrator. Pursuant to the Agreement, the ASA was terminated effective immediately, subject to a 60-day transition period to transition the services being provided by the Administrator to Partnership and ER12 management. All Administrator costs and expenses were 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 reimbursed under the ASA included, but were 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, were not incurred by the Administrator on behalf of the Partnership without prior express written consent of the Partnership. Costs and expenses attributable to the services performed by the Administrator under the ASA have been reimbursed by the Partnership. For the nine months ended September 30, 2023, approximately $165,000 of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator. For the three and nine months ended September 30, 2022, approximately $149,000 and $423,000 of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator. Also pursuant to the Agreement, the affiliates of Messrs. Keating and Mallick sold (i) all interests in the General Partner; (ii) all common unit interests in the Partnership; (iii) all Class B Unit interests in the Partnership; and (iv) their Class B Unit interests in ER12’s General Partner to an affiliate of Mr. Knight and withdrew as members of General Partner and ER12’s General Partner. Each of Messrs. Keating and Mallick also resigned their positions as director and as Co-Chief Operating Officer of the General Partner. Additionally, Clifford J. Merritt resigned as President of the General Partner. Prior to the execution of the Agreement, the Administrator assisted 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 paid 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.

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2023
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Note 10. Subsequent Events In October 2023, the Partnership paid approximately $2.3 million, or $0.12 per outstanding common unit, in distributions to its holders of common units. In October 2023, the Partnership declared a monthly cash distribution to its holders of common units of $0.11 per outstanding common unit for the month of October 2023. The distribution of approximately $2.1 million was paid on November 3, 2023 to common unit holders on record as of October 31, 2023.

Accounting Policies, by Policy

Accounting Policies, by Policy (Policies)	9 Months Ended
	Sep. 30, 2023
Accounting Policies [Abstract]
Basis of Accounting, Policy [Policy Text Block]	Basis of Presentation The accompanying unaudited financial statements have been prepared in accordance with the instructions for Article 10 of SEC Regulation S-X. Accordingly, they do not include all of the information required by generally accepted accounting principles (“GAAP”) in the United States. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. These unaudited financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements included in its 2022 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 2023 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2023.
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits.
Use of Estimates, Policy [Policy Text Block]	Use of Estimates The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
Revenue [Policy Text Block]	Revenue Recognition The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Accounts receivable 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.
Receivables, Trade and Other Accounts Receivable, Allowance for Doubtful Accounts, Policy [Policy Text Block]	Accounts Receivable and Concentration of Credit Risk For the quarter ended September 30, 2023, 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 Sanish Field Assets (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 September 30, 2023 and 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.
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. The Partnership reached a resolution with the state of North Dakota that entailed the Partnership making a payment of taxes on behalf of certain non-resident limited partners to the state for the tax years of 2021 and 2022. The Partnership made a payment of approximately $243,000 (approximately $0.013 per common unit) in May 2023 that settled the 2021 tax year. The Partnership anticipates that the estimate recorded at December 31, 2022 of approximately $315,000 for the 2022 tax year will be settled and paid in the fourth quarter of 2023. 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.
Earnings Per Share, Policy [Policy Text Block]	Net Income Per Common Unit Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three and nine months ended September 30, 2023. As a result, basic and diluted outstanding common units were the same. The Class B units and Incentive Distribution Rights, as defined below, are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 8) will occur.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2023
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations [Table Text Block]	The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement costs in oil and natural gas properties in the period in which the asset 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 changes in the aggregate ARO are as follows: 2023 2022 Balance at January 1 $ 1,966,738 $ 1,791,341 Well additions 1,086 73,508 Accretion 80,469 71,993 Revisions - 111,264 Balance at September 30 $ 2,048,293 $ 2,048,106

Fair Value of Financial Instr_2

Fair Value of Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2023
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 September 30, 2023 and December 31, 2022. Fair Value Measurements at September 30, 2023 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity derivatives - current liabilities $ - $ (513,275 ) $ - Total $ - $ (513,275 ) $ - Fair Value Measurements at December 31, 2022 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity derivatives - current liabilities $ - $ (3,173,965 ) $ - Total $ - $ (3,173,965 ) $ -

Risk Management (Tables)

Risk Management (Tables)	9 Months Ended
	Sep. 30, 2023
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 gains (losses) for the periods presented. Three Months Ended September 30, 2023 Three Months Ended September 30, 2022 Nine Months Ended September 30, 2023 Nine Months Ended September 30, 2022 Settlement loss on matured derivatives $ (1,284,710 ) $ (1,927,290 ) $ (1,780,610 ) $ (5,640,990 ) Gain (loss) on mark-to-market of derivatives, net 513,828 6,227,340 3,033,037 (1,167,463 ) Gain (loss) on derivatives, net $ (770,882 ) $ 4,300,050 $ 1,252,427 $ (6,808,453 )

Partnership Organization (Detai

Partnership Organization (Details) shares in Millions			9 Months Ended	46 Months Ended
	Dec. 18, 2015	Jul. 09, 2013 USD ($)	Sep. 30, 2023	Apr. 24, 2017 USD ($) shares
Partnership Organization (Details) [Line Items]
Limited Liability Company or Limited Partnership, Business, Formation State		Delaware
Partners' Capital Account, Contributions (in Dollars)		$ 1,000
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
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			295
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			14%
Oil and Gas, Present Activity, Well in Process of Drilling			4

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Details)	1 Months Ended	3 Months Ended	9 Months Ended	24 Months Ended
	May 31, 2023 USD ($) $ / shares	Jun. 30, 2023 USD ($)	Sep. 30, 2023	Dec. 31, 2022 USD ($)
Accounting Policies [Abstract]
Number of Operators			2
Operator, Percentage			99%
Estimated State Tax Withholding For Limited Partners | $	$ 243,000	$ 6,562		$ 315,000
Distribution Withholding Tax To Limited Partner Per Common Unit | $ / shares	$ 0.01283

Oil and Natural Gas Investmen_2

Oil and Natural Gas Investments (Details) $ in Millions				1 Months Ended	9 Months Ended	69 Months Ended
	Mar. 31, 2017	Jan. 11, 2017 USD ($)	Dec. 18, 2015 USD ($)	Mar. 31, 2017 USD ($)	Sep. 30, 2023 USD ($)	Sep. 30, 2023
Oil and Natural Gas Investments (Details) [Line Items]
Wells in Various Stages of Drilling and Completion Process					4
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					$ 121
Costs Incurred, Development Costs (in Dollars)					120
Sanish Field Located in Mountrail County, North Dakota [Member] | Maximum [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					$ 1
Non-operated Completed Wells [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number						82
Non-operated Completed Wells [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net			11%		24%
Oil, Productive Well, Number of Wells, Net					295	295
Acquisition No. 1 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Business Combination, Consideration Transferred (in Dollars)			$ 159.6
Acquisition No. 2 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net		11%
Business Combination, Consideration Transferred (in Dollars)		$ 128.5
Acquisition No. 3 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net	10.50%
Business Combination, Consideration Transferred (in Dollars)				$ 52.4
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 Natural Gas Investments (Details) [Line Items]
Wells Elected to Participate in Drilling						86

Debt (Details)

Debt (Details) - USD ($)		3 Months Ended	9 Months Ended
	May 13, 2021	Mar. 31, 2023	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Debt (Details) [Line Items]
Repayments of Lines of Credit			$ 15,600,000	$ 7,000,000
Long-Term Line of Credit			0		$ 22,600,000
Line of Credit Facility, Fair Value of Amount Outstanding			7,000,000		$ 22,600,000
Revolving Credit Facility [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount	$ 60,000,000
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	$ 59,000
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
Debt Instrument, Maturity Date	Mar. 01, 2024
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 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 September 1, 2023 redetermination analysis, the Lender confirmed the fixed borrowing base of $30 million and there would be no required Monthly Commitment Reduction. 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 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.
Long-Term Line of Credit			$ 7,000,000
Long-Term Debt, Percentage Bearing Variable Interest, Percentage Rate			9%
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%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations - USD ($)	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Schedule Of Asset Retirement Obligations Abstract
Balance	$ 1,966,738	$ 1,791,341
Balance	2,048,293	2,048,106
Well additions	1,086	73,508
Accretion	80,469	71,993
Revisions	$ 0	$ 111,264

Fair Value of Financial Instr_3

Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis - USD ($)	Sep. 30, 2023	Dec. 31, 2022
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
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	(513,275)	(3,173,965)
Total	(513,275)	(3,173,965)
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
Total	$ 0	$ 0

Risk Management (Details)

Risk Management (Details) - USD ($)	Sep. 30, 2023	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Liability, Current	$ 513,275	$ 3,173,965
Derivative Liability		$ 3,200,000

Risk Management (Details) - Sch

Risk Management (Details) - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Schedule Of Derivative Instruments In Statement Of Financial Position Fair Value Abstract
Settlement loss on matured derivatives	$ (1,284,710)	$ (1,927,290)	$ (1,780,610)	$ (5,640,990)
Gain (loss) on mark-to-market of derivatives, net	513,828	6,227,340	3,033,037	(1,167,463)
Gain (loss) on derivatives, net	$ (770,882)	$ 4,300,050	$ 1,252,427	$ (6,808,453)

Capital Contribution and Part_2

Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions			1 Months Ended		3 Months Ended				9 Months Ended		46 Months Ended
	Oct. 04, 2023	Jul. 09, 2013	Sep. 30, 2023	May 31, 2023	Sep. 30, 2023	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Sep. 30, 2023	Sep. 30, 2022	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
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 unit, regardless of the amount paid for the 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)					$ 0.35	$ 0.375891			$ 1.075753	$ 1.047123
Distribution Made to Limited Partner, Cash Distributions Paid					$ 6,600,000	$ 7,131,956	$ 6,622,520	$ 6,113,083	$ 20,410,772	$ 19,867,559
Annualized Rate Of Retun									7%
Distribution Withholding Tax To Limited Partner Per Common Unit (in Dollars per share)				$ 0.01283
Distribution At Payout To Limited Partner Per Common Unit (in Dollars per share)									$ 2.374841
Distribution At Payout To Limited Partner									$ 45,000,000
Dividend Declared [Member]
Capital Contribution and Partners' Equity (Details) [Line Items]
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share)			$ 0.12
Distribution Made to Limited Partner, Cash Distributions Paid	$ 2,300,000
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 ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
General Partner [Member]
Related Parties (Details) [Line Items]
Selling, General and Administrative Expense	$ 68,000	$ 32,000	$ 172,000	$ 108,000
Other Liabilities, Current	$ 68,000		68,000
Affiliated Entity [Member]
Related Parties (Details) [Line Items]
Selling, General and Administrative Expense		$ 149,000	$ 165,000	$ 423,000

Subsequent Events (Details)

Subsequent Events (Details) - Subsequent Event [Member] - USD ($) $ / shares in Units, $ in Millions		1 Months Ended
	Nov. 03, 2023	Oct. 31, 2023
Subsequent Events (Details) [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid	$ 2.1	$ 2.3
Distribution Made to Limited Partner, Distributions Paid, Per Unit		$ 0.12
Distribution Made to Limited Partner, Distributions Declared, Per Unit		$ 0.11