Energy 11 10-Q 14 Nov 22 2022 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2022	Nov. 14, 2022
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, 2022
Document Fiscal Year Focus	2022
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, 2022	Dec. 31, 2021
Assets
Cash and cash equivalents	$ 3,525,313	$ 912,828
Accounts receivable	23,161,081	15,118,535
Other current assets, net	379,715	317,497
Total Current Assets	27,066,109	16,348,860
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $112,824,448 and $98,150,833, respectively	351,624,281	325,032,321
Other assets	59,135	165,578
Total Assets	378,749,525	341,546,759
Liabilities
Accounts payable and accrued expenses	19,447,723	9,847,984
Derivative liability	3,914,971	1,264,935
Total Current Liabilities	23,362,694	11,112,919
Revolving credit facility	29,100,000	23,000,000
Asset retirement obligations	2,048,106	1,791,341
Derivative liability - noncurrent	0	1,099,388
Total Liabilities	54,510,800	37,003,648
Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)	324,240,452	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	324,238,725	304,543,111
Total Liabilities and Partners’ Equity	$ 378,749,525	$ 341,546,759

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - USD ($)	Sep. 30, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Oil and natural gas properties, accumulated depreciation, depletion and amortization (in Dollars)	$ 112,824,448	$ 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 ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Revenues
Oil	$ 27,811,323	$ 17,888,207	$ 69,253,619	$ 40,358,354
Natural gas	2,886,757	1,269,296	6,932,072	3,613,282
Natural gas liquids	2,278,848	1,835,202	6,717,097	4,504,618
Total revenue	32,976,928	20,992,705	82,902,788	48,476,254
Operating costs and expenses
Production expenses	4,402,718	2,747,487	12,838,368	8,270,708
Production taxes	2,602,071	1,653,661	6,363,511	3,749,060
General and administrative expenses	480,776	325,168	1,556,868	1,172,298
Depreciation, depletion, amortization and accretion	5,777,217	6,547,607	14,856,872	16,387,823
Total operating costs and expenses	13,262,782	11,273,923	35,615,619	29,579,889
Operating income	19,714,146	9,718,782	47,287,169	18,896,365
Gain (loss) on derivatives, net	4,300,050	(2,230,604)	(6,808,453)	(2,810,264)
Interest expense, net	(411,333)	(445,388)	(915,543)	(1,452,932)
Total other income (expense), net	3,888,717	(2,675,992)	(7,723,996)	(4,263,196)
Net income	$ 23,602,863	$ 7,042,790	$ 39,563,173	$ 14,633,169
Basic and diluted net income per common unit (in Dollars per share)	$ 1.24	$ 0.37	$ 2.09	$ 0.77
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, 2020	$ 280,345,822		$ 280,347,549	$ (1,727)
Balance (in Shares) at Dec. 31, 2020		62,500	18,973,474
Net income	3,463,469		$ 3,463,469
Balance at Mar. 31, 2021	283,809,291		$ 283,811,018	(1,727)
Balance (in Shares) at Mar. 31, 2021		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
Distributions declared and paid to common units	0
Net income	14,633,169
Balance at Sep. 30, 2021	294,978,991		$ 294,980,718	(1,727)
Balance (in Shares) at Sep. 30, 2021		62,500	18,973,474
Balance at Mar. 31, 2021	283,809,291		$ 283,811,018	(1,727)
Balance (in Shares) at Mar. 31, 2021		62,500	18,973,474
Net income	4,126,910		$ 4,126,910
Balance at Jun. 30, 2021	287,936,201		$ 287,937,928	(1,727)
Balance (in Shares) at Jun. 30, 2021		62,500	18,973,474
Net income	7,042,790		$ 7,042,790
Balance at Sep. 30, 2021	294,978,991		$ 294,980,718	(1,727)
Balance (in Shares) at Sep. 30, 2021		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 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	18,973,474	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	18,973,474	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	18,973,474	62,500	18,973,474

Consolidated Statements of Pa_2

Consolidated Statements of Partners' Equity (Parentheticals) - $ / shares	3 Months Ended
	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022
Capital Unit, Class B [Member] | Member Units [Member]
Distributions declared and paid to common units, per unit	$ 0.375891	$ 0.349041	$ 0.322191

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	3 Months Ended	9 Months Ended
	Sep. 30, 2022	Sep. 30, 2022	Sep. 30, 2021
Cash flow from operating activities:
Net income	$ 23,602,863	$ 39,563,173	$ 14,633,169
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion	5,777,217	14,856,872	16,387,823
(Gain) loss on mark-to-market of derivatives, net	(6,227,340)	1,167,463	1,627,844
Non-cash expenses, net		106,443	167,416
Accounts receivable		(8,042,546)	(8,290,053)
Other assets		(62,218)	(86,423)
Accounts payable and accrued expenses		1,886,910	(446,167)
Net cash flow provided by operating activities		49,476,097	23,993,609
Cash flow from investing activities:
Additions to oil and natural gas properties		(33,096,053)	(14,055,311)
Net cash flow used in investing activities		(33,096,053)	(14,055,311)
Cash flow from financing activities:
Cash paid for loan costs			(402,117)
Proceeds from BancFirst revolving credit facility		13,100,000	40,063,389
Payments on BancFirst revolving credit facility		(7,000,000)	(6,063,389)
Payments on Simmons revolving credit facility		0	(40,000,000)
Payments on affiliate term loan		0	(6,000,000)
Distributions paid to limited partners	(7,131,956)	(19,867,559)	0
Net cash flow used in financing activities		(13,767,559)	(12,402,117)
Decrease in cash and cash equivalents		2,612,485	(2,463,819)
Cash and cash equivalents, beginning of period		912,828	2,463,819
Cash and cash equivalents, end of period	$ 3,525,313	3,525,313	0
Interest paid		757,134	1,146,956
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties		$ 15,685,423	$ 5,174,707

Partnership Organization

Partnership Organization	9 Months Ended
	Sep. 30, 2022
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, 2022, the Partnership owned an approximate 25% non-operated working interest in 281 producing wells, an estimated approximate 17% non-operated working interest in 18 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”). Whiting Petroleum Corporation (“Whiting”) and Oasis Petroleum Inc. (“Oasis”), two of the largest producers in the Williston basin of North Dakota, operated substantially all of the Sanish Field Assets through June 30, 2022. On July 1, 2022, Chord Energy Corporation (“Chord”, NASDAQ: CHRD) announced the successful completion of the combination of Whiting and Oasis. The Partnership has not experienced any disruption to its normal course business as a result of this transaction, and Chord continues to administer the ongoing drilling program described below in Note 3. Oil and Natural Gas Investments. 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, 2022
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 2021 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 2022 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2022. 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. Reclassifications Certain prior period amounts in the consolidated financial statements have been reclassified to conform to the current period presentation with no effect on previously reported net income, partners’ equity or cash flows. 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, 2022. 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, 2022
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 68 of these 86 wells have been completed and were producing at September 30, 2022. The Partnership also has 18 wells that are in-process as of September 30, 2022. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 86 wells is approximately $115 million, of which approximately $109 million was incurred as of September 30, 2022. The Partnership estimates the approximate $5 to $8 million in capital expenditures to fully pay for its recently-completed wells along with the remaining 18 wells in various stages of drilling and completion will be incurred through the remainder of 2022 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, 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 $0.4 million and are being amortized over the life of the BF Credit Facility. Approximately $0.2 million of the deferred loan costs remain unamortized as of September 30, 2022; approximately $0.1 million are included in Other current assets, net and the other approximate $0.1 million is recorded as 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 September 30, 2022, the borrowing base was $44 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. The Lender did not make adjustments to the Partnership’s borrowing base or the Monthly Commitment Reduction provision based on its September 1, 2022 redetermination analysis. 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 additional hedging requirements under the amended BF Loan Agreement as of September 30, 2022. 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 The BF Loan Agreement does restrict the Partnership’s ability to pay limited partner distributions if the outstanding balance of the BF Credit Facility is greater than 50% of the lesser of (i) the Maximum Credit Amount or (ii) the current borrowing base (“Restricted Payment Clause”). If the Partnership maintains a credit facility utilization of equal to or less than 50%, the Partnership is permitted to make distributions so long as the Partnership is in compliance with its debt service coverage ratio and no other event of default has occurred. As of September 30, 2022, the Partnership was in compliance with its debt service coverage ratio; however, its outstanding balance was greater than 50% of the current borrowing base. In September 2022, the Lender agreed to waive the Restricted Payment Clause for the months of September 2022, October 2022 and November 2022; therefore, the Partnership will be permitted to make distributions to its limited partners for those months even if the Partnership’s utilization of its credit facility exceeds 50% of the current borrowing base. At September 30, 2022, the outstanding balance on the BF Credit Facility was approximately $29.1 million, and the interest rate was 6.75%. The Partnership was in compliance with its applicable covenants at September 30, 2022. At September 30, 2022 and December 31, 2021, the outstanding balances on the BF Credit Facility of approximately $29.1 million and $23.0 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, 2022
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: 2022 2021 Balance at January 1 $ 1,791,341 $ 1,564,105 Well additions 73,508 133,016 Accretion 71,993 64,636 Revisions 111,264 - Balance at September 30 $ 2,048,106 $ 1,761,757

Fair Value of Financial Instrum

Fair Value of Financial Instruments	9 Months Ended
	Sep. 30, 2022
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 nine months ended September 30, 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 September 30, 2022 and December 31, 2021. Fair Value Measurements at September 30, 2022 Quoted Prices in Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current liabilities $ - $ (3,914,971 ) $ - Total $ - $ (3,914,971 ) $ - 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 using various methodologies and significant observable inputs. The fair value of the commodity derivatives noted above are included in the Partnership’s consolidated balance sheet at September 30, 2022 and December 31, 2021. 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, 2022
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 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 will be settled monthly. As of September 30, 2022, the Partnership’s derivative instruments were in a loss position. The Partnership recognized a current Derivative liability of approximately $3.9 million on the Partnership’s consolidated balance sheet. As of December 31, 2021, the Partnership’s derivative instruments were also in a loss position; therefore, the Partnership recognized total liabilities of approximately $2.4 million, of which $1.3 million was recorded as current in Derivative liability and $1.1 million was recorded as Derivative liability – noncurrent 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 Three Months Ended Nine Months Ended Nine Months Ended Settlement loss on matured derivatives $ (1,927,290 ) $ - $ (5,640,990 ) $ (1,182,420 ) Gain (loss) on mark-to-market of derivatives, net 6,227,340 (2,230,604 ) (1,167,463 ) (1,627,844 ) Gain (loss) on derivatives, net $ 4,300,050 $ (2,230,604 ) $ (6,808,453 ) $ (2,810,264 ) 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 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 10/2022 - 12/2022 NYMEX Oil (bbls) 78,000 50.00 / 72.00 01/2023 - 09/2023 NYMEX Oil (bbls) 224,000 50.00 / 69.72 11/2022 - 12/2022 Henry Hub Gas (MMbtu) 60,000 2.00 / 4.50 01/2023 - 09/2023 Henry Hub Gas (MMbtu) 305,000 2.00 / 4.32 The Partnership’s outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (“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 its counterparties 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	9 Months Ended
	Sep. 30, 2022
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. 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 the Simmons Loan Agreement and BF Loan Agreement (both described above) until certain conditions within those credit agreements had been met. In November 2021, the Partnership successfully met the required conditions under the BF Loan Agreement to resume distributions to limited partners. Subsequently, the General Partner approved a partial distribution in November 2021 and has paid full monthly distributions in December 2021 through September 2022. 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. As described in Note 4. Debt, the Partnership was in compliance with its debt service coverage ratio at September 30, 2022, but the outstanding balance on the BF Credit Facility was greater than 50% of the current borrowing base. In September 2022, the Lender waived the restriction on Partnership distributions to its limited partners for the months of September 2022, October 2022 and November 2022, even if the Partnership’s utilization of its credit facility exceeds 50% of the current borrowing base. If the Partnership is not able to reduce its utilization of the BF Credit Facility by the end of the waiver period (and maintain compliance with its debt service coverage ratio), it may not be able to obtain similar waivers from the Lender and future distributions to limited partners may be restricted. 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 September 30, 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	9 Months Ended
	Sep. 30, 2022
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, 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 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 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 or will be reimbursed by the Partnership. At September 30, 2022, approximately $32,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses on the consolidated balance sheet. For the three and nine months ended September 30, 2021, approximately $29,000 and $91,000 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 provides administrative, operating and professional services necessary and useful to the Partnership. The Administrator also assists 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 three and nine months ended September 30, 2022, approximately $149,000 and $423,000, respectively, 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, 2021, approximately $129,000 and $420,000, respectively, of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator. 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

Subsequent Events	9 Months Ended
	Sep. 30, 2022
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Note 10. Subsequent Events In October 2022, the Partnership declared and paid $2.0 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

Accounting Policies, by Policy

Accounting Policies, by Policy (Policies)	9 Months Ended
	Sep. 30, 2022
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 2021 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 2022 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2022.
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.
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, 2022. 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.
Reclassification, Comparability Adjustment [Policy Text Block]	Reclassifications Certain prior period amounts in the consolidated financial statements have been reclassified to conform to the current period presentation with no effect on previously reported net income, partners’ equity or cash flows.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2022
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: 2022 2021 Balance at January 1 $ 1,791,341 $ 1,564,105 Well additions 73,508 133,016 Accretion 71,993 64,636 Revisions 111,264 - Balance at September 30 $ 2,048,106 $ 1,761,757

Fair Value of Financial Instr_2

Fair Value of Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 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 September 30, 2022 and December 31, 2021. Fair Value Measurements at September 30, 2022 Quoted Prices in Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current liabilities $ - $ (3,914,971 ) $ - Total $ - $ (3,914,971 ) $ - 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)	9 Months Ended
	Sep. 30, 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 gains (losses) for the periods presented. Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended Settlement loss on matured derivatives $ (1,927,290 ) $ - $ (5,640,990 ) $ (1,182,420 ) Gain (loss) on mark-to-market of derivatives, net 6,227,340 (2,230,604 ) (1,167,463 ) (1,627,844 ) Gain (loss) on derivatives, net $ 4,300,050 $ (2,230,604 ) $ (6,808,453 ) $ (2,810,264 )
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 10/2022 - 12/2022 NYMEX Oil (bbls) 78,000 50.00 / 72.00 01/2023 - 09/2023 NYMEX Oil (bbls) 224,000 50.00 / 69.72 11/2022 - 12/2022 Henry Hub Gas (MMbtu) 60,000 2.00 / 4.50 01/2023 - 09/2023 Henry Hub Gas (MMbtu) 305,000 2.00 / 4.32

Partnership Organization (Detai

Partnership Organization (Details) shares in Millions			9 Months Ended	46 Months Ended
	Dec. 18, 2015	Jul. 09, 2013 USD ($)	Sep. 30, 2022	Apr. 24, 2017 USD ($) 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%		25%
Oil, Productive Well, Number of Wells, Net			281
Non-operated Wells in the Process of Drilling [Member]
Partnership Organization (Details) [Line Items]
Oil and Gas, Present Activity, Well in Process of Drilling			18
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			17%
Oil and Gas, Present Activity, Well in Process of Drilling			18
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

Oil and Natural Gas Investmen_2

Oil and Natural Gas Investments (Details)				1 Months Ended	9 Months Ended	57 Months Ended
	Mar. 31, 2017	Jan. 11, 2017 USD ($)	Dec. 18, 2015 USD ($)	Mar. 31, 2017 USD ($)	Sep. 30, 2022 USD ($)	Sep. 30, 2022
Oil and Natural Gas Investments (Details) [Line Items]
Wells in Various Stages of Drilling and Completion Process					18
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)					$ 115,000,000
Costs Incurred, Development Costs (in Dollars)					109,000,000
Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					5
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)					$ 8,000,000
Non-operated Completed Wells [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number						68
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%		25%
Oil, Productive Well, Number of Wells, Net					281	281
Non-operated Wells in the Process of Drilling [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Oil and Gas, Present Activity, Well in Process of Drilling					18	18
Non-operated Wells in the Process of Drilling [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net					17%
Oil and Gas, Present Activity, Well in Process of Drilling					18	18
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)			$ 159,600,000
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)		$ 128,500,000
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)				$ 52,400,000
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 Natural Gas Investments (Details) [Line Items]
Wells Elected to Participate in Drilling						86

Debt (Details)

Debt (Details) - USD ($)			9 Months Ended
	May 13, 2021	Nov. 21, 2017	Sep. 30, 2022	Sep. 30, 2021	Dec. 31, 2021
Debt (Details) [Line Items]
Long-Term Line of Credit			$ 29,100,000		$ 23,000,000
Debt Issuance Costs, Noncurrent, Net			100,000
Proceeds from Lines of Credit			13,100,000	$ 40,063,389
Repayments of Lines of Credit			7,000,000	$ 6,063,389
Line of Credit Facility, Fair Value of Amount Outstanding			$ 29,100,000		$ 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%		6.75%
Long-Term Line of Credit	$ 40,000,000		$ 29,100,000
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	$ 200,000
Debt Issuance Costs, Current, Net			$ 100,000
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 September 30, 2022, the borrowing base was $44 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. The Lender did not make adjustments to the Partnership’s borrowing base or the Monthly Commitment Reduction provision based on its September 1, 2022 redetermination analysis. 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 September 30, 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%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations - USD ($)	9 Months Ended
	Sep. 30, 2022	Sep. 30, 2021
Schedule Of Asset Retirement Obligations Abstract
Balance	$ 1,791,341	$ 1,564,105
Balance	2,048,106	1,761,757
Well additions	73,508	133,016
Accretion	71,993	64,636
Revisions	$ 111,264	$ 0

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, 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	(3,914,971)	(1,264,935)
Commodity derivatives - noncurrent liabilities		(1,099,388)
Total	(3,914,971)	(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, 2021	Sep. 30, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Discussion of Price Risk Derivative Risk Management Policy	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, Current	$ 1,264,935	$ 3,914,971
Derivative Liability	2,400,000
Derivative Liability, Noncurrent	$ 1,099,388	$ 0

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, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
Schedule Of Derivative Instruments In Statement Of Financial Position Fair Value Abstract
Settlement loss on matured derivatives	$ (1,927,290)	$ 0	$ (5,640,990)	$ (1,182,420)
Gain (loss) on mark-to-market of derivatives, net	6,227,340	(2,230,604)	(1,167,463)	(1,627,844)
Gain (loss) on derivatives, net	$ 4,300,050	$ (2,230,604)	$ (6,808,453)	$ (2,810,264)

Risk Management (Details) - S_2

Risk Management (Details) - Schedule of Derivative Instruments - Price Risk Derivative [Member]	9 Months Ended
	Sep. 30, 2022 $ / bbl bbl
Costless Collar Agreements 1 [Member]
Derivative [Line Items]
Basis	NYMEX
Product	Oil (bbls)
Volume | bbl	78,000
Floor Price	50
Ceiling Price	72
Costless Collar Agreements 2 [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	60,000
Floor Price	2
Ceiling Price	4.5
Costless Collar Agreements 4 [Member]
Derivative [Line Items]
Basis	Henry Hub
Product	Gas (MMbtu)
Volume | bbl	305,000
Floor Price	2
Ceiling Price	4.32

Capital Contribution and Part_2

Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions		3 Months Ended			9 Months Ended		46 Months Ended
	Jul. 09, 2013	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Sep. 30, 2022	Sep. 30, 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 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)		$ 0.375891			$ 1.047123
Distribution Made to Limited Partner, Cash Distributions Paid		$ 7,131,956	$ 6,622,520	$ 6,113,083	$ 19,867,559	$ 0
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 ($)		3 Months Ended		9 Months Ended
	Jan. 01, 2020	Sep. 30, 2022	Sep. 30, 2021	Sep. 30, 2022	Sep. 30, 2021
General Partner [Member]
Related Parties (Details) [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party		$ 32,000	$ 29,000	$ 108,000	$ 91,000
Due to Related Parties, Current		32,000		32,000
Administrative Service Agreement [Member]
Related Parties (Details) [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party		$ 149,000	$ 129,000	$ 423,000	$ 420,000
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] $ / shares in Units, $ in Millions	1 Months Ended
	Oct. 31, 2022 USD ($) $ / shares
Subsequent Events (Details) [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid | $	$ 2
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ / shares	$ 0.107397