Energy 11 10-Q 12 Aug 21 2021 Q2 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2021	Aug. 12, 2021
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	Jun. 30, 2021
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q2
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
No Trading Symbol Flag	true

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Jun. 30, 2021	Dec. 31, 2020
Assets
Cash and cash equivalents	$ 5,647,433	$ 1,608,301
Restricted cash and cash equivalents	0	855,518
Accounts receivable	8,514,241	5,890,971
Other current assets, net	227,312	257,524
Total Current Assets	14,388,986	8,612,314
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $85,563,252 and $75,765,289, respectively	326,804,903	323,200,183
Other assets	236,539	0
Total Assets	341,430,428	331,812,497
Liabilities
Revolving credit facility	0	40,000,000
Affiliate term loan	0	6,000,000
Accounts payable and accrued expenses	11,745,969	3,299,810
Derivative liability	0	602,760
Total Current Liabilities	11,745,969	49,902,570
Revolving credit facility	40,063,389	0
Asset retirement obligations	1,684,869	1,564,105
Total Liabilities	53,494,227	51,466,675
Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)	287,937,928	280,347,549
General partner's interest	(1,727)	(1,727)
Class B Units (62,500 units issued and outstanding, respectively)	0	0
Total Partners’ Equity	287,936,201	280,345,822
Total Liabilities and Partners’ Equity	$ 341,430,428	$ 331,812,497

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - USD ($)	Jun. 30, 2021	Dec. 31, 2020
Statement of Financial Position [Abstract]
Oil and natural gas properties, accumulated depreciation, depletion and amortization (in Dollars)	$ 85,563,252	$ 75,765,289
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		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Revenues
Oil	$ 11,868,210	$ 3,995,270	$ 22,470,147	$ 14,225,003
Natural gas	865,226	401,106	2,343,986	755,680
Natural gas liquids	1,146,037	356,142	2,669,416	875,369
Total revenue	13,879,473	4,752,518	27,483,549	15,856,052
Operating costs and expenses
Production expenses	2,867,144	2,120,130	5,523,221	4,172,367
Production taxes	1,093,447	416,550	2,095,399	1,408,891
General and administrative expenses	315,832	355,137	847,130	920,434
Depreciation, depletion, amortization and accretion	4,952,799	5,897,854	9,840,216	10,462,715
Total operating costs and expenses	9,229,222	8,789,671	18,305,966	16,964,407
Operating income (loss)	4,650,251	(4,037,153)	9,177,583	(1,108,355)
Gain (loss) on derivatives, net	0	0	(579,660)	440,890
Interest expense, net	(523,341)	(404,368)	(1,007,544)	(840,629)
Total other expense, net	(523,341)	(404,368)	(1,587,204)	(399,739)
Net income (loss)	$ 4,126,910	$ (4,441,521)	$ 7,590,379	$ (1,508,094)
Basic and diluted net income (loss) per common unit (in Dollars per share)	$ 0.22	$ (0.23)	$ 0.40	$ (0.08)
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	Limited Partner [Member]	General Partner [Member]	Capital Unit, Class B [Member]Member Units [Member]
Balance at Dec. 31, 2019	$ 287,735,971	$ 287,737,698	$ (1,727)
Balance (in Shares) at Dec. 31, 2019		18,973,474		62,500
Distributions declared and paid to common units	(4,584,826)	$ (4,584,826)
Net income (loss)	2,933,427	2,933,427
Balance at Mar. 31, 2020	286,084,572	$ 286,086,299	(1,727)
Balance (in Shares) at Mar. 31, 2020		18,973,474		62,500
Balance at Dec. 31, 2019	287,735,971	$ 287,737,698	(1,727)
Balance (in Shares) at Dec. 31, 2019		18,973,474		62,500
Distributions declared and paid to common units	(4,584,826)
Net income (loss)	(1,508,094)
Balance at Jun. 30, 2020	281,643,051	$ 281,644,778	(1,727)
Balance (in Shares) at Jun. 30, 2020		18,973,474		62,500
Balance at Mar. 31, 2020	286,084,572	$ 286,086,299	(1,727)
Balance (in Shares) at Mar. 31, 2020		18,973,474		62,500
Net income (loss)	(4,441,521)	$ (4,441,521)
Balance at Jun. 30, 2020	281,643,051	$ 281,644,778	(1,727)
Balance (in Shares) at Jun. 30, 2020		18,973,474		62,500
Balance at Dec. 31, 2020	$ 280,345,822	$ 280,347,549	(1,727)
Balance (in Shares) at Dec. 31, 2020	18,973,474	18,973,474		62,500
Net income (loss)	$ 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		18,973,474		62,500
Balance at Dec. 31, 2020	$ 280,345,822	$ 280,347,549	(1,727)
Balance (in Shares) at Dec. 31, 2020	18,973,474	18,973,474		62,500
Distributions declared and paid to common units	$ 0
Net income (loss)	7,590,379
Balance at Jun. 30, 2021	$ 287,936,201	$ 287,937,928	(1,727)
Balance (in Shares) at Jun. 30, 2021	18,973,474	18,973,474		62,500
Balance at Mar. 31, 2021	$ 283,809,291	$ 283,811,018	(1,727)
Balance (in Shares) at Mar. 31, 2021		18,973,474		62,500
Net income (loss)	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	18,973,474	18,973,474		62,500

Consolidated Statements of Pa_2

Consolidated Statements of Partners' Equity (Parentheticals)	3 Months Ended
	Mar. 31, 2020$ / shares
Capital Unit, Class B [Member] | Member Units [Member]
Distributions declared and paid to common units, per unit	$ 0.241644

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Cash flow from operating activities:
Net income	$ 7,590,379	$ (1,508,094)
Adjustments to reconcile net income (loss) to cash from operating activities:
Depreciation, depletion, amortization and accretion	9,840,216	10,462,715
(Gain) / loss on mark-to-market of derivatives	(602,760)	(183,850)
Non-cash expenses, net	99,650	20,327
Changes in operating assets and liabilities:
Oil, natural gas and natural gas liquids revenue receivable	(2,623,270)	3,028,205
Other current assets	96,140	95,982
Accounts payable and accrued expenses	158,668	1,070,422
Net cash flow provided by operating activities	14,559,023	12,985,707
Cash flow from investing activities:
Additions to oil and natural gas properties	(5,043,870)	(17,083,210)
Net cash flow used in investing activities	(5,043,870)	(17,083,210)
Cash flow from financing activities:
Cash paid for loan costs	(394,928)	0
Proceeds from BancFirst revolving credit facility	40,063,389	0
Proceeds from (payments on) Simmons revolving credit facility	(40,000,000)	16,000,000
Payments on affiliate term loan	(6,000,000)	0
Distributions paid to limited partners	0	(4,584,826)
Net cash flow (used in) provided by financing activities	(6,331,539)	11,415,174
Decrease in cash and cash equivalents	3,183,614	7,317,671
Cash and cash equivalents, beginning of period	2,463,819	348,550
Cash and cash equivalents, end of period	5,647,433	7,666,221
Interest paid	731,069	861,825
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$ 9,812,130	$ 19,487,513

Partnership Organization

Partnership Organization	6 Months Ended
	Jun. 30, 2021
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 June 30, 2021, the Partnership owned an approximate 25% non-operated working interest in 256 producing wells, an estimated approximate 17% non-operated working interest in 12 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”) (NYSE: WLL) 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	6 Months Ended
	Jun. 30, 2021
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 2020 Annual Report on Form 10-K. Operating results for the three and six months ended June 30, 2021 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2021. 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. Fair Value of Other Financial Instruments The carrying value of the Partnership’s other financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and accrued expenses, reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments. Net Income (Loss) Per Common Unit Basic net income (loss) per common unit is computed as net income (loss) divided by the weighted average number of common units outstanding during the period. Diluted net income (loss) 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 six months ended June 30, 2021 and 2020. 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 (loss) per common unit until such time that it is probable Payout (as discussed in Note 7) will occur.

Oil and Natural Gas Investments

Oil and Natural Gas Investments	6 Months Ended
	Jun. 30, 2021
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. During 2018, six wells were completed by the Partnership’s operators. In total, the Partnership’s capital expenditures for the drilling and completion of these six wells were approximately $7.8 million. Since the beginning of 2019, the Partnership has elected to participate in the drilling and completion of 48 new wells in the Sanish field. Thirty-five (35) of these 48 wells have been completed and were producing at June 30, 2021; the Partnership has an approximate non-operated working interest of 21% in these 35 wells. The Partnership has an estimated approximate non-operated working interest of 17% in the 12 wells that are in-process as of June 30, 2021. The Partnership has an estimated approximate non-operated working interest of 14% in one well that had not commenced drilling as of June 30, 2021. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 48 wells is approximately $64 million, of which approximately $53 million was incurred as of June 30, 2021. In addition to the approximate $10 to $12 million to complete the 48 wells discussed above, the Partnership estimates it may incur an additional $8 to $12 million in capital expenditures during the second half of 2021 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 for the remainder of 2021, and estimated capital expenditures could be significantly different from amounts actually invested.

Debt

Debt	6 Months Ended
	Jun. 30, 2021
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 are recorded as Other current assets, net and the other approximate $0.2 million in deferred loan costs are 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 initially stipulated to be $1 million. Therefore, as of June 30, 2021, the borrowing base was $59 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 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 under the BF Loan Agreement, the Partnership is required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production. The Partnership must hedge at least 50% of its rolling 12-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is less than 50%, 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 50%. See Note 6. Risk Management for more information on the Partnership’s risk management program as required under the BF Loan Agreement. The BF Credit Facility contains prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants include: ● A minimum ratio of trailing 12-month EBITDAX to debt service coverage of 1.20 to 1.00 ● A minimum ratio of current assets to current liabilities of 1.00 to 1.00 The BF Loan Agreement restricts the Partnership’s ability to pay limited partner distributions until the outstanding balance of the BF Credit Facility is equal to or less than 50% of the Maximum Credit Amount, at which point 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. The Partnership was in compliance with its applicable covenants at June 30, 2021. At June 30, 2021, the outstanding balance on the BF Credit Facility was approximately $40 million, and the interest rate for the BF Credit Facility was 4.00%. As of June 30, 2021 and December 31, 2020, the outstanding balance on the BF Credit Facility and the Simmons Credit Facility was approximately $40 million, which approximated the fair market value of each credit facility. The Partnership estimated the fair value of its credit facilities 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. Term Loan from Affiliate On July 21, 2020, the Partnership, as borrower, entered into a loan agreement with GKDML, LLC (“GKDML”), which provided for an unsecured, one-year To provide the proceeds for the Term Loan, GKDML entered into a loan agreement with Bank of America, N.A. on July 21, 2020 (“GKDML Loan”). The GKDML Loan was also repaid in March 2021, had substantially the same terms as the Term Loan and was personally guaranteed by Messrs. Knight and McKenney. GKDML, Mr. Knight and Mr. McKenney did not receive any consideration for providing the Term Loan or guaranty to the GKDML Loan; however, under the Term Loan, the Partnership reimbursed GKDML for all costs of the GKDML Loan.

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 2021
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: 2021 2020 Balance at January 1 $ 1,564,105 $ 1,452,734 Well additions 78,511 27,844 Accretion 42,253 40,608 Revisions - - Balance at June 30 $ 1,684,869 $ 1,521,186

Risk Management

Risk Management	6 Months Ended
	Jun. 30, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	Note 6. Risk Management Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. Periodically, the Partnership 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. 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 Partnership did not settle any contracts during the second quarter of 2021 and had no outstanding contracts at June 30, 2021. The following table presents the settlement gain (loss) of matured derivative instruments and non-cash mark-to-market gains for the periods presented. Six Months Ended Six Months Ended Settlement gain (loss) on matured derivatives $ (1,182,420 ) $ 257,040 Gain on mark-to-market of derivatives 602,760 183,850 Gain (loss) on derivatives, net $ (579,660 ) $ 440,890 Settlements on matured derivatives above reflect realized gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash) gains 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. 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 July 2023, as shown in the table below. The Partnership did not pay or receive a premium related to the costless collars, and the contracts will be settled monthly. Settlement Period Basis Product Volume Floor / Ceiling Prices ($) 07/2021 - 12/2021 NYMEX Oil (bbls) 192,000 50.00 / 83.50 01/2022 - 06/2022 NYMEX Oil (bbls) 173,000 50.00 / 80.00 07/2022 - 06/2023 NYMEX Oil (bbls) 307,000 50.00 / 72.00 08/2021 - 07/2022 Henry Hub Gas (MMbtu) 440,000 2.00 / 7.00 08/2022 - 07/2023 Henry Hub Gas (MMbtu) 360,000 2.00 / 4.50

Capital Contribution and Partne

Capital Contribution and Partners' Equity	6 Months Ended
	Jun. 30, 2021
Partners' Capital Notes [Abstract]
Partners' Capital Notes Disclosure [Text Block]	Note 7. Capital Contribution and Partners Equity At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990, 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 offerings 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%). 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 COVID-19 pandemic and the impact on the Partnership’s operating cash flows. The Partnership will accumulate 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 June 30, 2021, the unpaid Payout Accrual totaled $1.875616 per common unit, or approximately $36 million. As discussed in Note 4. Debt, the Partnership must meet certain conditions under the BF Loan Agreement before distributions to limited partners may resume. For the six months ended June 30, 2020, the Partnership paid distributions of $0.241644, or $4.6 million.

Related Parties

Related Parties	6 Months Ended
	Jun. 30, 2021
Related Party Transactions [Abstract]
Related Party Transactions Disclosure [Text Block]	Note 8. Related Parties The members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer, David S. McKenney, Chief Financial Officer, Anthony F. Keating, III, Co-Chief Operating Officer and Michael J. Mallick, Co-Chief Operating Officer. Mr. Knight and Mr. McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy Resources 12 GP, LLC, the general partner of Energy Resources 12, L.P. (“ER12”), a limited partnership that also invests in producing and non-producing oil and 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 six months ended June 30, 2021, approximately $30,000 and $62,000 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 June 30, 2021, approximately $30,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses on the consolidated balance sheets. For the three and six months ended June 30, 2020, approximately $98,000 and $190,000 of general and administrative costs were incurred by a member of the General Partner and have been reimbursed by the Partnership. On January 31, 2018, the Partnership entered into a cost sharing agreement with ER12 that gave ER12 access to the Partnership’s personnel and administrative resources, including accounting, asset management and other day-to-day management support. The cost sharing agreement reduced these accounting and asset management costs to the Partnership, as these shared day-to-day costs were split evenly between the two partnerships. The shared costs were based on actual costs incurred with no mark-up or profit to the Partnership. Any other direct third-party costs were paid by the party receiving the services. For the three and six months ended June 30, 2020, approximately $64,000 and $140,000, respectively, of expenses subject to the cost sharing agreement were incurred by ER12 and have been reimbursed to the Partnership. In October 2020, the cost sharing agreement was terminated by ER12, effective December 31, 2020. On December 1, 2020, the Partnership entered into an Administrative Services Agreement (the “ASA”) with Regional Energy Investors, L.P. d/b/a Regional Energy Management (the “Administrator”) and ER12, whereby the Administrator will provide administrative, operating and professional services necessary and useful to the Partnership. The Administrator will also assist the General Partner with the day-to-day operations of the Partnership. The ASA is 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 six months ended June 30, 2021, approximately $151,000 and $291,000, 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.

Accounting Policies, by Policy

Accounting Policies, by Policy (Policies)	6 Months Ended
	Jun. 30, 2021
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 2020 Annual Report on Form 10-K. Operating results for the three and six months ended June 30, 2021 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2021.
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.
Fair Value of Financial Instruments, Policy [Policy Text Block]	Fair Value of Other Financial Instruments The carrying value of the Partnership’s other financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and accrued expenses, reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments.
Earnings Per Share, Policy [Policy Text Block]	Net Income (Loss) Per Common Unit Basic net income (loss) per common unit is computed as net income (loss) divided by the weighted average number of common units outstanding during the period. Diluted net income (loss) 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 six months ended June 30, 2021 and 2020. 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 (loss) per common unit until such time that it is probable Payout (as discussed in Note 7) will occur.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2021
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: 2021 2020 Balance at January 1 $ 1,564,105 $ 1,452,734 Well additions 78,511 27,844 Accretion 42,253 40,608 Revisions - - Balance at June 30 $ 1,684,869 $ 1,521,186

Risk Management (Tables)

Risk Management (Tables)	6 Months Ended
	Jun. 30, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	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. 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 Partnership did not settle any contracts during the second quarter of 2021 and had no outstanding contracts at June 30, 2021. The following table presents the settlement gain (loss) of matured derivative instruments and non-cash mark-to-market gains for the periods presented. Six Months Ended Six Months Ended Settlement gain (loss) on matured derivatives $ (1,182,420 ) $ 257,040 Gain on mark-to-market of derivatives 602,760 183,850 Gain (loss) on derivatives, net $ (579,660 ) $ 440,890
Schedule of Derivative Instruments [Table Text Block]	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 July 2023, as shown in the table below. The Partnership did not pay or receive a premium related to the costless collars, and the contracts will be settled monthly. Settlement Period Basis Product Volume Floor / Ceiling Prices ($) 07/2021 - 12/2021 NYMEX Oil (bbls) 192,000 50.00 / 83.50 01/2022 - 06/2022 NYMEX Oil (bbls) 173,000 50.00 / 80.00 07/2022 - 06/2023 NYMEX Oil (bbls) 307,000 50.00 / 72.00 08/2021 - 07/2022 Henry Hub Gas (MMbtu) 440,000 2.00 / 7.00 08/2022 - 07/2023 Henry Hub Gas (MMbtu) 360,000 2.00 / 4.50

Partnership Organization (Detai

Partnership Organization (Details) shares in Millions	Dec. 18, 2015	Jul. 09, 2013USD ($)	Jun. 30, 2021	Apr. 24, 2017USD ($)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	11.00%		25.00%
Oil, Productive Well, Number of Wells, Net			256
Non-operated Wells in the Process of Drilling [Member]
Partnership Organization (Details) [Line Items]
Oil and Gas, Present Activity, Well in Process of Drilling			12
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			17.00%
Oil and Gas, Present Activity, Well in Process of Drilling			12

Oil and Natural Gas Investmen_2

Oil and Natural Gas Investments (Details)	Mar. 31, 2017	Jan. 11, 2017USD ($)	Dec. 18, 2015USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2021USD ($)	Jun. 30, 2021USD ($)	Dec. 31, 2018	Dec. 31, 2020	Dec. 31, 2019USD ($)	Jun. 30, 2021
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Wells Elected to Participate in Drilling										48
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number							6
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)									$ 7,800,000
Wells not yet Commenced Drilling						1
Sanish Field Located in Mountrail County, North Dakota [Member] | Acquisition No. 1 [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Business Combination, Consideration Transferred (in Dollars)			$ 159,600,000
Sanish Field Located in Mountrail County, North Dakota [Member] | Acquisition No. 2 [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net		11.00%
Business Combination, Consideration Transferred (in Dollars)		$ 128,500,000
Sanish Field Located in Mountrail County, North Dakota [Member] | Acquisition No. 3 [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] | Minimum [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					$ 8,000,000	$ 10
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)					$ 12,000,000	$ 12,000,000
Non-operated Completed Wells [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number								35
Working Interest						21.00%				21.00%
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			11.00%			25.00%
Oil, Productive Well, Number of Wells, Net						256				256
Non-operated Wells in the Process of Drilling [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Working Interest						17.00%				17.00%
Oil and Gas, Present Activity, Well in Process of Drilling						12				12
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						17.00%
Oil and Gas, Present Activity, Well in Process of Drilling						12				12
Whiting Petroleum [Member] | 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)						$ 64,000,000
Costs Incurred, Development Costs (in Dollars)						$ 53,000,000

Debt (Details)

Debt (Details) - USD ($)	May 13, 2021	Nov. 21, 2017	Jul. 31, 2020	Jun. 30, 2021
Debt (Details) [Line Items]
Debt Issuance Costs, Noncurrent, Net				$ 200,000
Line of Credit Facility, Fair Value of Amount Outstanding				$ 40,000,000
GKDML [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount			$ 15,000,000
Debt Instrument, Term			1 year
Revolving Credit Facility [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount	$ 60,000,000	$ 40,000,000
Debt Instrument, Maturity Date	Mar. 1, 2024	Jul. 31, 2021
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate	4.25%			4.00%
Long-term Line of Credit	$ 40,000,000			$ 40,000,000
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 Instrument, Fee Amount	$ 300,000
Debt Issuance Costs, Gross	$ 400,000
Debt Issuance Costs, Current, Net				$ 200,000
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 initially stipulated to be $1 million. Therefore, as of June 30, 2021, the borrowing base was $59 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 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 June 30, 2021
Prime Rate [Member] | Revolving Credit Facility [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
Debt Instrument, Minimum Interest Rate	4.00%
London Interbank Offered Rate (LIBOR) [Member] | GKDML [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate			2.00%
London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member] | GKDML [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate			0.00%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations - USD ($)	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Schedule of Asset Retirement Obligations [Abstract]
Balance	$ 1,564,105	$ 1,452,734
Well additions	78,511	27,844
Accretion	42,253	40,608
Revisions	0	0
Balance	$ 1,684,869	$ 1,521,186

Risk Management (Details)

Risk Management (Details)	6 Months Ended
	Jun. 30, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Discussion of Price Risk Derivative Risk Management Policy	Debt, the Partnership was required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 2020 through February 2021.

Risk Management (Details) - Sch

Risk Management (Details) - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Abstract]
Settlement gain (loss) on matured derivatives			$ (1,182,420)	$ 257,040
Gain on mark-to-market of derivatives			602,760	183,850
Gain (loss) on derivatives, net	$ 0	$ 0	$ (579,660)	$ 440,890

Risk Management (Details) - S_2

Risk Management (Details) - Schedule of Derivative Instruments	6 Months Ended
	Jun. 30, 2021$ / itembbl
Costless Collar Agreements #1 [Member]
Derivative [Line Items]
Basis	NYMEX
Product	Oil (bbls)
Volume | bbl	192,000
Floor Price	50
Ceiling Price	83.50
Costless Collar Agreements #2 [Member]
Derivative [Line Items]
Basis	NYMEX
Product	Oil (bbls)
Volume | bbl	173,000
Floor Price	50
Ceiling Price	80
Costless Collar Agreements #3 [Member]
Derivative [Line Items]
Basis	NYMEX
Product	Oil (bbls)
Volume | bbl	307,000
Floor Price	50
Ceiling Price	72
Costless Collar Agreements #4 [Member]
Derivative [Line Items]
Basis	Henry Hub
Product	Gas (MMbtu)
Volume | bbl	440,000
Floor Price	2
Ceiling Price	7
Costless Collar Agreements #5 [Member]
Derivative [Line Items]
Basis	Henry Hub
Product	Gas (MMbtu)
Volume | bbl	360,000
Floor Price	2
Ceiling Price	4.50

Capital Contribution and Part_2

Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions	Jul. 09, 2013	Mar. 31, 2020	Mar. 31, 2019	Jun. 30, 2021	Jun. 30, 2020	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				6.00%
Managing Dealer, Maximum Contingent Incentive Fee on Gross Proceeds, Percentage				4.00%
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%).
Annualized Rate of Retun			7.00%
Distribution at Payout to limited partner, per common unit (in Dollars per share)				$ 1,875,616
Distribution at Payout to limited partner				$ 36,000,000
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share)					$ 0.241644
Distribution Made to Limited Partner, Cash Distributions Paid		$ 4,584,826		$ 0	$ 4,584,826
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 ($)	Jan. 01, 2021	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
General Partner [Member]
Related Parties (Details) [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party		$ 30,000	$ 98,000	$ 62,000	$ 190,000
Due to Related Parties, Current		30,000		30,000
Affiliated Entity [Member]
Related Parties (Details) [Line Items]
Reimbursements From Related Party			$ 64,000		$ 140,000
Administrative Service Agreement [Member]
Related Parties (Details) [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party		$ 151,000		$ 291,000
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.