Energy 11 10-K 12 Mar 21 2020 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2020	Mar. 12, 2021	Jun. 30, 2020
Document Information Line Items
Entity Registrant Name	ENERGY 11, L.P.
Document Type	10-K
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		18,973,474
Entity Public Float			$ 0
Amendment Flag	false
Entity Central Index Key	0001581552
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Non-accelerated Filer
Entity Well-known Seasoned Issuer	No
Document Period End Date	Dec. 31, 2020
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Document Annual Report	true
Document Transition Report	false
Entity File Number	000-55615
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-3070515
Entity Address, Address Line One	120 W 3rd Street, Suite 220
Entity Address, City or Town	Fort Worth
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	76102
City Area Code	817
Local Phone Number	882-9192
Title of 12(g) Security	Common Units of Limited Partnership Interest
Entity Interactive Data Current	Yes
No Trading Symbol Flag	true

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Assets
Cash and cash equivalents	$ 1,608,301	$ 348,550
Restricted cash and cash equivalents	855,518	0
Oil, natural gas and natural gas liquids revenue receivable	5,890,971	5,857,926
Other current assets	257,524	284,652
Total Current Assets	8,612,314	6,491,128
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $75,765,289 and $53,186,165, respectively	323,200,183	326,758,636
Total Assets	331,812,497	333,249,764
Liabilities
Revolving credit facility	40,000,000	0
Affiliate term loan	6,000,000	0
Accounts payable and accrued expenses	3,299,810	19,877,209
Derivative liability	602,760	183,850
Total Current Liabilities	49,902,570	20,061,059
Revolving credit facility	0	24,000,000
Asset retirement obligations	1,564,105	1,452,734
Total Liabilities	51,466,675	45,513,793
Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)	280,347,549	287,737,698
General partner's interest	(1,727)	(1,727)
Class B Units (62,500 units issued and outstanding, respectively)	0	0
Total Partners’ Equity	280,345,822	287,735,971
Total Liabilities and Partners’ Equity	$ 331,812,497	$ 333,249,764

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Oil and natural gas properties, accumulated depreciation, depletion and amortization (in Dollars)	$ 75,765,289	$ 53,186,165
Limited partners' interest, common units issued	18,973,474	18,973,474
Limited partners' interest, common units outstanding	18,973,474	18,973,474
Class B Units, units issued	62,500	62,500
Class B Units, units outstanding	62,500	62,500

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenues
Oil	$ 31,686,698	$ 30,940,480
Natural gas	2,126,001	2,466,601
Natural gas liquids	2,709,377	2,612,521
Total revenue	36,522,076	36,019,602
Operating costs and expenses
Production expenses	9,839,539	9,873,634
Production taxes	3,075,056	2,861,995
General and administrative expenses	1,577,317	1,303,570
Depreciation, depletion, amortization and accretion	22,654,849	12,451,435
Total operating costs and expenses	37,146,761	26,490,634
Operating income (loss)	(624,685)	9,528,968
Loss on derivatives, net	(272,200)	(170,540)
Interest expense, net	(1,908,438)	(877,978)
Total other expense, net	(2,180,638)	(1,048,518)
Net income (loss)	$ (2,805,323)	$ 8,480,450
Basic and diluted net income (loss) per common unit (in Dollars per share)	$ (0.15)	$ 0.45
Weighted average common units outstanding - basic and diluted (in Shares)	18,973,474	18,973,474

Consolidated Statements of Part

Consolidated Statements of Partners' Equity - USD ($)	Total	Limited Partner [Member]	General Partner [Member]	Capital Unit, Class B [Member]Member Units [Member]
Balance at Dec. 31, 2018	$ 305,745,602	$ 305,747,329	$ (1,727)
Balance (in Shares) at Dec. 31, 2018		18,973,474		62,500
Distributions declared and paid to common units	(26,490,081)	$ (26,490,081)
Net income (loss)	8,480,450	8,480,450
Balance at Dec. 31, 2019	$ 287,735,971	$ 287,737,698	(1,727)
Balance (in Shares) at Dec. 31, 2019	18,973,474	18,973,474		62,500
Distributions declared and paid to common units	$ (4,584,826)	$ (4,584,826)
Net income (loss)	(2,805,323)	(2,805,323)
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

Consolidated Statements of Pa_2

Consolidated Statements of Partners' Equity (Parentheticals) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Capital Unit, Class B [Member] | Member Units [Member]
Distributions declared and paid to common units, per unit	$ 0.241644	$ 1.396164

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Cash flow from operating activities:
Net income	$ (2,805,323)	$ 8,480,450
Depreciation, depletion, amortization and accretion	22,654,849	12,451,435
(Gain) / loss on mark-to-market of derivatives	418,910	183,850
Non-cash expenses, net	113,140	47,492
Oil, natural gas and natural gas liquids revenue receivable	(33,045)	411,316
Other current assets	23,609	(11,410)
Accounts payable and accrued expenses	321,085	(885,454)
Net cash flow provided by operating activities	20,693,225	20,677,679
Cash flow from investing activities:
Additions to oil and natural gas properties	(35,876,529)	(7,609,391)
Net cash flow used in investing activities	(35,876,529)	(7,609,391)
Cash flow from financing activities:
Cash paid for loan costs	(116,601)	(114,984)
Proceeds from revolving credit facility	16,000,000	10,200,000
Proceeds from affiliate term loan	15,000,000	0
Payments on affiliate term loan	(9,000,000)	0
Distributions paid to limited partners	(4,584,826)	(26,490,081)
Net cash flow (used in) provided by financing activities	17,298,573	(16,405,065)
Decrease in cash and cash equivalents	2,115,269	(3,336,777)
Cash and cash equivalents, beginning of period	348,550	3,685,327
Cash and cash equivalents, end of period	2,463,819	348,550
Interest paid	1,837,470	849,322
Accrued capital expenditures related to additions to oil and natural gas properties	$ 1,531,828	$ 18,423,332

Partnership Organization

Partnership Organization	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]	Note 1. Partnership Organization Energy 11, L.P. (together with its wholly-owned subsidiary, the “Partnership”) is a Delaware limited partnership formed to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties. The initial capitalization of the Partnership of $1,000 occurred on July 9, 2013. The Partnership completed its best-efforts offering on April 24, 2017 with a total of approximately 19 million common units sold for gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million. As of December 31, 2020, the Partnership owns an approximate 25% non-operated working interest in 243 producing wells, an estimated approximate 18% non-operated working interest in 21 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. COVID-19, Demand, Liquidity and Going Concern Considerations During 2019 and the first quarter of 2020, the Partnership elected to participate in the drilling and completion of 43 new wells (“Drilling Program”), primarily administered by Whiting, at an estimated cost of approximately $62 million to the Partnership. Through the first quarter of 2020, approximately 14 wells under the Drilling Program had been completed and production from additional wells to be completed under the Drilling Program were expected to enhance the Partnership’s operating performance throughout 2020, providing incremental cash flow from operations to fund the Partnership’s investment in its undrilled acreage. In December 2019, China reported an outbreak of a novel coronavirus (“COVID-19”) in its Wuhan province. COVID-19 rapidly spread worldwide, forcing governments around the world to take drastic measures to halt the outbreak. These measures included significant restrictions on travel, forced quarantines, stay-at-home requirements and the closure of businesses in many industries, creating extreme volatility in capital markets and the global economy. On March 11, 2020, the World Health Organization declared COVID-19 a pandemic, and on March 13, 2020, the United States declared a national emergency with respect to COVID-19. Because of COVID-19’s impact to the global economy, demand for oil, natural gas and natural gas liquids (“NGL”) substantially declined in March 2020 and remained depressed through the remainder of 2020. This reduction in demand compounded an existing excess in supply of oil and natural gas, as the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia could not agree on daily production output of crude oil in March 2020. As a result, Russia announced its intention to increase production, and Saudi Arabia immediately countered with announced reductions to export prices. These factors led to oil prices falling in March 2020 and to 20-year lows in April 2020. In response, the General Partner approved the suspension of distributions to limited partners of the Partnership in March 2020. Operators within the United States altered drilling programs and the related forecasted capital expenditures for those programs, and implemented other cost-saving measures, such as curtailing production or shutting in producing wells, during the second quarter of 2020. The financial impact of COVID-19 forced Whiting and certain of its subsidiaries to declare bankruptcy under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas on April 1, 2020. Whiting then subsequently suspended the Drilling Program. Even though Whiting completed its financial restructuring and emerged from bankruptcy protection in September 2020, Whiting has yet to resume the Drilling Program. At December 31, 2019, the Partnership had approximately $16 million available under its $40 million revolving credit facility (“Credit Facility”); the Partnership used that remaining availability in the first quarter of 2020 to partially fund capital expenditures within the Drilling Program. At the end of the first quarter of 2020, the Partnership had approximately $21 million in accrued capital expenditures to Whiting. As a result, the Partnership was not in compliance with certain covenants under its Credit Facility as of March 31, 2020. In July 2020, the Partnership entered into a letter agreement (“Letter Agreement”) with its lending group of its Credit Facility that, among other items, waived the non-compliance of certain covenants under the Credit Facility, accelerated the maturity date of the Credit Facility from September 30, 2022 to July 31, 2021 and permitted a term loan with an affiliate. Subsequently, the Partnership entered into a loan agreement for a one-year, $15 million term loan (“Affiliate Loan”), and proceeds from the Affiliate Loan plus cash on hand were used to pay its outstanding capital expenditures due to Whiting. As of December 31, 2020, the Partnership’s outstanding debt obligations total $46 million and are current on the Partnership’s consolidated balance sheet as both the Credit Facility and Affiliate Loan now mature in July 2021. The Partnership’s ability to continue as a going concern is dependent on several factors including, but not limited to, (i) the Partnership’s ability to comply with its obligations under its loan agreements; (ii) refinancing its existing debt and/or securing additional capital; (iii) an increase in demand for oil and natural gas as the global economy recovers from the effects of the COVID-19 pandemic and the existing oversupply of oil in the United States; and (iv) an increase in oil and natural gas market prices, which will improve the Partnership’s cash flow generated from operations. The Partnership can provide no assurance that it will be able to achieve any of these objectives. Refinancing its existing debt or securing additional capital may not be available on favorable terms to the Partnership, if it is available at all. There can be no assurance that economic activity and oil and natural gas market conditions, including commodity prices, will fully return and stabilize at pre-COVID-19 levels, or that the Partnership will be able to meet its operational obligations. If the Partnership is unable to refinance or repay its debt obligations or is unable to meet its operational obligations, the Partnership could be required to liquidate certain of its assets used for collateral to satisfy these obligations, which create the substantial doubt that exists about the ability of the Partnership to continue as a going concern for one year after the date these financial statements are issued. The financial statements included herein do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classifications of liabilities that may result from the possible inability of the Partnership to continue as a going concern.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	Note 2. Summary of Significant Accounting Policies Basis of Presentation The accompanying consolidated financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”). The consolidated financial statements include the accounts of the Partnership and its subsidiaries. Cash, Cash Equivalents and Restricted Cash and Cash Equivalents Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. Restricted cash as of December 31, 2020 of $0.9 million represents required collateral under the Letter Agreement (see Note 4. Debt) with the Partnership’s lender. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits. Property and Depreciation, Depletion and Amortization The Partnership accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities. No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties. The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions. Impairment The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of the properties exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an impairment expense equal to the difference between the carrying value and the fair value of the properties, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. The underlying commodity prices used in the determination of our estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment. Accounts Receivable and Concentration of Credit Risk Substantially all the Partnership’s accounts receivable is due from the operators of the Partnership’s oil and natural gas properties in North Dakota (the operators have accounts receivable from purchasers of oil, natural gas and NGLs). Oil, natural gas and NGL sales receivables are generally unsecured. This industry and location concentration has the potential to impact the Partnership’s overall exposure to credit risk, in that the purchasers of the Partnership’s oil, natural gas and NGLs and the operators of the properties the Partnership has an interest in may be similarly affected by changes in economic, industry or other conditions. At December 31, 2020, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible. For the year ended December 31, 2020, the Partnership’s oil, natural gas and NGL sales were through four operators. Whiting is the operator of 98% of the Partnership’s producing properties. All oil and natural gas producing activities of the Partnership are in North Dakota and represent substantially all of the business activities of the Partnership. Asset Retirement Obligation The Partnership has significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. The removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance. The following table shows the activity for the years ended December 31, 2020 and 2019, relating to the Partnership’s asset retirement obligations: Balance as of December 31, 2018 $ 1,294,067 Well additions 87,019 Accretion 71,648 Revisions in estimated cash flows - Balance as of December 31, 2019 $ 1,452,734 Well additions 35,647 Accretion 75,724 Revisions in estimated cash flows - Balance as of December 31, 2020 $ 1,564,105 Income Tax The Partnership is taxed as a partnership for federal and state income tax purposes. No provision for income taxes has been recorded since the liability for such taxes is that of each of the partners rather than the Partnership. The Partnership’s income tax returns are subject to examination by the federal and state taxing authorities, and changes, if any, could adjust the individual income tax of the partners. The Partnership has evaluated whether any material tax position taken will more likely than not be sustained upon examination by the appropriate taxing authority and believes that all such material tax positions taken are supportable by existing laws and related interpretations. Environmental Costs As the Partnership is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Partnership does not believe the existence of current environmental laws or interpretations thereof will materially hinder or adversely affect the Partnership’s business operations; however, there can be no assurances of future effects on the Partnership of new laws or interpretations thereof. Since the Partnership does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with the Partnership being responsible for its proportionate share of the costs involved. Environmental liabilities are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At December 31, 2020 and 2019, there were no such costs accrued. Use of Estimates Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Of these estimates and assumptions, management considers the estimation of oil, natural gas and NGL reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as depreciation, depletion and amortization (“DD&A”) and impairment calculations. On an annual basis, the Partnership’s independent consulting petroleum engineer, with assistance from the Partnership, prepares estimates of oil, natural gas and NGL reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the Securities and Exchange Commission (“SEC”), the reserve estimates were based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period excluding escalations based upon future conditions. For impairment purposes, projected NYMEX forward strip prices for oil, natural gas and NGL as estimated by management are used. Oil, natural gas and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future oil, natural gas and NGL pricing assumptions are used by management to prepare estimates of oil, natural gas and NGL reserves used in formulating management’s overall operating decisions. The Partnership does not operate its oil and natural gas properties and, therefore, receives actual oil, natural gas and NGL sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case, the most current available production data is gathered from the appropriate operators, and oil, natural gas and NGL index prices local to each well are used to estimate the accrual of revenue on these wells. The oil, natural gas and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, natural gas and NGLs. These variables could lead to an over or under accrual of oil, natural gas and NGL sales at the end of any particular quarter. However, the Partnership adjusts the estimated accruals of revenue to actual production in the period actual production is determined. Revenue Recognition The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Oil, natural gas and natural gas liquids revenue receivable in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers. 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 (loss), partners’ equity or cash flows. 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 unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the years ended December 31, 2020 and 2019. As a result, basic and diluted outstanding common units were the same. The Class B Units and Incentive Distribution Rights are not included in net income (loss) per common unit until such time that it is probable Payout (as discussed in Note 7) would occur. Recently Adopted Accounting Standards In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-04, Reference Rate Reform (Topic 848), which provides optional guidance through December 31, 2022 to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments in ASU No. 2020-04 apply to contract modifications that replace a reference rate affected by reference rate reform, providing optional expedients regarding the measurement of hedge effectiveness in hedging relationships that have been modified to replace a reference rate. While the guidance in ASU No. 2020-04 became effective upon issuance, the provisions of the ASU did not have a material impact on the Partnership’s consolidated financial statements and related disclosures as of December 31, 2020.

Oil and Gas Investments

Oil and Gas Investments	12 Months Ended
	Dec. 31, 2020
Oil and Gas Property [Abstract]
Oil and Gas Properties [Text Block]	Note 3. Oil and Gas Investments On December 18, 2015, the Partnership completed its first purchase in the Sanish field, acquiring an approximate 11% non-operated working interest in the Sanish Field Assets for approximately $159.6 million. On January 11, 2017, the Partnership closed on its second purchase in the Sanish field, acquiring an additional approximate 11% non-operated working interest in the Sanish Field Assets for approximately $128.5 million. On March 31, 2017, the Partnership closed on its third purchase in the Sanish field, acquiring an additional approximate average 10.5% non-operated working interest in 82 of the Partnership’s then 216 existing producing wells and 150 of the Partnership’s then 253 future development locations in the Sanish Field Assets for approximately $52.4 million. 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. During 2019 and the first quarter of 2020, the Partnership elected to participate in the Drilling Program primarily administered by Whiting, which includes the drilling and completion of 43 new wells in the Sanish field. Twenty-two (22) of 43 wells have been completed and were producing at December 31, 2020; the Partnership has an approximate non-operated working interest of 23% in these 22 wells. The Partnership has an estimated approximate non-operated working interest of 18% in the remaining 21 wells that are in-process as of December 31, 2020. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 43 wells is approximately $62 million, of which approximately $42 million was incurred as of December 31, 2020. Whiting suspended the Drilling Program during the second quarter of 2020 in response to the significant reduction in demand for oil caused by COVID-19 and the oversupply of oil in the United States. The timing for completion of a portion or all of the in-process wells within the Drilling Program is dependent upon several factors, including an increase in commodity pricing and available capital. The Partnership estimates it may incur approximately $12 to $15 million in capital expenditures, if Whiting resumes its Drilling Program, in 2021. However, low commodity prices, market supply and demand imbalances and Whiting’s performance after emerging from bankruptcy protection in September 2020 make it difficult to predict the amount and timing of capital expenditures for 2021, and estimated capital expenditures could be significantly different from amounts actually invested. Evaluation for Potential Impairment of Oil and Natural Gas Investments The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. The Partnership considered the declines in the current and forecasted operating cash flows resulting from COVID-19 and sustained lower commodity prices to be potential indicators of impairment and, as a result, performed a test of recoverability for the Sanish Field Assets. Estimated future net cash flows calculated in the recoverability test were based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. The underlying commodity prices used in the determination of the Partnership’s estimated future net cash flows were based on NYMEX forward strip prices as of January 1, 2021, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believed will impact realizable prices. Future operating cost estimates were based on actual historical costs of the Sanish Field Assets. The Partnership’s recoverability analyses did not identify any impairment losses as of December 31, 2020. If current macro-economic conditions continue or worsen, the carrying value of the Partnership’s oil and natural gas properties may not be recoverable and impairment losses could be recorded in future periods.

Debt

Debt	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
Debt Disclosure [Text Block]	Note 4. Debt Revolving Credit Facility On November 21, 2017, the Partnership, as the borrower, entered into a loan agreement (the “Loan Agreement”) between and among the Partnership and Simmons Bank, as administrative agent and the lenders party thereto (the “Lender”), which provided for a revolving credit facility with an approved initial commitment amount of $20 million, subject to borrowing base restrictions. The maturity date was November 21, 2019. Effective September 30, 2019, the Partnership entered into an amendment and restatement of the Loan Agreement (the “Amended Loan Agreement”) with the Lender, which provided for the Credit Facility with an approved initial commitment of $40 million (the “Revolver Commitment Amount”), subject to borrowing base restrictions. The terms of the Amended Loan Agreement were generally similar to the Partnership’s existing revolving credit facility and included the following: (i) a maturity date of September 30, 2022; (ii) subject to certain exceptions, an interest rate, which did not change from the existing revolving credit facility, equal to the London Inter-Bank Offered Rate (LIBOR) plus a margin ranging from 2.50% to 3.50%, depending upon the Partnership’s borrowing base utilization, as calculated under the terms of the Amended Loan Agreement; (iii) an increase to the borrowing base from $30 million to an initially stipulated $40 million; and (iv) an increase to the mortgage and lenders’ first lien position from 80% to 90% of the Partnership’s owned producing oil and natural gas properties. At closing of the Amended Loan Agreement in October 2019, the Partnership paid an origination fee of 0.45% on the change in Revolver Commitment Amount of the Credit Facility (increase from $20 million on previous credit facility to $40 million under revised Credit Facility, or $20 million), or $90,000. The Partnership is also required to pay an unused facility fee of 0.50% on the unused portion of the Revolver Commitment Amount, based on the amount of borrowings outstanding during a quarter. On July 21, 2020, the Partnership entered into the Letter Agreement with the Lender that amended and modified the Amended Loan Agreement. The modifications to the Amended Loan Agreement include, among other items, the following: - Maturity date was changed from September 30, 2022 to July 31, 2021; - Interest rate was changed to the prime rate plus 1.00%, with an interest rate floor of 4.00% (an increase of 50 basis points from the rate prior to the Letter Agreement); - Any future Partnership distributions to limited partners require lender approval; - The definition of current ratio excludes the Affiliate Loan (discussed below) from the definition of liabilities; and - As additional collateral for the loan, the Partnership established and funded a bank account with its lender in the amount of $1.6 million, to be used for interest payments until maturity (the balance of this collateral bank account at December 31, 2020 was approximately $0.9 million and is included in Restricted cash and cash equivalents on the Partnership’s December 31, 2020 consolidated balance sheet). Also, under the Letter Agreement, the Partnership is required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and natural gas sales. The risk management program must cover at least 80% of the Partnership’s projected total production of oil and natural gas for the period from August 31, 2020 until the next borrowing base redetermination date (first quarter of 2021). See more information on the Partnership’s hedging program in Note 6. Risk Management. In addition to the modification of certain terms of the Credit Facility, the Letter Agreement waived the defaults by the Partnership that existed prior to signing the Letter Agreement, including not meeting the current ratio covenant as of March 31, 2020, the Partnership not filing its first quarter financial statements within 60 days of March 31, 2020 and the non-payment by the Partnership of amounts due to Whiting. The Letter Agreement also waived the Partnership’s calculation of the current ratio covenant at June 30, 2020. The Letter Agreement allowed for the Affiliate Loan, discussed below, and permitted payments under the Affiliate Loan if certain conditions were met. In consideration for the modifications, amendments and waivers described above to the Amended Loan Agreement, the Letter Agreement required an amendment fee to the Lender of $40,000. The Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants, each as defined in the Amended Loan Agreement, include: ● A maximum ratio of funded debt to trailing 12-month EBITDAX of 3.50 to 1.00 ● A minimum ratio of current assets to current liabilities of 1.00 to 1.00 (“Current Ratio”) ● A minimum ratio of EBITDAX to cash interest expense of 2.50 to 1.00 for trailing 12-month period The Partnership was in compliance with its applicable covenants at December 31, 2020. If the Partnership is not in compliance with its covenants in future periods, it may not be able to obtain waivers and the outstanding balance under the Credit Facility may become due on demand at that time. At December 31, 2020, the outstanding balance on the Credit Facility was $40 million, and the interest rate for the Credit Facility was 4.25%. As of December 31, 2020 and 2019, the outstanding balance on the Credit Facility was $40 million and $24.0 million, respectively, which approximates its fair market value. The Partnership estimated the fair value of its Credit Facility by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity. Term Loan from Affiliate On July 21, 2020, the Partnership, as borrower, entered into a loan agreement with GKDML, LLC (“GKDML”), which provides 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 has substantially the same terms as the Term Loan and is personally guaranteed by Messrs. Knight and McKenney. GKDML, Mr. Knight and Mr. McKenney have not and will not receive any consideration for providing the Term Loan or guaranty to the GKDML Loan; however, under the Term Loan, the Partnership is required to reimburse GKDML for all costs of the GKDML Loan. The Term Loan may be prepaid at any time with no penalty and in any amount, but any amounts repaid may not be reborrowed.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value Disclosures [Text Block]	Note 5. Fair Value of Financial Instruments The Partnership follows authoritative guidance related to fair value measurement and disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement using market participant assumptions at the measurement date. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The three levels are defined as follows: ● Level 1: Quoted prices in active markets for identical assets ● Level 2: Significant other observable inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, either directly or indirectly, for substantially the full term of the financial instrument ● Level 3: Significant unobservable inputs The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and the consideration of factors specific to the asset or liability. The Partnership’s policy is to recognize transfers in or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Partnership has consistently applied the valuation techniques discussed above for all periods presented. During the years ended December 31, 2020 and 2019, there were no transfers in or out of Level 1, Level 2, or Level 3 assets and liabilities measured on a recurring basis. As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2020 and 2019. Fair Value Measurements at December 31, 2020 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current liabilities $ - $ (602,760 ) $ - Total $ - $ (602,760 ) $ - Fair Value Measurements at December 31, 2019 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current liabilities $ - $ (183,850 ) $ - Total $ - $ (183,850 ) $ - 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 sheets as Derivative Liability at December 31, 2020 and 2019. See additional detail in Note 6. Risk Management. Fair Value of Other Financial Instruments The carrying value of the Partnership’s cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments. In addition, see Note 4. Debt for the fair value discussion on the Partnership’s debt.

Risk Management

Risk Management	12 Months Ended
	Dec. 31, 2020
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. The Partnership settled three derivative contracts during the first quarter of 2020, and in accordance with the Letter Agreement discussed in Note 4. Debt, the Partnership is 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 31, 2020 until the next borrowing base redetermination date (first quarter of 2021). In August 2020, the Partnership established its risk management program by entering into costless collar derivative contracts for future oil and natural gas produced by the Sanish Field Assets during the period from August 2020 through February 2021. All derivative instruments are recorded on the Partnership’s balance sheet as assets or liabilities measured at fair value. As of December 31, 2020 and 2019, the Partnership’s derivative instruments were in a loss position; therefore, current liabilities of approximately $0.6 million and $0.2 million, respectively, which approximate fair value, were recognized as Derivative Liability on the Partnership’s consolidated balance sheets. The Partnership determined the estimated fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets and quotes from third parties, among other things. The Partnership also performed an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Partnership assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually-required payments. Additionally, the Partnership considered that the counterparty is of substantial credit quality and had the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. See additional discussion above in Note 5. Fair Value of Financial Instruments. The Partnership has not designated its derivative instruments as hedges for accounting purposes and has not entered 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 settlements of matured derivative instruments and non-cash losses on open derivative instruments for the periods presented. Settlements on matured derivatives below reflect a realized net gain 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) losses below represent the change in fair value of derivative instruments which were held at period-end. Year Ended December 31, 2020 Year Ended December 31, 2019 Settlements on matured derivatives, net $ 146,710 $ 13,310 Loss on mark-to-market of derivatives, net (418,910 ) (183,850 ) Loss on derivatives, net $ (272,200 ) $ (170,540 ) 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, and the contracts are settled monthly. The following table reflects the open costless collar derivative instruments as of December 31, 2020. Settlement Period Basis Product Volume Floor / Ceiling Prices ($) Fair Value of Asset (Liability) at 01/2021 - 02/2021 NYMEX Oil (bbls) 30,000 37.50 / 44.50 $ (174,600 ) 01/2021 - 02/2021 NYMEX Oil (bbls) 30,000 38.00 / 44.25 (184,350 ) 01/2021 - 02/2021 NYMEX Oil (bbls) 30,000 38.00 / 44.00 (194,850 ) 01/2021 - 02/2021 NYMEX Oil (bbls) 15,000 38.00 / 44.50 (67,590 ) 01/2021 - 02/2021 Henry Hub Gas (MMBtu) 120,000 2.50 / 3.05 18,630 $ (602,760 ) The Partnership’s outstanding derivative instrument is covered by an International Swap Dealers Association Master Agreement (“ISDA”) entered into with the counterparty. The ISDA may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately. The Partnership has netting arrangements with the counterparty that provide for offsetting payables against receivables from separate derivative instruments. The use of derivative instruments involves the risk that the Partnership’s counterparty will be unable to meet the financial terms of such instruments.

Capital Contribution and Partne

Capital Contribution and Partners' Equity	12 Months Ended
	Dec. 31, 2020
Partners' Capital Notes [Abstract]
Partners' Capital Notes Disclosure [Text Block]	Note 7. Capital Contribution and Partners Equity At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering the organizational limited partner withdrew its initial capital contribution of $990, the General Partner received Incentive Distribution Rights (defined below), and was reimbursed for its documented third-party out-of-pocket expenses incurred in organizing the Partnership and offering the common units. The Partnership completed its best-efforts offering of common units on April 24, 2017. As of the conclusion of the offering on April 24, 2017, the Partnership had completed the sale of approximately 19.0 million common units for total gross proceeds of $374.2 million and proceeds net of offerings costs of $349.6 million. Under the agreement with the Dealer Manager, the Dealer Manager received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager will also be paid a contingent incentive fee, which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold based on the performance of the Partnership. Based on the common units sold in the best-efforts offering, the total contingent fee is approximately $15.0 million. Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units. Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights (owned by the General Partner), the Class B units or the contingent, incentive payments to the Dealer Manager, until Payout occurs. The Partnership Agreement provides that Payout occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount. All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows: ● First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement; ● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%). All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above. In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to market volatility resulting from COVID-19 and the impact on the Partnership’s operating cash flows. The Partnership has accumulated and will continue to 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 discussed in Note 4. Debt and pursuant to the Letter Agreement, the Partnership is not permitted to pay distributions without lender approval. As of December 31, 2020, the unpaid Payout Accrual totaled $1.181370 per common unit, or approximately $22 million. For the year ended December 31, 2020, the Partnership paid distributions of $0.241644 per common unit, or $4.6 million. For the year ended December 31, 2019, the Partnership paid distributions of $1.396164 per common unit or $26.5 million.

Related Parties

Related Parties	12 Months Ended
	Dec. 31, 2020
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 years ended December 31, 2020 and 2019, approximately $381,000 and $319,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At December 31, 2020 and 2019, approximately $52,000 and $83,000, respectively, was due to/from members of the General Partner; these costs are included in Accounts payable and accrued expenses in the consolidated balance sheets. 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. The compensation due to Clifford J. Merritt, President of the General Partner, was also a shared cost between the Partnership and ER12 for the years ended December 31, 2020 and 2019. The Partnership leases office space in Oklahoma City, Oklahoma on a month-to-month basis from an affiliate of the General Partner; because the office space is shared between the Partnership and ER12, the monthly payments of $8,537 made in 2019 and 2020 were evenly split between the two partnerships in accordance with the cost sharing agreement. For the years ended December 31, 2020 and 2019, approximately $268,000 and $285,000, respectively, of expenses subject to the cost sharing agreement were incurred by the Partnership and have been reimbursed by ER12. At December 31, 2019, approximately $85,000 was due to the Partnership from ER12 and is included in Other current assets in the consolidated balance sheet. 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. 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. 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. The Administrator will also assist Energy Resources 12 GP, LLC, the general partner of ER12 (“ER12’s General Partner”), with the day-to-day operations of ER12. ER12 currently pays ER12’s General Partner an annual management fee of 0.5% of the total gross equity proceeds raised by ER12 in its best-efforts offering. Under the ASA, ER12’s General Partner will pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. This fee is only applicable to ER12 and does not apply to the Partnership. The Administrator is owned by entities that are controlled by Messrs. Keating and Mallick. E11 Incentive Holdings, LLC (“Incentive Holdings”) was the owner of all Class B units outstanding (62,500) as of March 31, 2017. During the second quarter of 2017, Incentive Holdings transferred substantially all of its assets; on April 5, 2017, Incentive Holdings transferred 18,125 of the 62,500 Class B units to E11 Incentive Carry Vehicle, LLC, an affiliate of Incentive Holdings, for de minimis consideration. On April 6, 2017, the remaining 44,375 Class B units were acquired by Regional Energy Incentives, LP in exchange for approximately $98,000. Regional Energy Incentives, LP is owned by entities that are controlled by Messrs. Keating, Mallick and McKenney. The Class B units entitle the holder to certain distribution rights after Payout, as described in Note 7. Capital Contribution and Partners’ Equity.

Supplementary Information on Oi

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)	12 Months Ended
	Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Gas Exploration and Production Industries Disclosures [Text Block]	Note 9. Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) Aggregate Capitalized Costs The aggregate amount of capitalized costs of oil, natural gas and NGL properties and related accumulated depreciation, depletion and amortization as of December 31, 2020 and 2019 is as follows: 2020 2019 Producing properties $ 229,234,243 $ 217,356,850 Non-producing 169,731,229 162,587,950 398,965,472 379,944,800 Accumulated depreciation, depletion and amortization (75,765,289 ) (53,186,164 ) Net capitalized costs $ 323,200,183 $ 326,758,636 Costs Incurred For the years ended December 31, 2020 and 2019, the Partnership incurred the following costs in oil and natural gas producing activities: 2020 2019 Development costs $ 19,020,672 $ 26,021,438 Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves The following unaudited information regarding the Partnership’s oil, natural gas and NGL reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB. Proved oil and natural gas reserves are those quantities of oil, natural gas and NGLs which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. The independent consulting petroleum engineering firm of Pinnacle Energy of Oklahoma City, OK, prepared estimates of the Partnership’s oil, natural gas and NGL reserves as of December 31, 2020, 2019 and 2018. The Partnership’s net proved oil, NGL and natural gas reserves, all of which are located in the contiguous United States, as of December 31, 2020, 2019 and 2018, have been estimated by the Partnership’s independent consulting petroleum engineering firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principles and techniques that are in accordance with SEC rules and regulations along with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history. For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate. Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available. “Revisions of previous estimates” in the table below represent changes in previous reserve estimates, either upward or downward, resulting from a change in economic factors, such as commodity prices, operating costs or development costs, or resulting from information obtained from the Partnership’s production history. The rollforward of net quantities of proved developed and undeveloped oil, natural gas and NGL reserves are summarized as follows: Proved Reserves Oil Natural Gas NGLs (Bbls) (Mcf) (Bbls) Total (BOE) December 31, 2018 19,557,273 23,040,536 3,987,383 27,384,745 Acquisition - - - - Extensions, discoveries and other additions (1) 1,101,604 1,167,115 163,884 1,460,007 Revisions of previous estimates (2) (1,213,675 ) 456,464 (710,685 ) (1,848,283 ) Production (624,079 ) (888,208 ) (126,516 ) (898,629 ) December 31, 2019 18,821,123 23,775,907 3,314,066 26,097,840 Acquisition - - - - Extensions, discoveries and other additions - - - - Revisions of previous estimates (3) (3,391,968 ) (5,920,203 ) (527,522 ) (4,906,190 ) Production (1,014,980 ) (1,057,474 ) (158,050 ) (1,349,276 ) December 31, 2020 14,414,175 16,798,230 2,628,494 19,842,374 (1) In 2019, extensions, discoveries and other additions of 1,460 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator in the Sanish field. (2) Revisions to previous estimates decreased proved reserves by a net amount of 1,848 MBOE. These revisions result from 1,216 MBOE of downward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2019 to December 31, 2018, 511 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2019 to December 31, 2018, and 121 MBOE of downward adjustments attributable to changes in the future drill schedule. (3) Revisions to previous estimates decreased proved reserves by a net amount of 4,906 MBOE. These revisions result from 5,409 MBOE of downward adjustments attributable to changes in the future drill schedule and 1,619 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019, offset by 2,122 of upward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019. In accordance with SEC Regulation S-X, Rule 4-10, as amended, the Partnership uses the 12-month average price calculated as the unweighted arithmetic average of the spot price on the first day of each month within the 12-month period prior to the end of the reporting period. The oil and natural gas prices used in computing the Partnership’s reserves as of December 31, 2020 were $39.57 per barrel of oil and $1.99 per MMcf of natural gas, before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Partnership’s reserves as of December 31, 2020 were $32.08 per barrel of oil, $(0.55) per MMcf of natural gas and $5.54 per barrel of NGL. The oil and natural gas prices used in computing the Partnership’s reserves as of December 31, 2019 were $55.69 per barrel of oil and $2.58 per MMcf of natural gas, before price differentials. Including the effect of price differential adjustments, the average realized prices used in computing the Partnership’s reserves as of December 31, 2019 were $47.70 per barrel of oil, $(0.03) per MMcf of natural gas and $8.91 per barrel of NGL. Net quantities of proved developed and proved undeveloped reserves at December 31, 2020, 2019 and 2018 are summarized in the table below. The net quantities classified as proved developed reserves at December 31, 2019 include four proved developed non-producing (“PDNP”) wells converted to producing, as these wells were substantially complete at December 31, 2019 and the costs to bring to production were relatively minor. Oil Natural Gas NGLs (Bbls) (Mcf) (Bbls) Total (BOE) Proved developed reserves: December 31, 2018 9,195,064 12,333,784 2,134,478 13,385,173 December 31, 2019 9,771,596 14,232,526 1,974,006 14,117,690 December 31, 2020 10,688,857 12,992,674 2,029,392 14,883,695 Proved undeveloped reserves: December 31, 2018 10,362,209 10,706,752 1,852,905 13,999,573 December 31, 2019 9,049,527 9,543,381 1,340,060 11,980,151 December 31, 2020 3,725,318 3,805,556 599,102 4,958,679 The following details the changes in proved undeveloped reserves (PUD) for 2019 and 2020: BOE Proved undeveloped reserves, December 31, 2018 13,999,573 Revisions of previous estimates (1) (365,470 ) Extensions, discoveries and other additions (2) 1,460,007 Conversion to proved developed reserves (3) (3,113,959 ) Proved undeveloped reserves acquired - Proved undeveloped reserves, December 31, 2019 11,980,151 Revisions of previous estimates (4) (5,501,947 ) Extensions, discoveries and other additions - Conversion to proved developed reserves (5) (1,519,525 ) Proved undeveloped reserves acquired - Proved undeveloped reserves, December 31, 2019 4,958,679 (1) The annual review of the PUDs resulted in a negative revision of approximately 365 MBOE. This revision was the result of 244 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2018 to December 31, 2019 and 121 MBOE of downward adjustments attributable to changes in the future drill schedule. (2) In 2019, extensions, discoveries and other additions of 1,460 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator in the Sanish field. (3) The Partnership completed 11 new wells during 2019. In addition, the Partnership had four wells at December 31, 2019 classified as PDNP that were substantially complete and the costs to bring to production were relatively minor. Therefore, the Partnership converted the 11 completed wells and the four PDNP wells from PUD to proved developed reserves, which resulted in a downward adjustment to PUDs of 3,114 MBOE. (4) The annual review of the PUDs resulted in a negative revision of approximately 5,502 MBOE. This revision was the result of 5,409 MBOE of downward adjustments attributable to changes in the future drill schedule, 121 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2020 and December 31, 2019, and 28 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2020 to December 31, 2019. (5) The Partnership completed 11 new wells during 2020. As discussed in (3) above, the Partnership already converted four of these 11 wells from PUD to proved developed reserves at December 31, 2019 because they were substantially complete and the costs to bring to production were relatively minor. Therefore, the Partnership converted the other 7 completed wells to proved developed reserves during 2020, which resulted in a downward adjustment to PUDs of 1,520 MBOE. Based upon current information from its operators, the Partnership anticipates all current PUD locations will be drilled and converted to PDP within five years of the date they were added. PUD locations and associated reserves which are no longer projected to be drilled within five years from the date they were first booked as proved undeveloped reserves have been removed as revisions at the time that determination was made. Standardized Measure of Discounted Future Net Cash Flows Accounting standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Partnership has followed these guidelines, which are briefly discussed below. Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for such year. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect the Partnership’s expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process. 2020 2019 Future cash inflows $ 467,805,216 $ 926,512,000 Future production costs (197,152,040 ) (297,812,320 ) Future development costs (58,641,300 ) (120,692,304 ) Future net cash flows 212,011,876 508,007,376 10% annual discount (139,125,116 ) (301,184,896 ) Standardized measure of discounted future net cash flows $ 72,886,760 $ 206,822,480 Changes in the standardized measure of discounted future net cash flows are as follows: 2020 2019 Standardized measure at beginning of period $ 206,822,480 $ 304,884,875 Changes resulting from: Acquisition of reserves - - Extensions, discoveries and other additions - 21,876,159 Sales of oil, natural gas and NGLs, net of production costs (23,607,481 ) (23,283,973 ) Net changes in prices and production costs (129,957,704 ) (100,417,683 ) Development costs incurred during the period 19,020,672 26,021,438 Revisions to previous estimates (63,132,466 ) (27,133,641 ) Accretion of discount 20,710,927 30,530,765 Change in estimated future development costs 43,030,332 (25,655,460 ) Standardized measure of discounted future net cash flows $ 72,886,760 $ 206,822,480

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2020
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information [Text Block]	Note 10. Quarterly Financial Data (Unaudited) The following is a summary of quarterly results of operations for the years ended December 31, 2020 and 2019. 2020 First Quarter Second Quarter Third Quarter Fourth Quarter Total revenue $ 11,103,534 $ 4,752,518 $ 9,650,268 $ 11,051,756 Net income (loss) $ 2,933,427 $ (4,441,521 ) $ (879,896 ) $ (417,333 ) Basic and diluted net income (loss) per common share $ 0.15 $ (0.23 ) $ (0.05 ) $ (0.02 ) 2019 First Quarter Second Quarter Third Quarter Fourth Quarter Total revenue $ 10,091,345 $ 9,317,659 $ 7,339,109 $ 9,271,489 Net income $ 2,339,974 $ 1,959,063 $ 1,794,044 $ 2,387,369 Basic and diluted net income per common share $ 0.12 $ 0.10 $ 0.09 $ 0.13

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2020
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Note 11. Subsequent Events During the first quarter of 2021, the Partnership paid off the remaining $6 million balance on its Affiliate Loan with GKDML, LLC. The Partnership did not incur a penalty for prepayment.

Accounting Policies, by Policy

Accounting Policies, by Policy (Policies)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Basis of Accounting, Policy [Policy Text Block]	Basis of Presentation
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash, Cash Equivalents and Restricted Cash and Cash Equivalents Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. Restricted cash as of December 31, 2020 of $0.9 million represents required collateral under the Letter Agreement (see Note 4. Debt) with the Partnership’s lender. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits.
Oil and Gas Properties Policy [Policy Text Block]	Property and Depreciation, Depletion and Amortization The Partnership accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities. No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties. The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.
Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]	Impairment The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of the properties exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an impairment expense equal to the difference between the carrying value and the fair value of the properties, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. The underlying commodity prices used in the determination of our estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.
Concentration Risk, Credit Risk, Policy [Policy Text Block]	Accounts Receivable and Concentration of Credit Risk Substantially all the Partnership’s accounts receivable is due from the operators of the Partnership’s oil and natural gas properties in North Dakota (the operators have accounts receivable from purchasers of oil, natural gas and NGLs). Oil, natural gas and NGL sales receivables are generally unsecured. This industry and location concentration has the potential to impact the Partnership’s overall exposure to credit risk, in that the purchasers of the Partnership’s oil, natural gas and NGLs and the operators of the properties the Partnership has an interest in may be similarly affected by changes in economic, industry or other conditions. At December 31, 2020, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible. For the year ended December 31, 2020, the Partnership’s oil, natural gas and NGL sales were through four operators. Whiting is the operator of 98% of the Partnership’s producing properties. All oil and natural gas producing activities of the Partnership are in North Dakota and represent substantially all of the business activities of the Partnership.
Asset Retirement Obligation [Policy Text Block]	Asset Retirement Obligation The Partnership has significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. The removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance. The following table shows the activity for the years ended December 31, 2020 and 2019, relating to the Partnership’s asset retirement obligations: Balance as of December 31, 2018 $ 1,294,067 Well additions 87,019 Accretion 71,648 Revisions in estimated cash flows - Balance as of December 31, 2019 $ 1,452,734 Well additions 35,647 Accretion 75,724 Revisions in estimated cash flows - Balance as of December 31, 2020 $ 1,564,105
Income Tax, Policy [Policy Text Block]	Income Tax The Partnership is taxed as a partnership for federal and state income tax purposes. No provision for income taxes has been recorded since the liability for such taxes is that of each of the partners rather than the Partnership. The Partnership’s income tax returns are subject to examination by the federal and state taxing authorities, and changes, if any, could adjust the individual income tax of the partners. The Partnership has evaluated whether any material tax position taken will more likely than not be sustained upon examination by the appropriate taxing authority and believes that all such material tax positions taken are supportable by existing laws and related interpretations.
Environmental Costs, Policy [Policy Text Block]	Environmental Costs As the Partnership is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Partnership does not believe the existence of current environmental laws or interpretations thereof will materially hinder or adversely affect the Partnership’s business operations; however, there can be no assurances of future effects on the Partnership of new laws or interpretations thereof. Since the Partnership does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with the Partnership being responsible for its proportionate share of the costs involved. Environmental liabilities are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At December 31, 2020 and 2019, there were no such costs accrued.
Use of Estimates, Policy [Policy Text Block]	Use of Estimates Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the financial statements and accompanying notes. Actual results could differ from those estimates. Of these estimates and assumptions, management considers the estimation of oil, natural gas and NGL reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as depreciation, depletion and amortization (“DD&A”) and impairment calculations. On an annual basis, the Partnership’s independent consulting petroleum engineer, with assistance from the Partnership, prepares estimates of oil, natural gas and NGL reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the Securities and Exchange Commission (“SEC”), the reserve estimates were based on average individual product prices during the 12-month period prior to December 31, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period excluding escalations based upon future conditions. For impairment purposes, projected NYMEX forward strip prices for oil, natural gas and NGL as estimated by management are used. Oil, natural gas and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future oil, natural gas and NGL pricing assumptions are used by management to prepare estimates of oil, natural gas and NGL reserves used in formulating management’s overall operating decisions. The Partnership does not operate its oil and natural gas properties and, therefore, receives actual oil, natural gas and NGL sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case, the most current available production data is gathered from the appropriate operators, and oil, natural gas and NGL index prices local to each well are used to estimate the accrual of revenue on these wells. The oil, natural gas and NGL sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, natural gas and NGLs. These variables could lead to an over or under accrual of oil, natural gas and NGL sales at the end of any particular quarter. However, the Partnership adjusts the estimated accruals of revenue to actual production in the period actual production is determined.
Revenue [Policy Text Block]	Revenue Recognition The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Oil, natural gas and natural gas liquids revenue receivable in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.
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 (loss), partners’ equity or cash flows.
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 unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the years ended December 31, 2020 and 2019. As a result, basic and diluted outstanding common units were the same. The Class B Units and Incentive Distribution Rights are not included in net income (loss) per common unit until such time that it is probable Payout (as discussed in Note 7) would occur.
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Adopted Accounting Standards In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-04, Reference Rate Reform (Topic 848), which provides optional guidance through December 31, 2022 to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments in ASU No. 2020-04 apply to contract modifications that replace a reference rate affected by reference rate reform, providing optional expedients regarding the measurement of hedge effectiveness in hedging relationships that have been modified to replace a reference rate. While the guidance in ASU No. 2020-04 became effective upon issuance, the provisions of the ASU did not have a material impact on the Partnership’s consolidated financial statements and related disclosures as of December 31, 2020.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2020
Accounting Policies [Abstract]
Schedule of Asset Retirement Obligations [Table Text Block]	The following table shows the activity for the years ended December 31, 2020 and 2019, relating to the Partnership’s asset retirement obligations: Balance as of December 31, 2018 $ 1,294,067 Well additions 87,019 Accretion 71,648 Revisions in estimated cash flows - Balance as of December 31, 2019 $ 1,452,734 Well additions 35,647 Accretion 75,724 Revisions in estimated cash flows - Balance as of December 31, 2020 $ 1,564,105

Fair Value of Financial Instr_2

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2020 and 2019. Fair Value Measurements at December 31, 2020 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current liabilities $ - $ (602,760 ) $ - Total $ - $ (602,760 ) $ - Fair Value Measurements at December 31, 2019 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current liabilities $ - $ (183,850 ) $ - Total $ - $ (183,850 ) $ -

Risk Management (Tables)

Risk Management (Tables)	12 Months Ended
	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	The Partnership has not designated its derivative instruments as hedges for accounting purposes and has not entered 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 settlements of matured derivative instruments and non-cash losses on open derivative instruments for the periods presented. Settlements on matured derivatives below reflect a realized net gain 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) losses below represent the change in fair value of derivative instruments which were held at period-end. Year Ended December 31, 2020 Year Ended December 31, 2019 Settlements on matured derivatives, net $ 146,710 $ 13,310 Loss on mark-to-market of derivatives, net (418,910 ) (183,850 ) Loss on derivatives, net $ (272,200 ) $ (170,540 )
Schedule of Derivative Instruments [Table Text Block]	The following table reflects the open costless collar derivative instruments as of December 31, 2020. Settlement Period Basis Product Volume Floor / Ceiling Prices ($) Fair Value of Asset (Liability) at 01/2021 - 02/2021 NYMEX Oil (bbls) 30,000 37.50 / 44.50 $ (174,600 ) 01/2021 - 02/2021 NYMEX Oil (bbls) 30,000 38.00 / 44.25 (184,350 ) 01/2021 - 02/2021 NYMEX Oil (bbls) 30,000 38.00 / 44.00 (194,850 ) 01/2021 - 02/2021 NYMEX Oil (bbls) 15,000 38.00 / 44.50 (67,590 ) 01/2021 - 02/2021 Henry Hub Gas (MMBtu) 120,000 2.50 / 3.05 18,630 $ (602,760 )

Supplementary Information on _2

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2020
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]	The aggregate amount of capitalized costs of oil, natural gas and NGL properties and related accumulated depreciation, depletion and amortization as of December 31, 2020 and 2019 is as follows: 2020 2019 Producing properties $ 229,234,243 $ 217,356,850 Non-producing 169,731,229 162,587,950 398,965,472 379,944,800 Accumulated depreciation, depletion and amortization (75,765,289 ) (53,186,164 ) Net capitalized costs $ 323,200,183 $ 326,758,636
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]	For the years ended December 31, 2020 and 2019, the Partnership incurred the following costs in oil and natural gas producing activities: 2020 2019 Development costs $ 19,020,672 $ 26,021,438
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]	The rollforward of net quantities of proved developed and undeveloped oil, natural gas and NGL reserves are summarized as follows: Proved Reserves Oil Natural Gas NGLs (Bbls) (Mcf) (Bbls) Total (BOE) December 31, 2018 19,557,273 23,040,536 3,987,383 27,384,745 Acquisition - - - - Extensions, discoveries and other additions (1) 1,101,604 1,167,115 163,884 1,460,007 Revisions of previous estimates (2) (1,213,675 ) 456,464 (710,685 ) (1,848,283 ) Production (624,079 ) (888,208 ) (126,516 ) (898,629 ) December 31, 2019 18,821,123 23,775,907 3,314,066 26,097,840 Acquisition - - - - Extensions, discoveries and other additions - - - - Revisions of previous estimates (3) (3,391,968 ) (5,920,203 ) (527,522 ) (4,906,190 ) Production (1,014,980 ) (1,057,474 ) (158,050 ) (1,349,276 ) December 31, 2020 14,414,175 16,798,230 2,628,494 19,842,374 (1) In 2019, extensions, discoveries and other additions of 1,460 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator in the Sanish field. (2) Revisions to previous estimates decreased proved reserves by a net amount of 1,848 MBOE. These revisions result from 1,216 MBOE of downward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2019 to December 31, 2018, 511 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2019 to December 31, 2018, and 121 MBOE of downward adjustments attributable to changes in the future drill schedule. (3) Revisions to previous estimates decreased proved reserves by a net amount of 4,906 MBOE. These revisions result from 5,409 MBOE of downward adjustments attributable to changes in the future drill schedule and 1,619 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019, offset by 2,122 of upward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019. Oil Natural Gas NGLs (Bbls) (Mcf) (Bbls) Total (BOE) Proved developed reserves: December 31, 2018 9,195,064 12,333,784 2,134,478 13,385,173 December 31, 2019 9,771,596 14,232,526 1,974,006 14,117,690 December 31, 2020 10,688,857 12,992,674 2,029,392 14,883,695 Proved undeveloped reserves: December 31, 2018 10,362,209 10,706,752 1,852,905 13,999,573 December 31, 2019 9,049,527 9,543,381 1,340,060 11,980,151 December 31, 2020 3,725,318 3,805,556 599,102 4,958,679 BOE Proved undeveloped reserves, December 31, 2018 13,999,573 Revisions of previous estimates (1) (365,470 ) Extensions, discoveries and other additions (2) 1,460,007 Conversion to proved developed reserves (3) (3,113,959 ) Proved undeveloped reserves acquired - Proved undeveloped reserves, December 31, 2019 11,980,151 Revisions of previous estimates (4) (5,501,947 ) Extensions, discoveries and other additions - Conversion to proved developed reserves (5) (1,519,525 ) Proved undeveloped reserves acquired - Proved undeveloped reserves, December 31, 2019 4,958,679 (1) The annual review of the PUDs resulted in a negative revision of approximately 365 MBOE. This revision was the result of 244 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2018 to December 31, 2019 and 121 MBOE of downward adjustments attributable to changes in the future drill schedule. (2) In 2019, extensions, discoveries and other additions of 1,460 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator in the Sanish field. (3) The Partnership completed 11 new wells during 2019. In addition, the Partnership had four wells at December 31, 2019 classified as PDNP that were substantially complete and the costs to bring to production were relatively minor. Therefore, the Partnership converted the 11 completed wells and the four PDNP wells from PUD to proved developed reserves, which resulted in a downward adjustment to PUDs of 3,114 MBOE. (4) The annual review of the PUDs resulted in a negative revision of approximately 5,502 MBOE. This revision was the result of 5,409 MBOE of downward adjustments attributable to changes in the future drill schedule, 121 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2020 and December 31, 2019, and 28 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2020 to December 31, 2019. (5) The Partnership completed 11 new wells during 2020. As discussed in (3) above, the Partnership already converted four of these 11 wells from PUD to proved developed reserves at December 31, 2019 because they were substantially complete and the costs to bring to production were relatively minor. Therefore, the Partnership converted the other 7 completed wells to proved developed reserves during 2020, which resulted in a downward adjustment to PUDs of 1,520 MBOE.
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]	The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect the Partnership’s expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process. 2020 2019 Future cash inflows $ 467,805,216 $ 926,512,000 Future production costs (197,152,040 ) (297,812,320 ) Future development costs (58,641,300 ) (120,692,304 ) Future net cash flows 212,011,876 508,007,376 10% annual discount (139,125,116 ) (301,184,896 ) Standardized measure of discounted future net cash flows $ 72,886,760 $ 206,822,480
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]	Changes in the standardized measure of discounted future net cash flows are as follows: 2020 2019 Standardized measure at beginning of period $ 206,822,480 $ 304,884,875 Changes resulting from: Acquisition of reserves - - Extensions, discoveries and other additions - 21,876,159 Sales of oil, natural gas and NGLs, net of production costs (23,607,481 ) (23,283,973 ) Net changes in prices and production costs (129,957,704 ) (100,417,683 ) Development costs incurred during the period 19,020,672 26,021,438 Revisions to previous estimates (63,132,466 ) (27,133,641 ) Accretion of discount 20,710,927 30,530,765 Change in estimated future development costs 43,030,332 (25,655,460 ) Standardized measure of discounted future net cash flows $ 72,886,760 $ 206,822,480

Quarterly Financial Data (Una_2

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2020
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information [Table Text Block]	The following is a summary of quarterly results of operations for the years ended December 31, 2020 and 2019. 2020 First Quarter Second Quarter Third Quarter Fourth Quarter Total revenue $ 11,103,534 $ 4,752,518 $ 9,650,268 $ 11,051,756 Net income (loss) $ 2,933,427 $ (4,441,521 ) $ (879,896 ) $ (417,333 ) Basic and diluted net income (loss) per common share $ 0.15 $ (0.23 ) $ (0.05 ) $ (0.02 ) 2019 First Quarter Second Quarter Third Quarter Fourth Quarter Total revenue $ 10,091,345 $ 9,317,659 $ 7,339,109 $ 9,271,489 Net income $ 2,339,974 $ 1,959,063 $ 1,794,044 $ 2,387,369 Basic and diluted net income per common share $ 0.12 $ 0.10 $ 0.09 $ 0.13

Partnership Organization (Detai

Partnership Organization (Details) shares in Millions

Dec. 18, 2015

Jul. 09, 2013USD ($)

Dec. 31, 2020USD ($)

Dec. 31, 2019

Dec. 31, 2018

Mar. 31, 2020USD ($)

Dec. 31, 2020

Dec. 31, 2019USD ($)

Apr. 24, 2017USD ($)shares

Jul. 31, 2020USD ($)

Sep. 30, 2019USD ($)

Nov. 21, 2017USD ($)

Partnership Organization (Details) [Line Items]

Limited Liability Company or Limited Partnership, Business, Formation State

Delaware

Partners' Capital Account, Contributions

$ 1,000

Debt, Current

$ 46,000,000

Sanish Field Located in Mountrail County, North Dakota [Member]

Partnership Organization (Details) [Line Items]

Capital Expenditures, Drilling and Completion of Wells

$ 62,000,000

$ 7,800,000

Oil and Gas, Development Well Drilled, Net Productive, Number

6

Best-Efforts Offering [Member]

Partnership Organization (Details) [Line Items]

Partners' Capital Account, Units, Sale of Units (in Shares) | shares

19

Proceeds from Issuance of Common Limited Partners Units

$ 374,200,000

Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units

$ 349,600,000

Revolving Credit Facility [Member]

Partnership Organization (Details) [Line Items]

Debt Instrument, Face Amount

$ 20,000,000

Revolving Credit Facility [Member] | Amended Loan Agreement [Member]

Partnership Organization (Details) [Line Items]

Line of Credit Facility, Remaining Borrowing Capacity

$ 16,000,000

Debt Instrument, Face Amount

$ 40,000,000

$ 40,000,000

GKDML [Member]

Partnership Organization (Details) [Line Items]

Debt Instrument, Face Amount

15,000,000

Amounts Outstanding To Operator

$ 21,000,000

Sanish Field Located in Mountrail County, North Dakota [Member]

Partnership Organization (Details) [Line Items]

Wells Elected to Participate in Drilling

43

Capital Expenditures, Drilling and Completion of Wells

$ 62,000,000

Oil and Gas, Development Well Drilled, Net Productive, Number

14

Non-operated Completed Wells [Member]

Partnership Organization (Details) [Line Items]

Oil and Gas, Development Well Drilled, Net Productive, Number

11

22

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

243

243

Non-operated Wells in the Process of Drilling [Member]

Partnership Organization (Details) [Line Items]

Oil and Gas, Present Activity, Well in Process of Drilling

21

21

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

18.00%

Oil and Gas, Present Activity, Well in Process of Drilling

21

21

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2020USD ($)shares	Dec. 31, 2019USD ($)shares
Summary of Significant Accounting Policies (Details) [Line Items]
Restricted Cash and Cash Equivalents, Current | $	$ 855,518	$ 0
Number of Operators	4
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | shares	0	0
Customer Concentration Risk [Member] | Whiting Petroleum [Member] | Revenue Benchmark [Member]
Summary of Significant Accounting Policies (Details) [Line Items]
Concentration Risk, Percentage	98.00%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) - Schedule of Asset Retirement Obligations - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Asset Retirement Obligations [Abstract]
Balance	$ 1,452,734	$ 1,294,067
Well additions	35,647	87,019
Accretion	75,724	71,648
Revisions in estimated cash flows	0	0
Balance	$ 1,564,105	$ 1,452,734

Oil and Gas Investments (Detail

Oil and Gas Investments (Details) $ in Millions	Mar. 31, 2017	Jan. 11, 2017USD ($)	Dec. 18, 2015USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019	Dec. 31, 2018	Mar. 31, 2020USD ($)	Dec. 31, 2020	Dec. 31, 2019USD ($)
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and 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)					$ 62					$ 7.8
Costs Incurred, Development Costs (in Dollars)					42
Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member]
Oil and Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					12
Sanish Field Located in Mountrail County, North Dakota [Member] | Maximum [Member]
Oil and Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					$ 15
Acquisition No. 1 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Business Combination, Consideration Transferred (in Dollars)			$ 159.6
Acquisition No. 2 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net		11.00%
Business Combination, Consideration Transferred (in Dollars)		$ 128.5
Acquisition No. 3 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net	10.50%
Business Combination, Consideration Transferred (in Dollars)				$ 52.4
Number of Producing Partnership Wells Acquired	82
Oil, Productive Well, Number of Wells, Net	216			216
Number of Future Development Partnership Locations Acquired	150
Gas and Oil Area Undeveloped, Net	253
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number								14
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)								$ 62
Wells Elected to Participate in Drilling								43
Non-operated Completed Wells [Member]
Oil and Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number						11			22
Working Interest					23.00%				23.00%
Non-operated Completed Wells [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net			11.00%		25.00%
Oil, Productive Well, Number of Wells, Net					243				243
Non-operated Wells in the Process of Drilling [Member]
Oil and Gas Investments (Details) [Line Items]
Working Interest					18.00%				18.00%
Oil and Gas, Present Activity, Well in Process of Drilling					21				21
Non-operated Wells in the Process of Drilling [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net					18.00%
Oil and Gas, Present Activity, Well in Process of Drilling					21				21

Debt (Details)

Debt (Details) - USD ($)	Jul. 21, 2020	Sep. 30, 2019	Nov. 21, 2017	Jul. 31, 2020	Dec. 31, 2020	Mar. 31, 2020	Dec. 31, 2019
Debt (Details) [Line Items]
Long-term Line of Credit					$ 0		$ 24,000,000
Line of Credit Facility, Fair Value of Amount Outstanding					40,000,000		24,000,000
Notes Payable, Related Parties, Current					$ 6,000,000		$ 0
Revolving Credit Facility [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount			$ 20,000,000
Debt Instrument, Maturity Date			Nov. 21, 2019
Line of Credit Facility, Commitment Fee Description		the Partnership paid an origination fee of 0.45% on the change in Revolver Commitment Amount of the Credit Facility (increase from $20 million on previous credit facility to $40 million under revised Credit Facility, or $20 million), or $90,000
Line of Credit Facility, Commitment Fee Percentage		0.45%
Line of Credit Facility, Commitment Fee Amount		$ 90,000
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage		0.50%
Line of Credit Facility, Covenant Compliance					The Partnership was in compliance with its applicable covenants at December 31, 2020.
Long-term Line of Credit					$ 40,000,000
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate					4.25%
Revolving Credit Facility [Member] | Amended Loan Agreement [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount		$ 40,000,000				$ 40,000,000
Debt Instrument, Maturity Date	Jul. 31, 2021	Sep. 30, 2022
Line of Credit Facility, Borrowing Capacity, Description		an increase to the borrowing base from $30 million to an initially stipulated $40 million
Line of Credit Facility, Collateral		an increase to the mortgage and lenders’ first lien position from 80% to 90% of the Partnership’s owned producing oil and natural gas properties
Debt Instrument, Collateral Amount	$ 1,600,000
Restricted Cash, Current					$ 900,000
Debt, Risk Management, Description		Also, under the Letter Agreement, the Partnership is required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and natural gas sales. The risk management program must cover at least 80% of the Partnership’s projected total production of oil and natural gas for the period from August 31, 2020 until the next borrowing base redetermination date (first quarter of 2021).
Debt Instrument, Fee Amount	$ 40,000
GKDML [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount				$ 15,000,000
Debt Instrument, Term				1 year
Notes Payable, Related Parties, Current					$ 6,000,000
Short-term Debt, Weighted Average Interest Rate, at Point in Time					2.10%
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | Amended Loan Agreement [Member] | Minimum [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.50%
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | Amended Loan Agreement [Member] | Maximum [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate		3.50%
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] | GKDML [Member] | Minimum [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate				0.00%
Prime Rate [Member] | Revolving Credit Facility [Member] | Amended Loan Agreement [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
Prime Rate [Member] | Revolving Credit Facility [Member] | Amended Loan Agreement [Member] | Minimum [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	4.00%

Fair Value of Financial Instr_3

Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis - USD ($)	Dec. 31, 2020	Dec. 31, 2019
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 assets	$ 0	$ 0
Total	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current assets	(602,760)	(183,850)
Total	(602,760)	(183,850)
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 assets	0	0
Total	$ 0	$ 0

Risk Management (Details)

Risk Management (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Discussion of Price Risk Derivative Risk Management Policy	Debt, the Partnership is 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 31, 2020 until the next borrowing base redetermination date (first quarter of 2021).
Derivative Liability	$ 0.6	$ 0.2

Risk Management (Details) - Sch

Risk Management (Details) - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Abstract]
Settlements on matured derivatives, net	$ 146,710	$ 13,310
Loss on mark-to-market of derivatives, net	(418,910)	(183,850)
Loss on derivatives, net	$ (272,200)	$ (170,540)

Risk Management (Details) - S_2

Risk Management (Details) - Schedule of Derivative Instruments	12 Months Ended
	Dec. 31, 2020USD ($)$ / bblbbl
Derivative [Line Items]
Fair Value of Asset / (Liability) | $	$ (602,760)
Costless Collar Agreements 1 [Member] | Price Risk Derivative [Member]
Derivative [Line Items]
Basis	NYMEX
Product	Oil (bbls)
Volume | bbl	30,000
Floor Price	37.50
Ceiling Price	44.50
Fair Value of Asset / (Liability) | $	$ (174,600)
Costless Collar Agreements 2 [Member] | Price Risk Derivative [Member]
Derivative [Line Items]
Basis	NYMEX
Product	Oil (bbls)
Volume | bbl	30,000
Floor Price	38
Ceiling Price	44.25
Fair Value of Asset / (Liability) | $	$ (184,350)
Costless Collar Agreements 3 [Member] | Price Risk Derivative [Member]
Derivative [Line Items]
Basis	NYMEX
Product	Oil (bbls)
Volume | bbl	30,000
Floor Price	38
Ceiling Price	44
Fair Value of Asset / (Liability) | $	$ (194,850)
Costless Collar Agreements 4 [Member] | Price Risk Derivative [Member]
Derivative [Line Items]
Basis	NYMEX
Product	Oil (bbls)
Volume | bbl	15,000
Floor Price	38
Ceiling Price	44.50
Fair Value of Asset / (Liability) | $	$ (67,590)
Costless Collar Agreements 5 [Member] | Price Risk Derivative [Member]
Derivative [Line Items]
Basis	Henry Hub
Product	Gas (MMBtu)
Volume | bbl	120,000
Floor Price	2.50
Ceiling Price	3.05
Fair Value of Asset / (Liability) | $	$ 18,630

Capital Contribution and Part_2

Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions	Jul. 09, 2013	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	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 common unit, regardless of the amount paid for the common unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount. All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:  ● First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement;   ● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%).
Annualized Rate of Retun		7.00%
Distribution at Payout to limited partner, per common unit (in Dollars per share)			$ 1,181,370
Distribution at Payout to limited partner			$ 22,000,000
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share)			$ 0.241644	$ 1.396164
Distribution Made to Limited Partner, Cash Distributions Paid			$ 4,584,826	$ 26,490,081
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, 2020	Apr. 06, 2017	Apr. 05, 2017	Dec. 31, 2020	Dec. 31, 2019	Mar. 31, 2017
Related Parties (Details) [Line Items]
Class B Units, Units Outstanding (in Shares)				62,500	62,500
Related Party, Administrative Service Agreement	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. 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.
General Partner [Member]
Related Parties (Details) [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party				$ 381,000	$ 319,000
Due to Related Parties, Current				52,000	83,000
Affiliated Entity [Member]
Related Parties (Details) [Line Items]
Operating Leases, Rent Expense, Minimum Rentals				8,537
Reimbursements From Related Party				$ 268,000	285,000
Due from Related Parties					$ 85,000
E11 Incentive Holdings [Member]
Related Parties (Details) [Line Items]
Class B Units, Units Outstanding (in Shares)						62,500
E11 Incentive Holdings [Member] | Units transferred to E11 Incentive Carry Vehicle, LP for minimis Consideration [Member]
Related Parties (Details) [Line Items]
Class B Units, transferred (in Shares)			18,125
E11 Incentive Holdings [Member] | Units Sold to Regional Energy Incentives, LP [Member]
Related Parties (Details) [Line Items]
Class B Units, Units Sold (in Shares)		44,375
Class B Units, Total Sales Price for Sale of Capital Units		$ 98,000

Supplementary Information on _3

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details)	12 Months Ended				24 Months Ended
	Dec. 31, 2020Boe$ / bbl$ / MMcf		Dec. 31, 2019Boe$ / bbl$ / MMcf		Dec. 31, 2020
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)	(5,501,947)	[1]	(365,470)	[2]
Number of Proved Developed Non-producing Wells Converted to Producing	7		4
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)	(1,519,525)	[3]	(3,113,959)	[4]
Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)	(4,906,000)		(1,848,000)
Proved Undeveloped Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)	(5,502,000)		(365,000)
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)	1,520,000		(3,114,000)
Before Price Differentials [Member] | Oil [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Average Sale Price (in Dollars per Barrel (of Oil)) | $ / bbl	39.57		55.69
Before Price Differentials [Member] | Natural Gas [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Average Sale Price (in Dollars per Barrel (of Oil)) | $ / MMcf	1.99		2.58
Including Effect of Price Differential Adjustments [Member] | Oil [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Average Sale Price (in Dollars per Barrel (of Oil)) | $ / bbl	32.08		47.70
Including Effect of Price Differential Adjustments [Member] | Natural Gas [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Average Sale Price (in Dollars per Barrel (of Oil)) | $ / MMcf	(0.55)		(0.03)
Including Effect of Price Differential Adjustments [Member] | Natural Gas Liquids [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Average Sale Price (in Dollars per Barrel (of Oil)) | $ / bbl	5.54		8.91
Non-operated Completed Wells [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number			11		22
Adjustments Related to Successful Drilling [Member] | Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)			1,460,000
Adjustments Related to Well Performance [Member] | Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)	2,122,000		(1,216,000)
Adjustments Related to Prices [Member] | Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)	(1,619,000)		(511,000)
Adjustment Related to Changes in Future Drill Schedule [Member] | Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)	(5,409,000)		(121,000)
Adjustments Related to Natural Gas Shrink [Member] | Proved Undeveloped Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)	28,000		(244,000)
[1]	The annual review of the PUDs resulted in a negative revision of approximately 5,502 MBOE. This revision was the result of 5,409 MBOE of downward adjustments attributable to changes in the future drill schedule, 121 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2020 and December 31, 2019, and 28 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2020 to December 31, 2019.
[2]	The annual review of the PUDs resulted in a negative revision of approximately 365 MBOE. This revision was the result of 244 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2018 to December 31, 2019 and 121 MBOE of downward adjustments attributable to changes in the future drill schedule.
[3]	The Partnership completed 11 new wells during 2020. As discussed in (3) above, the Partnership already converted four of these 11 wells from PUD to proved developed reserves at December 31, 2019 because they were substantially complete and the costs to bring to production were relatively minor. Therefore, the Partnership converted the other 7 completed wells to proved developed reserves during 2020, which resulted in a downward adjustment to PUDs of 1,520 MBOE.
[4]	The Partnership completed 11 new wells during 2019. In addition, the Partnership had four wells at December 31, 2019 classified as PDNP that were substantially complete and the costs to bring to production were relatively minor. Therefore, the Partnership converted the 11 completed wells and the four PDNP wells from PUD to proved developed reserves, which resulted in a downward adjustment to PUDs of 3,114 MBOE.

Supplementary Information on _4

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure - USD ($)	Dec. 31, 2020	Dec. 31, 2019
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved Properties	$ 398,965,472	$ 379,944,800
Accumulated depreciation, depletion and amortization	(75,765,289)	(53,186,164)
Net capitalized costs	323,200,183	326,758,636
Producing Properties [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved Properties	229,234,243	217,356,850
Non-Producing Properties [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved Properties	$ 169,731,229	$ 162,587,950

Supplementary Information on _5

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Abstract]
Development costs	$ 19,020,672	$ 26,021,438

Supplementary Information on _6

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities	12 Months Ended
	Dec. 31, 2020BoebblMcf		Dec. 31, 2019BoebblMcf		Dec. 31, 2018BoebblMcf
Reserve Quantities [Line Items]
Balance	26,097,840		27,384,745
Balance, Proved Developed Reserves (in Barrels of Oil Equivalent) | Boe	14,883,695		14,117,690		13,385,173
Balance, Proved Undeveloped Reserves (in Barrels of Oil Equivalent) | Boe	4,958,679		11,980,151		13,999,573
Balance, Proved Undeveloped Reserves (in Barrels of Oil Equivalent) | Boe	4,958,679		11,980,151		13,999,573
Revisions of previous estimates (in Barrels of Oil Equivalent) | Boe	(5,501,947)	[1]	(365,470)	[2]
Extensions, discoveries and other additions (in Barrels of Oil Equivalent) | Boe	0		1,460,007	[3]
Conversion to proved developed reserves (in Barrels of Oil Equivalent) | Boe	(1,519,525)	[4]	(3,113,959)	[5]
Proved undeveloped reserves acquired (in Barrels of Oil Equivalent) | Boe	0		0
Acquisition	0		0
Extensions, discoveries and other additions	0		1,460,007	[3]
Revisions of previous estimates	(4,906,190)	[6]	(1,848,283)	[7]
Production	(1,349,276)		(898,629)
Balance	19,842,374		26,097,840
Oil [Member]
Reserve Quantities [Line Items]
Balance	18,821,123		19,557,273
Balance, Proved Developed Reserves	10,688,857		9,771,596		9,195,064
Balance, Proved Undeveloped Reserves	3,725,318		9,049,527		10,362,209
Acquisition	0		0
Extensions, discoveries and other additions	0		1,101,604	[3]
Revisions of previous estimates	(3,391,968)	[6]	(1,213,675)	[7]
Production	(1,014,980)		(624,079)
Balance	14,414,175		18,821,123
Natural Gas [Member]
Reserve Quantities [Line Items]
Balance | Mcf	23,775,907		23,040,536
Balance, Proved Developed Reserves | Mcf	12,992,674		14,232,526		12,333,784
Balance, Proved Undeveloped Reserves | Mcf	3,805,556		9,543,381		10,706,752
Acquisition | Mcf	0		0
Extensions, discoveries and other additions | Mcf	0		1,167,115	[3]
Revisions of previous estimates | Mcf	(5,920,203)	[6]	456,464	[7]
Production | Mcf	(1,057,474)		(888,208)
Balance | Mcf	16,798,230		23,775,907
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Balance	3,314,066		3,987,383
Balance, Proved Developed Reserves	2,029,392		1,974,006		2,134,478
Balance, Proved Undeveloped Reserves	599,102		1,340,060		1,852,905
Acquisition	0		0
Extensions, discoveries and other additions	0		163,884	[3]
Revisions of previous estimates	(527,522)	[6]	(710,685)	[7]
Production	(158,050)		(126,516)
Balance	2,628,494		3,314,066
[1]	The annual review of the PUDs resulted in a negative revision of approximately 5,502 MBOE. This revision was the result of 5,409 MBOE of downward adjustments attributable to changes in the future drill schedule, 121 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2020 and December 31, 2019, and 28 MBOE of upward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2020 to December 31, 2019.
[2]	The annual review of the PUDs resulted in a negative revision of approximately 365 MBOE. This revision was the result of 244 MBOE of downward adjustments attributable to changes in natural gas shrink and NGL yield when comparing the Partnership’s reserves at December 31, 2018 to December 31, 2019 and 121 MBOE of downward adjustments attributable to changes in the future drill schedule.
[3]	In 2019, extensions, discoveries and other additions of 1,460 MBOE were primarily attributable to successful drilling by the Partnership’s primary operator in the Sanish field.
[4]	The Partnership completed 11 new wells during 2020. As discussed in (3) above, the Partnership already converted four of these 11 wells from PUD to proved developed reserves at December 31, 2019 because they were substantially complete and the costs to bring to production were relatively minor. Therefore, the Partnership converted the other 7 completed wells to proved developed reserves during 2020, which resulted in a downward adjustment to PUDs of 1,520 MBOE.
[5]	The Partnership completed 11 new wells during 2019. In addition, the Partnership had four wells at December 31, 2019 classified as PDNP that were substantially complete and the costs to bring to production were relatively minor. Therefore, the Partnership converted the 11 completed wells and the four PDNP wells from PUD to proved developed reserves, which resulted in a downward adjustment to PUDs of 3,114 MBOE.
[6]	Revisions to previous estimates decreased proved reserves by a net amount of 4,906 MBOE. These revisions result from 5,409 MBOE of downward adjustments attributable to changes in the future drill schedule and 1,619 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019, offset by 2,122 of upward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2020 to December 31, 2019.
[7]	Revisions to previous estimates decreased proved reserves by a net amount of 1,848 MBOE. These revisions result from 1,216 MBOE of downward adjustments attributable to well performance when comparing the Partnership’s reserve estimates at December 31, 2019 to December 31, 2018, 511 MBOE of downward adjustments caused by lower oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2019 to December 31, 2018, and 121 MBOE of downward adjustments attributable to changes in the future drill schedule.

Supplementary Information on _7

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure - USD ($)	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Abstract]
Future cash inflows	$ 467,805,216	$ 926,512,000
Future production costs	(197,152,040)	(297,812,320)
Future development costs	(58,641,300)	(120,692,304)
Future net cash flows	212,011,876	508,007,376
10% annual discount	(139,125,116)	(301,184,896)
Standardized measure of discounted future net cash flows	$ 72,886,760	$ 206,822,480	$ 304,884,875

Supplementary Information on _8

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure (Parentheticals)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Measurement Input, Discount Rate [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Annual discount	10.00%	10.00%

Supplementary Information on _9

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Abstract]
Standardized measure at beginning of period	$ 206,822,480	$ 304,884,875
Acquisition of reserves	0	0
Extensions, discoveries and other additions	0	21,876,159
Sales of oil, natural gas and NGLs, net of production costs	(23,607,481)	(23,283,973)
Net changes in prices and production costs	(129,957,704)	(100,417,683)
Development costs incurred during the period	19,020,672	26,021,438
Revisions to previous estimates	(63,132,466)	(27,133,641)
Accretion of discount	20,710,927	30,530,765
Change in estimated future development costs	43,030,332	(25,655,460)
Standardized measure of discounted future net cash flows	$ 72,886,760	$ 206,822,480

Quarterly Financial Data (Una_3

Quarterly Financial Data (Unaudited) (Details) - Quarterly Financial Information - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019
Quarterly Financial Information [Abstract]
Total revenue	$ 11,051,756	$ 9,650,268	$ 4,752,518	$ 11,103,534	$ 9,271,489	$ 7,339,109	$ 9,317,659	$ 10,091,345	$ 36,522,076	$ 36,019,602
Net income (loss)	$ (417,333)	$ (879,896)	$ (4,441,521)	$ 2,933,427	$ 2,387,369	$ 1,794,044	$ 1,959,063	$ 2,339,974	$ (2,805,323)	$ 8,480,450
Basic and diluted net income (loss) per common share (in Dollars per share)	$ (0.02)	$ (0.05)	$ (0.23)	$ 0.15	$ 0.13	$ 0.09	$ 0.10	$ 0.12	$ (0.15)	$ 0.45

Subsequent Events (Details)

Subsequent Events (Details) $ in Millions	3 Months Ended
	Mar. 31, 2021USD ($)
GKDML [Member] | Subsequent Event [Member]
Subsequent Events (Details) [Line Items]
Repayments of Related Party Debt	$ 6