Energy Resources 12 10-K19 Mar 202019 FY Annual reportFinancial data

Company Profile

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
Document And Entity Information - USD ($)	Dec. 31, 2019	Mar. 19, 2020	Jun. 30, 2019
Document Information Line Items
Entity Registrant Name	Energy Resources 12, L.P.
Document Type	10-K
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		11,031,579
Entity Public Float			$ 0
Amendment Flag	false
Entity Central Index Key	0001696088
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, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Entity Small Business	true
Entity Emerging Growth Company	true
Entity Shell Company	false
Entity Ex Transition Period	true
Document Annual Report	true
Document Transition Report	false
Entity File Number	000-55916
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	81-4805237
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

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Assets
Cash and cash equivalents	$ 14,834,452	$ 9,682,402
Oil, natural gas and natural gas liquids revenue receivable	8,186,604	3,431,064
Derivative asset	0	644,786
Total Current Assets	23,021,056	13,758,252
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $21,955,397 and $4,889,806, respectively	197,498,771	182,078,667
Derivative asset - noncurrent	0	234,831
Other assets, net	0	1,512,941
Total Assets	220,519,827	197,584,691
Liabilities
Accounts payable and accrued expenses	8,835,537	11,488,175
Due to related parties	217,209	212,117
Derivative liability	207,327	0
Total Current Liabilities	9,260,073	11,700,292
Revolving credit facility	0	39,500,000
Asset retirement obligations	570,795	383,255
Total Liabilities	9,830,868	51,583,547
Partners’ Equity
Limited partners' interest (11,031,579 and 7,857,359 common units issued and outstanding, respectively)	210,689,174	146,001,359
General partner's interest	(215)	(215)
Total Partners’ Equity	210,688,959	146,001,144
Total Liabilities and Partners’ Equity	$ 220,519,827	$ 197,584,691

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Oil and natural gas properties, successful efforts method, accumulated depreciation, depletion and amortization (in Dollars)	$ 21,955,397	$ 4,889,806
Limited partners' interest, common units issued	11,031,579	7,857,359
Limited partners' interest, common units outstanding	11,031,579	7,857,359

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($)	12 Months Ended
Consolidated Statements of Operations - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Revenues
Oil	$ 61,146,651	$ 23,790,225
Natural gas	2,005,423	1,053,135
Natural gas liquids	1,278,743	877,676
Total revenue	64,430,817	25,721,036
Operating costs and expenses
Production expenses	17,027,589	5,694,187
Production taxes	5,772,463	2,293,761
General and administrative expenses	2,323,230	1,614,910
Depreciation, depletion, amortization and accretion	17,203,330	4,928,439
Total operating costs and expenses	42,326,612	14,531,297
Operating income	22,104,205	11,189,739
Interest expense, net	(1,620,953)	(1,703,327)
Loss on extinguishment of debt	(999,172)	0
Gain (loss) on derivatives	(1,143,292)	879,617
Total other expense, net	(3,763,417)	(823,710)
Net income	$ 18,340,788	$ 10,366,029
Basic and diluted net income per common unit (in Dollars per share)	$ 1.92	$ 2.04
Weighted average common units outstanding - basic and diluted (in Shares)	9,555,311	5,091,922

Consolidated Statements of Part

Consolidated Statements of Partners' Equity - USD ($)	Total	Limited Partner [Member]	General Partner [Member]
Balance at Dec. 31, 2017	$ 55,045,527	$ 55,045,742	$ (215)
Balance (in Shares) at Dec. 31, 2017		3,191,231
Net proceeds from issuance of common units	87,634,447	$ 87,634,447
Net proceeds from issuance of common units (in Shares)		4,666,128
Distributions declared and paid to common units	(7,044,859)	$ (7,044,859)
Net income	10,366,029	10,366,029
Balance at Dec. 31, 2018	$ 146,001,144	$ 146,001,359	(215)
Balance (in Shares) at Dec. 31, 2018	7,857,359	7,857,359
Net proceeds from issuance of common units	$ 59,633,446	$ 59,633,446
Net proceeds from issuance of common units (in Shares)		3,174,220
Distributions declared and paid to common units	(13,286,419)	$ (13,286,419)
Net income	18,340,788	18,340,788
Balance at Dec. 31, 2019	$ 210,688,959	$ 210,689,174	$ (215)
Balance (in Shares) at Dec. 31, 2019	11,031,579	11,031,579

Consolidated Statements of Pa_2

Consolidated Statements of Partners' Equity (Parentheticals) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
General Partner [Member]
Distributions declared and paid per unit	$ 1.396164	$ 1.396164

Consolidated Statement of Cash

Consolidated Statement of Cash Flows - USD ($)	12 Months Ended
Consolidated Statement of Cash Flows - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Cash flow from operating activities:
Net income	$ 18,340,788	$ 10,366,029
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion	17,203,330	4,928,439
(Gain) loss on mark-to-market of derivatives	1,086,944	(879,617)
Loss on extinguishment of debt	999,172	0
Non-cash expenses, net	513,770	189,118
Changes in operating assets and liabilities:
Oil, natural gas and natural gas liquids revenue receivable	(4,755,540)	(4,683,138)
Due to related parties	5,092	(346,506)
Accounts payable and accrued expenses	2,692,642	1,256,020
Net cash flow provided by operating activities	36,086,198	10,830,345
Cash flow from investing activities:
Cash paid for acquisition of oil and natural gas properties	(1,367,256)	(161,249,883)
Additions to oil and natural gas properties	(36,408,112)	(5,144,076)
Net cash flow used in investing activities	(37,775,368)	(166,393,959)
Cash flow from financing activities:
Cash paid for loan costs	0	(1,702,059)
Proceeds from term loan	0	25,000,000
Payments on term loan	0	(25,000,000)
Proceeds from advance from member of general partner	0	7,000,000
Payments on advance from member of general partner	0	(7,000,000)
Net proceeds from (payments on) revolving credit facility	(39,500,000)	39,500,000
Net proceeds related to issuance of common units	59,627,639	87,633,206
Distributions paid to limited partners	(13,286,419)	(7,044,859)
Net cash flow provided by financing activities	6,841,220	118,386,288
Increase (decrease) in cash and cash equivalents	5,152,050	(37,177,326)
Cash and cash equivalents, beginning of period	9,682,402	46,859,728
Cash and cash equivalents, end of period	14,834,452	9,682,402
Interest paid	1,170,811	1,557,862
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$ 6,048,081	$ 10,276,836

Partnership Organization

Partnership Organization	12 Months Ended
Partnership Organization	Dec. 31, 2019
Accounting Policies [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]	Note 1. Partnership Organization Energy Resources 12, L.P. (together with its wholly-owned subsidiary, the “Partnership”) was formed as a Delaware limited partnership. The initial capitalization of the Partnership of $1,000 occurred on December 30, 2016. The Partnership began offering common units of limited partner interest (the “common units”) on a best-efforts basis on May 17, 2017, the date the Securities and Exchange Commission (“SEC”) declared the offering effective. As of July 25, 2017, the Partnership completed the sale of the minimum offering of 1,315,790 common units. The subscribers to the common units were admitted as Limited Partners of the Partnership at the initial closing of the offering, and the Partnership admitted additional Limited Partners monthly through the completion of its offering on October 24, 2019. The Partnership sold approximately 11.0 million common units for gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million. The proceeds from the sale of the common units have been used to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties. As of December 31, 2019, the Partnership owned an approximate 5.8% non-operated working interest in 332 currently producing wells, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”). The Partnership also owns an estimated approximate 2% non-operated working interest in 20 wells in various stages of the drilling and completion process, and possible future development locations in the Bakken Assets. The Bakken Assets, which are a part of the Bakken shale formation in the Greater Williston Basin, are operated by 14 third-party operators on behalf of the Partnership and other working interest owners. The general partner of the Partnership is Energy Resources 12 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership. David Lerner Associates, Inc. (the “Managing Dealer”), was the dealer manager for the offering of the common units. The Partnership’s fiscal year ends on December 31.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2019
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	Note 2. Summary of Significant Accounting Policies Basis of Presentation The accompanying financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”). Cash and Cash Equivalents Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits. Property and Depreciation, Depletion and Amortization The Partnership accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities. 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 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, including appropriate escalators, 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 of the Partnership’s accounts receivable are 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, 2019, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible. For the year ended December 31, 2019, the Partnership’s oil, natural gas and NGL sales were through 14 operators and approximately 91% of the Partnership’s total revenue was generated through sales by four operators. 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. Accounting for Asset Retirement Obligations 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, 2019 and 2018 relating to the Partnership’s asset retirement obligations: Balance as of January 1, 2018 $ - Liabilities incurred on February 1, 2018 (Acquisition No. 1) 133,155 Liabilities incurred on August 31, 2018 (Acquisition No. 2) 170,823 Well additions 40,644 Accretion 38,633 Balance as of December 31, 2018 383,255 Well additions 49,801 Accretion 20,607 Revisions (1) 117,132 Balance as of December 31, 2019 $ 570,795 (1) During 2019, six wells owned by the Partnership were shut-in by the Partnership’s operators. Revisions to the asset retirement obligations represent the full accretion of these six wells due to the reduction in the estimated life of the wells. 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, 2019 and 2018, there were no such costs accrued. Use of Estimates The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. 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 Revenues associated with the sales of crude oil, natural gas, and natural gas liquids are recognized at the point in time when the customer obtains control of the asset. In evaluating when a customer has control of the asset, we primarily consider whether the transfer of legal title and physical delivery has occurred, whether the customer has significant risks and rewards of ownership, and whether the customer has accepted delivery and a right to payment exists. 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. 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. Net Income per Common Unit Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the years ended December 31, 2019 and 2018. As a result, basic and diluted outstanding common units were the same. The Incentive Distribution Rights (as discussed in Note 7) are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 7) would occur. Recently Adopted Accounting Standards In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets as right-of-use assets and lease liabilities. The Partnership concluded there is no material impact to the Partnership’s consolidated financial statements and related disclosures. The Partnership adopted this standard as of January 1, 2019.

Oil and Gas Investments

Oil and Gas Investments	12 Months Ended
Oil and Gas Investments	Dec. 31, 2019
Oil and Gas Property [Abstract]
Oil and Gas Properties [Text Block]	Note 3. Oil and Gas Investments On February 1, 2018, the Partnership completed its first purchase (“Acquisition No. 1”) in the Bakken Assets for approximately $87.5 million, and customary adjustments and capitalized transaction costs. The Partnership adjusted the purchase price of Acquisition No. 1, as set forth in the purchase agreement, to reflect the customary settlement of operating revenues and expenses received or paid by the seller on the Partnership’s behalf between the effective date of September 1, 2017 and the closing date of February 1, 2018. The net impact of the purchase price adjustments was a decreased to the purchase price of the asset of approximately $2.1 million. The Partnership accounted for Acquisition No. 1 as a purchase of a group of similar assets, and therefore capitalized transaction costs associated with this acquisition. These acquisition-related costs included, but were not limited to, fees for advisory and consulting (discussed below), due diligence, legal, accounting, engineering and environmental review services. The capitalized acquisition-related costs for Acquisition No. 1 totaled approximately $5.0 million. The Partnership also recorded an asset retirement obligation liability of approximately $0.1 million in conjunction with this acquisition. Acquisition No. 1 was funded using proceeds from the Partnership’s best-efforts offering, proceeds from an unsecured term loan of $25.0 million and an advance from a member of the General Partner of $7.0 million. The term loan (discussed below in Note 4. Debt) was repaid in full and extinguished in December 2018. The advance from a member of the General Partner was repaid in full in May 2018. The advance did not bear interest and the member of the General Partner did not receive any compensation for the advance. On August 31, 2018, the Partnership completed its second purchase (“Acquisition No. 2”) of an additional non-operated working interest in the Bakken Assets for approximately $82.5 million, and customary adjustments and capitalized transaction costs. The Partnership adjusted the purchase price of Acquisition No. 2 to reflect the customary settlement of operating revenues and expenses received or paid by the seller on the Partnership’s behalf between the effective date of March 1, 2018 and the closing date of August 31, 2018. The net impact of the purchase price adjustments was a decrease to the purchase price of the asset of approximately $4.3 million. The Partnership accounted for Acquisition No. 2 as a purchase of a group of similar assets, and therefore capitalized transaction costs associated with this acquisition. The capitalized acquisition-related costs, which included but were not limited to those listed above, for Acquisition No. 2 totaled approximately $2.9 million. The Partnership also recorded an asset retirement obligation liability of approximately $0.2 million in conjunction with this acquisition. Acquisition No. 2 was funded using proceeds from the Partnership’s best-efforts offering and proceeds from a line of credit of $60.0 million (discussed below in Note 4. Debt). The credit facility was terminated and extinguished in November 2019. In November 2017, the Partnership engaged Regional Energy Investors, LP (“REI”) to perform advisory and consulting services, including supporting the Partnership through closing and post-closing of Acquisition No. 1. In the first quarter of 2018, the Partnership paid REI a total of approximately $5.3 million for its advisory and consulting services related to Acquisition No. 1. Of the $5.3 million paid to REI, approximately $4.7 million of these services related to Acquisition No. 1 were capitalized as part of the acquisition costs described above. In June 2018, the Partnership re-engaged REI to perform advisory and consulting services and support the Partnership through closing and post-closing of Acquisition No. 2, including assistance with due diligence and obtaining financing for Acquisition No. 2. In the third quarter of 2018, the Partnership paid REI a total of $4.1 million for its advisory and consulting services related to Acquisition No. 2. Of the $4.1 million, approximately $2.7 million of these services related to Acquisition No. 2 were capitalized as part of the acquisition costs described above. The remaining $1.4 million was capitalized as deferred loan costs and were being amortized over the life of the revolving credit facility described in Note 4. Debt. Under the advisory and administration agreements (the “Agreements”) with REI, REI was also entitled to a fee of 5% of the gross sales price in the event the Partnership disposed of any or all of the Bakken Assets, if surplus funds are available after Payout to the holders of the Partnership’s common units, as defined in Note 7. Capital Contribution and Partners’ Equity below. On December 28, 2018, the Partnership terminated the Agreements with REI, which extinguished any potential fee upon sale of certain of the Partnership’s assets as was required under the Agreements. At the time of the extinguishment, the payment of a fee was not probable and there was no value to the rights owned by REI. In connection with the termination, the General Partner issued 500 of its Class B Units to each of Pope Energy Investors, LP and CFK Energy, LLC. The General Partner received $250 from each of Pope Energy Investors, LP and CFK Energy, LLC for this transaction. The General Partner Class B Units are non-voting and participate in 50% of any distributions by the General Partner from proceeds of its Incentive Distribution Rights, after Payout and the Dealer Manager Incentive Fees as described in Note 7. Capital Contribution and Partners’ Equity below. REI is owned by entities that are controlled by Anthony F. Keating, III, Co-Chief Operating Officer of Energy 11 GP, LLC, and Michael J. Mallick, Co-Chief Operating Officer of Energy 11 GP, LLC. Glade M. Knight and David S. McKenney are the Chief Executive Officer and Chief Financial Officer, respectively, of Energy 11 GP, LLC as well as the Chief Executive Officer and Chief Financial Officer, respectively, of the General Partner. In addition, CFK Energy, LLC and Pope Energy Investors, LP are owned by entities controlled by Messrs. Keating and Mallick, respectively. See Note 8. Related Parties below for additional information. The following unaudited pro forma financial information for the year ended December 31, 2018 has been prepared as if Acquisitions No.1 and No. 2 of the Bakken Assets had occurred on January 1, 2018. The unaudited pro forma financial information was derived from the historical statements of operations of the Partnership and the historical financial statements of the sellers of the Bakken Assets. The unaudited pro forma financial information does not purport to be indicative of the results of operations that would have occurred had the acquisition of the Bakken Assets and related financings occurred on the basis assumed above, nor is such information indicative of the Partnership’s expected future results of operations. Year Ended (Unaudited) Revenues $ 43,067,089 Net income $ 20,511,627 As of December 31, 2019, the Partnership’s ownership of the Bakken Assets consisted of an approximate 5.8% non-operated working interest in 332 currently producing wells, and an estimated approximate 2% non-operated working interest in 20 wells in various stages of the drilling and completion process. From September 1, 2017, the effective date of Acquisition No. 1, to December 31, 2019, the Partnership has participated in the drilling of 153 wells, of which 133 have been completed and 20 wells are in various stages of completion at December 31, 2019. The Partnership incurred approximately $32.2 million and $15.4 million in capital drilling and completion costs for the year ended December 31, 2019 and for the period from February 1, 2018 to December 31, 2018, respectively. The Partnership anticipates approximately $1.0 million of capital expenditures to be incurred in first half of 2020 to complete the 20 wells in various stages of completion at December 31, 2019; however, actual capital expenditures incurred may exceed this range. Non-consent wells Pursuant to the terms of the American Association of Professional Landmen Model Form Operating Agreement or North Dakota statute, each of which may govern operations between an operator and a non-operated working interest owner (“interest owner”), like the Partnership, an operator must notify an interest owner of its intention to drill a new well through submittal of a formal well proposal. The interest owner has the option to elect to participate in the drilling, completion and operating of the well and pay its proportionate share of all costs, or the interest owner may elect to non-consent the proposed well under the terms of the operating agreement or statute and bear no cost. If the interest owner elects to non-consent the proposed well, the interest owner is not obligated to pay any portion of the drilling, completion and operating expenses; however, the interest owner is then subject to a non-consent penalty under the terms of the operating agreement or North Dakota statute. Through its 2018 acquisitions, the Partnership acquired 59 wells designated as non-consent wells, whereby a previous interest owner did not consent to participate in the drilling and completion of those wells. As a result, the Partnership is currently subject to non-consent penalties ranging from 200%-400%, meaning in general terms, the Partnership will remain in non-consent status and will not receive any revenue from these wells until the wells have satisfied the contractual or statutory penalties of 2-4 times payout of the expenses related to drilling, completion and operating the well. The Partnership may receive revenue or be responsible for operating and/or abandonment costs from all or a portion of these wells if the wells generate enough revenue to exceed the non-consent penalties described above.

Debt

Debt	12 Months Ended
Debt	Dec. 31, 2019
Debt Disclosure [Abstract]
Debt Disclosure [Text Block]	Note 4. Debt On January 16, 2018, the Partnership entered into a loan agreement with Bank of America, N.A. (“BOA”), which provides for an unsecured term loan (the “Term Loan”) of $25 million. The Term Loan was paid in full and extinguished in December 2018. Interest was payable monthly, and the Term Loan bore interest at a variable rate based on the London Inter-Bank Offered Rate (LIBOR) plus a margin of 2.00%. The Term Loan proceeds were used in closing on Acquisition No. 1, as described above. Glade M. Knight and David S. McKenney, the General Partner’s Chief Executive Officer and Chief Financial Officer, respectively, had guaranteed repayment of the Term Loan and did not receive any consideration in exchange for providing this guarantee. On August 31, 2018, the Partnership entered into a loan agreement (“Loan Agreement”) with Simmons Bank, as administrative agent and the lenders party thereto, which provided for a revolving credit facility (“Credit Facility”) with an initial commitment amount of $60 million. On November 26, 2019, the Partnership elected to terminate the Loan Agreement, which extinguished the Credit Facility and terminated the related mortgage secured by the Partnership’s non-operating working interests in the Bakken Assets. At the date of termination, the Partnership had no outstanding borrowings on the Loan Agreement. Early termination of the Loan Agreement did not require payment of any early termination penalties. The interest rate was equal to LIBOR plus a margin ranging from 2.75% to 3.75%, depending upon the Partnership’s borrowing base utilization, as calculated under the terms of the Loan Agreement. The Credit Facility proceeds of $60.0 million borrowed at closing were used to fund the purchase of Acquisition No. 2, as described above, and pay closing costs. In conjunction with Acquisition No. 2 and the closing on the Loan Agreement, the Partnership capitalized $1.7 million of deferred loan costs, and the Partnership was amortizing these loan costs over the life of the Credit Facility to its maturity date of August 31, 2021. In November 2019, upon the termination of the Credit Facility, the Partnership expensed the remaining unamortized deferred loan costs and recorded a Loss on extinguishment of debt of $1.0 million on the Partnership’s consolidated statement of operations. As of December 31, 2018, the Partnership’s outstanding balance on its revolving credit facility was $39.5 million, which approximated its fair market value. The Partnership estimated the fair value of its note payable by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
Fair Value of Financial Instruments	Dec. 31, 2019
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, 2019 and 2018, 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, 2019 and 2018. Year Ended December 31, 2019 Quoted Prices in Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current liabilities $ - $ (207,327 ) $ - Total $ - $ (207,327 ) $ - Year Ended December 31, 2018 Quoted Prices in Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current assets $ - $ 644,786 $ - Commodity derivatives - noncurrent assets - 234,831 - Total $ - $ 879,617 $ - The Level 2 instruments presented in the table above consist of Partnership’s costless collar commodity derivative instruments. The fair value of the Partnership’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The fair value of the commodity derivatives noted above are included in the Partnership’s consolidated balance sheet as Derivative liability at December 31, 2019 and Derivative asset at December 31, 2018. 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, oil, natural gas and natural gas liquids revenue receivable, accounts payable and accrued expenses reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments. In addition, see Note 4. Debt for the fair value discussion on the Partnership’s debt.

Risk Management

Risk Management	12 Months Ended
Risk Management	Dec. 31, 2019
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. In December 2018 and March 2019, the Partnership entered into derivative contracts to hedge a portion of the Partnership’s anticipated future oil and gas production through September 2020 with two counterparties to reduce the effect of volatility in commodity price changes and provide a base level of cash flow from operations. The Partnership has used costless collar derivative contracts, which establish floor and ceiling prices on future anticipated oil production. While the use of these derivative instruments limits the downside risk of adverse price movement, they may also limit future revenues from favorable price movement. The Partnership did not pay or receive a premium related to the costless collar agreements. The contracts are settled monthly. All derivative instruments are recorded on the Partnership’s balance sheet as assets or liabilities measured at fair value. As of December 31, 2019, the Partnership’s derivative instruments with its remaining counterparty were in a loss position; therefore, a liability of approximately $0.2 million, which approximates its fair value, was recognized as a Derivative liability (current) on the Partnership’s consolidated balance sheet as of December 31, 2019. As of December 31, 2018, the Partnership’s derivative instruments were in a net gain position; therefore, an asset of approximately $0.9 million, which approximates its fair value, was recognized as a Derivative asset (current and noncurrent) on the Partnership’s consolidated balance sheet as of December 31, 2018. The fair value of the Derivative liability at December 31, 2019 and Derivative asset at December 31, 2018 was determined based on Level 2 inputs as defined under the fair value hierarchy. 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 performs 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 considers that it is of substantial credit quality and has 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 did not designate its derivative instruments as hedges for accounting purposes and did not enter into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The following table presents settlements on matured derivative instruments and non-cash gains or losses on open derivative instruments for the years ended December 31, 2019 and 2018. The net settlement loss on matured derivatives for the year ended December 31, 2019 reflects gains and losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price, and also includes the $22,500 gain on certain contracts that were terminated. Non-cash gains or losses below represent the change in fair value of derivative instruments which were held at period-end. Year Ended Year Ended Settlement loss on matured derivatives, net $ (56,348 ) $ - Gain (loss) on mark-to-market of derivatives (1,086,944 ) 879,617 Gain (loss) on derivatives $ (1,143,292 ) $ 879,617 The following table reflects the open costless collar instruments as of December 31, 2019. Settlement Period Basis Oil (Barrels) Floor / Ceiling Prices ($) Fair Value of Liability at 01/01/20 - 06/30/20 NYMEX 107,000 45.00 / 61.20 (207,327 ) The Partnership’s outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (“ISDA”) entered into with the counterparties. 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 use of derivative instruments involves the risk that the Partnership’s counterparties will be unable to meet the financial terms of such instruments. The Partnership has netting arrangements with its counterparties that provide for offsetting payables against receivables from separate derivative instruments, which allow these assets and liabilities to be netted on the Partnership’s consolidated balance sheet.

Capital Contribution and Partne

Capital Contribution and Partners' Equity	12 Months Ended
Capital Contribution and Partners' Equity	Dec. 31, 2019
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 has been and will be 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 as of the close of business on October 24, 2019. As of the conclusion of the offering, the Partnership had completed the sale of approximately 11.0 million common units for total gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million. Under the agreement with the Managing Dealer, the Managing Dealer received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering as outlined in the prospectus based on the performance of the Partnership. Based on the common units sold through the conclusion of the offering on October 24, 2019, the Dealer Manager Incentive Fees are approximately $8.7 million, subject to Payout (defined below). Prior to “Payout,” which is defined below, all 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 and will not pay the Dealer Manager Incentive Fees to the Managing Dealer, until Payout occurs. The Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”) provides that “Payout”, which is defined below, 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, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest. ● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest. All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above. For the year ended December 31, 2019, the Partnership paid distributions of $1.396164 per common unit, or $13.3 million. For the year ended December 31, 2018, the Partnership paid distributions of $1.396164 per common unit, or $7.0 million.

Related Parties

Related Parties	12 Months Ended
Related Parties	Dec. 31, 2019
Related Party Transactions [Abstract]
Related Party Transactions Disclosure [Text Block]	Note 8. Related Parties 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. The Partnership will reimburse the General Partner for any costs incurred by the General Partner for certain expenses, which include costs for organizing the Partnership and costs incurred in the offering of the common units. The Partnership has also agreed to pay the General Partner an advisory fee to manage the day-to-day affairs of the Partnership, including serving as an investment advisor and consultant in connection with the acquisition, development, operation and disposition of oil and gas properties and other assets of the Partnership. In accordance with the limited partner agreement, subsequent to the Partnership’s first asset purchase, which occurred on February 1, 2018, the Partnership is required to pay quarterly an annual fee of 0.5% of the total gross equity proceeds raised by the Partnership in its best-efforts offering. Based upon the total gross equity proceeds as of December 31, 2019, the management fee paid to the General Partner for the year ended December 31, 2019 was approximately $1.0 million. The management fee paid to the General Partner for the year ended December 31, 2018 was approximately $537,000. The management fee paid to the General Partner is included in General and administrative expenses on the consolidated statements of operations. The Partnership also will reimburse the General Partner for certain general and administrative costs. For the years ended December 31, 2019 and 2018, approximately $414,000 and $402,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership, respectively. At December 31, 2019 and 2018, approximately $133,000 and $135,000, respectively, was due to a member of the General Partner and is included in Due to related parties in the consolidated balance sheets. As discussed in Note 3. Oil and Gas Investments, in January 2018, the Partnership received an advance of $7.0 million from a member of the General Partner to partially fund Acquisition No. 1. The Partnership repaid a member of the General Partner in full in May 2018. The advance did not bear interest and the member of the General Partner did not receive any compensation for the advance. As discussed in Note 4. Debt, the Chief Executive Officer and Chief Financial Officer of the Partnership’s General Partner had guaranteed repayment of the Term Loan with Bank of America. Neither the Chief Executive Officer nor the Chief Financial Officer received any consideration in exchange for providing the guarantee on either loan. The Chief Executive Officer and Chief Financial Officer of the Partnership’s General Partner are also the Chief Executive Officer and Chief Financial Officer of Energy 11 GP, LLC, the general partner of Energy 11, L.P. (“Energy 11”), a limited partnership that also invests in producing and non-producing oil and gas properties on-shore in the United States. On January 31, 2018, the Partnership entered into a cost sharing agreement with Energy 11 that gives the Partnership access to Energy 11’s personnel and administrative resources, including accounting, asset management and other day-to-day management support. The shared day-to-day costs are split evenly between the two partnerships and any direct third-party costs are paid by the party receiving the services. The shared costs are based on actual costs incurred with no mark-up or profit to the Partnership. The agreement may be terminated at any time by either party upon 60 days written notice. The cost sharing agreement reduces the costs to the Partnership for accounting and asset management services provided through a member of the General Partner. In addition to certain accounting and asset management resources, the Partnership and Energy 11 share the rent expense for leased office space (leased from an affiliate of a member of the general partner of Energy 11) in Oklahoma City, Oklahoma along with the compensation due to the President of Energy 11’s general partner. For the years ended December 31, 2019 and 2018, approximately $285,000 and $252,000, respectively, of expenses subject to the cost sharing agreement were incurred by the Partnership and have been or will be reimbursed to Energy 11. At December 31, 2019 and 2018, approximately $85,000 and $77,000, respectively, was due from the Partnership to Energy 11 and is included in Due to related parties in the consolidated balance sheets. As discussed in Note 3. Oil and Gas Investments, in November 2017 and June 2018, the Partnership engaged REI to perform advisory and consulting services, including supporting the Partnership through closing, financing and post-closing on Acquisitions No. 1 and No. 2. REI is owned by entities that are controlled by Messrs. Keating and Mallick and has engaged Cliff Merritt, President of Energy 11 GP, LLC, to support its operations. With the fees received from the Partnership for advisory and consulting services, REI paid certain personnel utilized by Energy 11 and the Partnership, including Mr. Merritt, an aggregate total of $500,000. Under the advisory and administration agreements (the “Agreements”) with REI, REI was also entitled to a fee of 5% of the gross sales price in the event the Partnership disposes any or all of the Bakken Assets, if surplus funds were available after Payout to the holders of the Partnership’s common units, as defined in Note 7. Capital Contribution and Partners’ Equity above. On December 28, 2018, the Partnership terminated the Agreements with REI, which extinguished any potential fee upon sale of certain of the Partnership’s assets as was required under the Agreements. At the time of the extinguishment, the payment of a fee was not probable and there was no value to the rights owned by REI. In connection with the termination, the General Partner issued 500 of its Class B Units each to entities owned and controlled by Messrs. Keating and Mallick in exchange for $500 total. The General Partner Class B Units are non-voting and participate in 50% of any distributions by the General Partner from proceeds of its Incentive Distribution Rights, after Payout and the Dealer Manager Incentive Fees as described in Note 7. Capital Contribution and Partners’ Equity above.

Supplementary Information on Oi

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)	12 Months Ended
	Dec. 31, 2019
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 and Costs Incurred The aggregate amount of capitalized costs of oil, natural gas and NGL properties and related accumulated depreciation, depletion and amortization as of December 31, 2019 and 2018 is as follows: 2019 2018 Producing properties $ 148,370,378 $ 116,487,297 Non-producing 71,083,790 70,481,176 219,454,168 186,968,473 Accumulated depreciation, depletion and amortization (21,955,397 ) (4,889,806 ) Net capitalized costs $ 197,498,771 $ 182,078,667 For the years ended December 31, 2019 and 2018, the Partnership incurred the following costs in oil and natural gas producing activities: 2019 2018 Property acquisition costs $ 256,536 $ 171,506,918 Development costs 32,229,159 15,461,555 $ 32,485,695 $ 186,968,473 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, 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, 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) January 1, 2018 - - - - Acquisition, February 1, 2018 (1) 9,717,859 4,957,715 712,913 11,257,058 Acquisition, August 31, 2018 (2) 10,298,392 4,779,497 696,600 11,791,575 Extensions, discoveries and other additions - - - - Revisions of previous estimates (3) 653,770 545,023 124,901 869,507 Production (February 1, 2018 to December 31, 2018) (405,581 ) (319,445 ) (42,329 ) (501,150 ) December 31, 2018 20,264,440 9,962,790 1,492,085 23,416,990 Acquisition - - - - Extensions, discoveries and other additions (4) 94,703 50,978 7,664 110,863 Revisions of previous estimates (5) (1,047,353 ) (395,183 ) 50,422 (1,062,795 ) Production (1,129,951 ) (849,047 ) (126,760 ) (1,398,219 ) December 31, 2019 18,181,839 8,769,538 1,423,411 21,066,839 (1) The Partnership acquired 11,257 MBOE of reserves attributable to producing developed wells and PUDs in conjunction with Acquisition No. 1 (see Note 3. Oil and Gas Investments). (2) The Partnership acquired 11,792 MBOE of reserves attributable to producing developed wells and PUDs in conjunction with Acquisition No. 2 (see Note 3. Oil and Gas Investments). (3) Revisions to previous estimates increased proved reserves by a net amount of 870 MBOE. These revisions result from 1,248 MBOE of upward adjustments attributable to changes in the future drill schedule and 7 MBOE of upward adjustments caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2018 to the drill schedules and oil, natural gas and NGL prices at the dates of Acquisitions No. 1 and No. 2, which were partially offset by 385 MBOE of downward adjustments related to well performance post acquisition-closing dates. (4) In 2019, extensions, discoveries and other additions of 111 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets. (5) Revisions to previous estimates decreased proved reserves by 1,063 MBOE. These revisions result from 804 MBOE of downward adjustments attributable to well performance, 246 MBOE of downward adjustments attributable to changes in the future drill schedule and 13 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. 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, 2019 were $55.69 per barrel of oil and $2.58 per MMcf of natural gas, before price differentials. Including the effect of average price differential adjustments, the average realized prices used in computing the Partnership’s reserves as of December 31, 2019 were $49.42 per barrel of oil, $(1.61) per MMcf of natural gas and $2.74 per barrel of NGL. The oil and natural gas prices used in computing the Partnership’s reserves as of December 31, 2018 were $65.56 per barrel of oil and $3.10 per MMcf of natural gas, before price differentials. Including the effect of average price differential adjustments, the average realized prices used in computing the Partnership’s reserves as of December 31, 2018 were $59.56 per barrel of oil, $2.43 per MMcf of natural gas and $20.25 per barrel of NGL. Net quantities of proved developed and proved undeveloped reserves at December 31, 2019 and 2018 are summarized in the table below. Oil Natural Gas NGLs (Bbls) (Mcf) (Bbls) Total (BOE) Proved developed reserves: December 31, 2018 6,982,216 4,126,780 686,765 8,356,778 December 31, 2019 6,986,035 4,733,090 774,311 8,549,194 Proved undeveloped reserves: December 31, 2018 13,282,224 5,836,010 805,320 15,060,212 December 31, 2019 11,195,804 4,036,448 649,100 12,517,645 The following details the changes in proved undeveloped reserves (PUD) for 2018 and 2019 (in BOE): BOE Proved undeveloped reserves, beginning - Proved undeveloped reserves acquired, February 1, 2018 (1) 8,427,708 Proved undeveloped reserves acquired, August 31, 2018 (2) 7,279,846 Revisions of previous estimates (3) 1,252,630 Conversion to proved developed reserves (4) (1,899,972 ) Proved undeveloped reserves, December 31, 2018 15,060,212 Revisions of previous estimates (5) (401,688 ) Extensions, discoveries and other additions (6) 52,367 Conversion to proved developed reserves (7) (2,193,246 ) Proved undeveloped reserves acquired - Proved undeveloped reserves, December 31, 2019 12,517,645 (1) The Partnership acquired 8,428 MBOE attributable to PUDs in conjunction with Acquisition No. 1 (see Note 3. Oil and Gas Investments). (2) The Partnership acquired 7,280 MBOE attributable to PUDs in conjunction with Acquisition No. 2 (see Note 3. Oil and Gas Investments). (3) Revisions to previous estimates, from the respective closing dates for Acquisitions No. 1 and No. 2, increased PUDs by a net amount of 1,253 MBOE. These revisions result from 1,249 MBOE of upward adjustments attributable to changes in the future drill schedule and 4 MBOE of upward adjustments caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2018 to oil, natural gas and NGL prices at the dates of Acquisitions No. 1 and No. 2. There were no adjustments related to well performance. (4) Since the Partnership completed its first acquisition, 56 wells have either been completed or are in-process by the Partnership’s operators (the in-process wells converted were substantially complete and required relatively minor costs to bring to production). This development led to 1,900 MBOE of PUDs being converted to proved developed reserves from February 1, 2018 to December 31, 2018. (5) The annual review of the PUDs resulted in a negative revision of approximately 402 MBOE. This revision was the result of 246 MBOE of downward adjustments attributable to changes in the future drill schedule, 147 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 9 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. (6) In 2019, extensions, discoveries and other additions of 52 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets. (7) The Partnership converted 38 wells to proved developed reserves during 2019 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 2,193 MBOE. 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. 2019 2018 (in thousands) (in thousands) Future cash inflows $ 888,271 $ 1,256,302 Future production costs (244,165 ) (342,615 ) Future development costs (88,056 ) (102,210 ) Future net cash flows 556,050 811,477 10% annual discount (312,901 ) (440,982 ) Standardized measure of discounted future net cash flows $ 243,149 $ 370,495 Changes in the standardized measure of discounted future net cash flows are as follows: 2019 2018 (in thousands) (in thousands) Standardized measure at beginning of period $ 370,495 $ - Changes resulting from: Acquisition of reserves - 273,568 Extensions, discoveries and other additions 1,093 - Sales of oil, natural gas and NGLs, net of production costs (41,631 ) (17,733 ) Net changes in prices and production costs (97,776 ) 71,883 Development costs incurred during the period 32,229 15,462 Revisions to previous estimates (40,287 ) 11,491 Accretion of discount 37,101 15,174 Change in estimated future development costs (18,075 ) 650 Standardized measure of discounted future net cash flows $ 243,149 $ 370,495

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
Quarterly Financial Data (Unaudited)	Dec. 31, 2019
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, 2019 and 2018. Net income per common unit is non-additive in comparison to net income per common unit for each year due to the timing and size of the Partnership’s common unit issuances. 2019 First Quarter Second Quarter Third Quarter Fourth Quarter Total revenue $ 11,361,830 $ 18,832,114 $ 15,883,884 $ 18,352,989 Net income $ 1,641,943 $ 8,277,089 $ 5,680,657 $ 2,741,099 Basic and diluted net income per common share $ 0.20 $ 0.92 $ 0.56 $ 0.25 2018 (1) First Quarter Second Quarter Third Quarter Fourth Quarter Total revenue $ 3,497,079 $ 7,531,096 $ 5,503,706 $ 9,189,155 Net income $ 1,288,325 $ 3,400,535 $ 2,087,725 $ 3,589,444 Basic and diluted net income per common share $ 0.38 $ 0.82 $ 0.37 $ 0.51 (1) The Partnership did not acquire its first operating asset until February 1, 2018.

Subsequent Events

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2019
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Note 11. Subsequent Events In January 2020, the Partnership declared and paid $1.5 million, or $0.134247 per outstanding common unit, in distributions to its holders of common units. In February 2020, the Partnership declared and paid $1.2 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

Accounting Policies, by Policy

Accounting Policies, by Policy (Policies)	12 Months Ended
Accounting Policies, by Policy (Policies)	Dec. 31, 2019
Accounting Policies [Abstract]
Basis of Accounting, Policy [Policy Text Block]	Basis of Presentation The accompanying financial statements of the Partnership have been prepared in accordance with United States generally accepted accounting principles (“US GAAP”).
Cash and Cash Equivalents, Policy [Policy Text Block]	Cash and Cash Equivalents Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits.
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.
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 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, including appropriate escalators, 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
Asset Retirement Obligation [Policy Text Block]	Accounting for Asset Retirement Obligations 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, 2019 and 2018 relating to the Partnership’s asset retirement obligations: Balance as of January 1, 2018 $ - Liabilities incurred on February 1, 2018 (Acquisition No. 1) 133,155 Liabilities incurred on August 31, 2018 (Acquisition No. 2) 170,823 Well additions 40,644 Accretion 38,633 Balance as of December 31, 2018 383,255 Well additions 49,801 Accretion 20,607 Revisions (1) 117,132 Balance as of December 31, 2019 $ 570,795 (1) During 2019, six wells owned by the Partnership were shut-in by the Partnership’s operators. Revisions to the asset retirement obligations represent the full accretion of these six wells due to the reduction in the estimated life of the wells.
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, 2019 and 2018, there were no such costs accrued.
Use of Estimates, Policy [Policy Text Block]	Use of Estimates The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. 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 Revenues associated with the sales of crude oil, natural gas, and natural gas liquids are recognized at the point in time when the customer obtains control of the asset. In evaluating when a customer has control of the asset, we primarily consider whether the transfer of legal title and physical delivery has occurred, whether the customer has significant risks and rewards of ownership, and whether the customer has accepted delivery and a right to payment exists. 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.
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.
Earnings Per Share, Policy [Policy Text Block]	Net Income per Common Unit Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the years ended December 31, 2019 and 2018. As a result, basic and diluted outstanding common units were the same. The Incentive Distribution Rights (as discussed in Note 7) are not included in net income 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 February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, Leases (Topic 842), which amends the existing accounting standards for lease accounting, including requiring lessees to recognize most leases on their balance sheets as right-of-use assets and lease liabilities. The Partnership concluded there is no material impact to the Partnership’s consolidated financial statements and related disclosures. The Partnership adopted this standard as of January 1, 2019.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
Summary of Significant Accounting Policies (Tables)	Dec. 31, 2019
Accounting Policies [Abstract]
Schedule of Asset Retirement Obligations [Table Text Block]	The following table shows the activity for the years ended December 31, 2019 and 2018 relating to the Partnership’s asset retirement obligations: Balance as of January 1, 2018 $ - Liabilities incurred on February 1, 2018 (Acquisition No. 1) 133,155 Liabilities incurred on August 31, 2018 (Acquisition No. 2) 170,823 Well additions 40,644 Accretion 38,633 Balance as of December 31, 2018 383,255 Well additions 49,801 Accretion 20,607 Revisions (1) 117,132 Balance as of December 31, 2019 $ 570,795

Oil and Gas Investments (Tables

Oil and Gas Investments (Tables)	12 Months Ended
Oil and Gas Investments (Tables)	Dec. 31, 2019
Oil and Gas Property [Abstract]
Business Acquisition, Pro Forma Information [Table Text Block]	The following unaudited pro forma financial information for the year ended December 31, 2018 has been prepared as if Acquisitions No.1 and No. 2 of the Bakken Assets had occurred on January 1, 2018. The unaudited pro forma financial information was derived from the historical statements of operations of the Partnership and the historical financial statements of the sellers of the Bakken Assets. The unaudited pro forma financial information does not purport to be indicative of the results of operations that would have occurred had the acquisition of the Bakken Assets and related financings occurred on the basis assumed above, nor is such information indicative of the Partnership’s expected future results of operations. Year Ended (Unaudited) Revenues $ 43,067,089 Net income $ 20,511,627

Fair Value of Financial Instr_2

Fair Value of Financial Instruments (Tables)	12 Months Ended
Fair Value of Financial Instruments (Tables)	Dec. 31, 2019
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, 2019 and 2018. Year Ended December 31, 2019 Quoted Prices in Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current liabilities $ - $ (207,327 ) $ - Total $ - $ (207,327 ) $ - Year Ended December 31, 2018 Quoted Prices in Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current assets $ - $ 644,786 $ - Commodity derivatives - noncurrent assets - 234,831 - Total $ - $ 879,617 $ -

Risk Management (Tables)

Risk Management (Tables)	12 Months Ended
Risk Management (Tables)	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments, Gain (Loss) [Table Text Block]	The Partnership did not designate its derivative instruments as hedges for accounting purposes and did not enter into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The following table presents settlements on matured derivative instruments and non-cash gains or losses on open derivative instruments for the years ended December 31, 2019 and 2018. The net settlement loss on matured derivatives for the year ended December 31, 2019 reflects gains and losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price, and also includes the $22,500 gain on certain contracts that were terminated. Non-cash gains or losses below represent the change in fair value of derivative instruments which were held at period-end. Year Ended Year Ended Settlement loss on matured derivatives, net $ (56,348 ) $ - Gain (loss) on mark-to-market of derivatives (1,086,944 ) 879,617 Gain (loss) on derivatives $ (1,143,292 ) $ 879,617
Schedule of Derivative Instruments [Table Text Block]	The following table reflects the open costless collar instruments as of December 31, 2019. Settlement Period Basis Oil (Barrels) Floor / Ceiling Prices ($) Fair Value of Liability at 01/01/20 - 06/30/20 NYMEX 107,000 45.00 / 61.20 (207,327 )

Supplementary Information on _2

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
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, 2019 and 2018 is as follows: 2019 2018 Producing properties $ 148,370,378 $ 116,487,297 Non-producing 71,083,790 70,481,176 219,454,168 186,968,473 Accumulated depreciation, depletion and amortization (21,955,397 ) (4,889,806 ) Net capitalized costs $ 197,498,771 $ 182,078,667
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]	For the years ended December 31, 2019 and 2018, the Partnership incurred the following costs in oil and natural gas producing activities: 2019 2018 Property acquisition costs $ 256,536 $ 171,506,918 Development costs 32,229,159 15,461,555 $ 32,485,695 $ 186,968,473
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) January 1, 2018 - - - - Acquisition, February 1, 2018 (1) 9,717,859 4,957,715 712,913 11,257,058 Acquisition, August 31, 2018 (2) 10,298,392 4,779,497 696,600 11,791,575 Extensions, discoveries and other additions - - - - Revisions of previous estimates (3) 653,770 545,023 124,901 869,507 Production (February 1, 2018 to December 31, 2018) (405,581 ) (319,445 ) (42,329 ) (501,150 ) December 31, 2018 20,264,440 9,962,790 1,492,085 23,416,990 Acquisition - - - - Extensions, discoveries and other additions (4) 94,703 50,978 7,664 110,863 Revisions of previous estimates (5) (1,047,353 ) (395,183 ) 50,422 (1,062,795 ) Production (1,129,951 ) (849,047 ) (126,760 ) (1,398,219 ) December 31, 2019 18,181,839 8,769,538 1,423,411 21,066,839 (1) The Partnership acquired 11,257 MBOE of reserves attributable to producing developed wells and PUDs in conjunction with Acquisition No. 1 (see Note 3. Oil and Gas Investments). (2) The Partnership acquired 11,792 MBOE of reserves attributable to producing developed wells and PUDs in conjunction with Acquisition No. 2 (see Note 3. Oil and Gas Investments). (3) Revisions to previous estimates increased proved reserves by a net amount of 870 MBOE. These revisions result from 1,248 MBOE of upward adjustments attributable to changes in the future drill schedule and 7 MBOE of upward adjustments caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2018 to the drill schedules and oil, natural gas and NGL prices at the dates of Acquisitions No. 1 and No. 2, which were partially offset by 385 MBOE of downward adjustments related to well performance post acquisition-closing dates. (4) In 2019, extensions, discoveries and other additions of 111 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets. (5) Revisions to previous estimates decreased proved reserves by 1,063 MBOE. These revisions result from 804 MBOE of downward adjustments attributable to well performance, 246 MBOE of downward adjustments attributable to changes in the future drill schedule and 13 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. Oil Natural Gas NGLs (Bbls) (Mcf) (Bbls) Total (BOE) Proved developed reserves: December 31, 2018 6,982,216 4,126,780 686,765 8,356,778 December 31, 2019 6,986,035 4,733,090 774,311 8,549,194 Proved undeveloped reserves: December 31, 2018 13,282,224 5,836,010 805,320 15,060,212 December 31, 2019 11,195,804 4,036,448 649,100 12,517,645 BOE Proved undeveloped reserves, beginning - Proved undeveloped reserves acquired, February 1, 2018 (1) 8,427,708 Proved undeveloped reserves acquired, August 31, 2018 (2) 7,279,846 Revisions of previous estimates (3) 1,252,630 Conversion to proved developed reserves (4) (1,899,972 ) Proved undeveloped reserves, December 31, 2018 15,060,212 Revisions of previous estimates (5) (401,688 ) Extensions, discoveries and other additions (6) 52,367 Conversion to proved developed reserves (7) (2,193,246 ) Proved undeveloped reserves acquired - Proved undeveloped reserves, December 31, 2019 12,517,645 (1) The Partnership acquired 8,428 MBOE attributable to PUDs in conjunction with Acquisition No. 1 (see Note 3. Oil and Gas Investments). (2) The Partnership acquired 7,280 MBOE attributable to PUDs in conjunction with Acquisition No. 2 (see Note 3. Oil and Gas Investments). (3) Revisions to previous estimates, from the respective closing dates for Acquisitions No. 1 and No. 2, increased PUDs by a net amount of 1,253 MBOE. These revisions result from 1,249 MBOE of upward adjustments attributable to changes in the future drill schedule and 4 MBOE of upward adjustments caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2018 to oil, natural gas and NGL prices at the dates of Acquisitions No. 1 and No. 2. There were no adjustments related to well performance. (4) Since the Partnership completed its first acquisition, 56 wells have either been completed or are in-process by the Partnership’s operators (the in-process wells converted were substantially complete and required relatively minor costs to bring to production). This development led to 1,900 MBOE of PUDs being converted to proved developed reserves from February 1, 2018 to December 31, 2018. (5) The annual review of the PUDs resulted in a negative revision of approximately 402 MBOE. This revision was the result of 246 MBOE of downward adjustments attributable to changes in the future drill schedule, 147 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 9 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. (6) In 2019, extensions, discoveries and other additions of 52 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets. (7) The Partnership converted 38 wells to proved developed reserves during 2019 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 2,193 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. 2019 2018 (in thousands) (in thousands) Future cash inflows $ 888,271 $ 1,256,302 Future production costs (244,165 ) (342,615 ) Future development costs (88,056 ) (102,210 ) Future net cash flows 556,050 811,477 10% annual discount (312,901 ) (440,982 ) Standardized measure of discounted future net cash flows $ 243,149 $ 370,495
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: 2019 2018 (in thousands) (in thousands) Standardized measure at beginning of period $ 370,495 $ - Changes resulting from: Acquisition of reserves - 273,568 Extensions, discoveries and other additions 1,093 - Sales of oil, natural gas and NGLs, net of production costs (41,631 ) (17,733 ) Net changes in prices and production costs (97,776 ) 71,883 Development costs incurred during the period 32,229 15,462 Revisions to previous estimates (40,287 ) 11,491 Accretion of discount 37,101 15,174 Change in estimated future development costs (18,075 ) 650 Standardized measure of discounted future net cash flows $ 243,149 $ 370,495

Quarterly Financial Data (Una_2

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
Quarterly Financial Data (Unaudited) (Tables)	Dec. 31, 2019
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, 2019 and 2018. Net income per common unit is non-additive in comparison to net income per common unit for each year due to the timing and size of the Partnership’s common unit issuances. 2019 First Quarter Second Quarter Third Quarter Fourth Quarter Total revenue $ 11,361,830 $ 18,832,114 $ 15,883,884 $ 18,352,989 Net income $ 1,641,943 $ 8,277,089 $ 5,680,657 $ 2,741,099 Basic and diluted net income per common share $ 0.20 $ 0.92 $ 0.56 $ 0.25 2018 (1) First Quarter Second Quarter Third Quarter Fourth Quarter Total revenue $ 3,497,079 $ 7,531,096 $ 5,503,706 $ 9,189,155 Net income $ 1,288,325 $ 3,400,535 $ 2,087,725 $ 3,589,444 Basic and diluted net income per common share $ 0.38 $ 0.82 $ 0.37 $ 0.51 (1) The Partnership did not acquire its first operating asset until February 1, 2018.

Partnership Organization (Detai

Partnership Organization (Details)	Dec. 30, 2016USD ($)	Jul. 25, 2017shares	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Oct. 24, 2019USD ($)shares
Partnership Organization (Details) [Line Items]
Limited Liability Company or Limited Partnership, Business, Formation State	Delaware
Partners' Capital Account, Contributions (in Dollars)	$ 1,000
Minimum Unit Offering, Shares (in Shares) \| shares		1,315,790
Proceeds from Issuance of Common Limited Partners Units (in Dollars)			$ 59,633,446	$ 87,634,447
Bakken Assets [Member]
Partnership Organization (Details) [Line Items]
Number of Operators			14
Best-Efforts Offering [Member]
Partnership Organization (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares) \| shares					11,000,000
Proceeds from Issuance of Common Limited Partners Units (in Dollars)					$ 218,000,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units (in Dollars)					$ 204,300,000
Non-operated Completed Wells [Member] \| Bakken Assets [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net			5.80%
Oil, Productive Well, Number of Wells, Net			332
Non-operated Wells in the Process of Drilling [Member] \| Bakken Assets [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net			2.00%
Oil and Gas, Present Activity, Well in Process of Drilling			20

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Details)	12 Months Ended
Summary of Significant Accounting Policies (Details)	Dec. 31, 2019
Summary of Significant Accounting Policies (Details) [Line Items]
Number of Wells shut-in	6
Revenue Benchmark [Member]
Summary of Significant Accounting Policies (Details) [Line Items]
Number of Operators	14
Customer Concentration Risk [Member] \| Revenue Benchmark [Member] \| Four Operators [Member]
Summary of Significant Accounting Policies (Details) [Line Items]
Number of Operators	4
Concentration Risk, Percentage	91.00%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies (Details) - Schedule of Asset Retirement Obligations - USD ($)		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Summary of Significant Accounting Policies (Details) - Schedule of Asset Retirement Obligations [Line Items]
Balance		$ 383,255	$ 0
Well additions		49,801	40,644
Accretion		20,607	38,633
Revisions	[1]	117,132
Balance		$ 570,795	383,255
Acquisition No. 1 [Member]
Summary of Significant Accounting Policies (Details) - Schedule of Asset Retirement Obligations [Line Items]
Well additions			133,155
Acquisition No. 2 [Member]
Summary of Significant Accounting Policies (Details) - Schedule of Asset Retirement Obligations [Line Items]
Well additions			$ 170,823

[1]	During 2019, six wells owned by the Partnership were shut-in by the Partnership’s operators. Revisions to the asset retirement obligations represent the full accretion of these six wells due to the reduction in the estimated life of the wells.

Oil and Gas Investments (Detail

Oil and Gas Investments (Details)	Dec. 28, 2018USD ($)shares	Aug. 31, 2018USD ($)	Feb. 01, 2018USD ($)	Sep. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Sep. 30, 2018USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2019
Oil and Gas Investments (Details) [Line Items]
Costs Incurred, Development Costs							$ 32,229,159	$ 15,461,555
Asset Retirement Obligation, Liabilities Incurred							49,801	40,644
Proceeds from Issuance of Unsecured Debt							0	25,000,000
Proceeds from Related Party Debt							$ 0	$ 7,000,000
Oil and Gas, Development Well Drilled, Net Productive, Number							38	56
Non-consent well description								Pursuant to the terms of the American Association of Professional Landmen Model Form Operating Agreement or North Dakota statute, each of which may govern operations between an operator and a non-operated working interest owner (“interest owner”), like the Partnership, an operator must notify an interest owner of its intention to drill a new well through submittal of a formal well proposal. The interest owner has the option to elect to participate in the drilling, completion and operating of the well and pay its proportionate share of all costs, or the interest owner may elect to non-consent the proposed well under the terms of the operating agreement or statute and bear no cost. If the interest owner elects to non-consent the proposed well, the interest owner is not obligated to pay any portion of the drilling, completion and operating expenses; however, the interest owner is then subject to a non-consent penalty under the terms of the operating agreement or North Dakota statute. Through its 2018 acquisitions, the Partnership acquired 59 wells designated as non-consent wells, whereby a previous interest owner did not consent to participate in the drilling and completion of those wells. As a result, the Partnership is currently subject to non-consent penalties ranging from 200%-400%, meaning in general terms, the Partnership will remain in non-consent status and will not receive any revenue from these wells until the wells have satisfied the contractual or statutory penalties of 2-4 times payout of the expenses related to drilling, completion and operating the well. The Partnership may receive revenue or be responsible for operating and/or abandonment costs from all or a portion of these wells if the wells generate enough revenue to exceed the non-consent penalties described above.
Number of Wells Designated as Non-Consent Wells								59
Minimum [Member]
Oil and Gas Investments (Details) [Line Items]
Non-consent penalty range								200.00%
Maximum [Member]
Oil and Gas Investments (Details) [Line Items]
Non-consent penalty range								400.00%
Bakken Assets [Member]
Oil and Gas Investments (Details) [Line Items]
Costs Incurred, Development Costs				$ 2,700,000
Deferred Costs								$ 1,400,000
Non-operated Completed Wells [Member] \| Bakken Assets [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net							5.80%
Oil, Productive Well, Number of Wells, Net							332		332
Non-operated Wells in the Process of Drilling [Member] \| Bakken Assets [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net							2.00%
Oil, Productive Well, Number of Wells, Net							20		20
Affiliated Entity [Member] \| Bakken Assets [Member]
Oil and Gas Investments (Details) [Line Items]
Advisory and Consulting Services Related Party					$ 5,300,000
Asset Disposal Fee, Related Party, Percentage								5.00%
Acquisition No. 1 [Member]
Oil and Gas Investments (Details) [Line Items]
Asset Retirement Obligation, Liabilities Incurred								$ 133,155
Acquisition No. 1 [Member] \| Bakken Assets [Member]
Oil and Gas Investments (Details) [Line Items]
Business Combination, Consideration Transferred			$ 87,500,000
Non-cash Transaction Increase in Accounts Receivable Settlement of Pre-close Activity			2,100,000
Costs Incurred, Development Costs			5,000,000			$ 15,400,000	$ 32,200,000
Asset Retirement Obligation, Liabilities Incurred					100,000
Proceeds from Issuance of Unsecured Debt			25,000,000
Proceeds from Related Party Debt			$ 7,000,000
Wells Drilled									153
Oil and Gas, Development Well Drilled, Net Productive, Number									133
Oil and Gas, Present Activity, Well in Process of Drilling							20		20
Capital Expenditures Drilling and Completion of Wells							$ 1,000,000
Acquisition No. 1 [Member] \| Affiliated Entity [Member] \| Bakken Assets [Member]
Oil and Gas Investments (Details) [Line Items]
Acquisition Costs, Period Cost					$ 4,700,000
Acquisition No. 2 [Member]
Oil and Gas Investments (Details) [Line Items]
Asset Retirement Obligation, Liabilities Incurred								170,823
Acquisition No. 2 [Member] \| Bakken Assets [Member]
Oil and Gas Investments (Details) [Line Items]
Business Combination, Consideration Transferred		$ 82,500,000
Asset Retirement Obligation, Liabilities Incurred		200,000
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Financial Assets								4,300,000
Acquisition Costs, Period Cost		$ 2,900,000
Proceeds from Lines of Credit								$ 60,000,000
Acquisition No. 2 [Member] \| Affiliated Entity [Member] \| Bakken Assets [Member]
Oil and Gas Investments (Details) [Line Items]
Acquisition Costs, Period Cost				$ 4,100,000
Capital Unit, Class B [Member]
Oil and Gas Investments (Details) [Line Items]
In connection with termination of agreements with REI, the General Partner issued 500 of its non-voting Class B Units to entities controlled by related parties (in Shares) \| shares	500
Payment made by entities controlled by related parties to General Partner for non-voting Class B Units	$ 250
In connection with termination of agreements with REI, entities controlled by related parties have acquired a non-voting interest in the General Partner	50.00%

Oil and Gas Investments (Deta_2

Oil and Gas Investments (Details) - Business Acquisition, Pro Forma Information	12 Months Ended
	Dec. 31, 2018USD ($)
Business Acquisition, Pro Forma Information [Abstract]
Revenues	$ 43,067,089
Net income	$ 20,511,627

Debt (Details)

Debt (Details) - USD ($)	Aug. 31, 2018	Jan. 16, 2018	Dec. 31, 2019	Dec. 31, 2018	Nov. 26, 2019
Debt (Details) [Line Items]
Long-term Line of Credit			$ 0	$ 39,500,000
Gain (Loss) on Extinguishment of Debt			$ (999,172)	$ 0
Revolving Credit Facility [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount	$ 60,000,000
Long-term Line of Credit					$ 0
Deferred Costs	$ 1,700,000
Debt Instrument, Maturity Date	Aug. 31, 2021
Notes Payable to Banks [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount		$ 25,000,000
Guarantor Obligations, Origin and Purpose		Glade M. Knight and David S. McKenney, the General Partner’s Chief Executive Officer and Chief Financial Officer, respectively, had guaranteed repayment of the Term Loan and did not receive any consideration in exchange for providing this guarantee.
London Interbank Offered Rate (LIBOR) [Member] \| Revolving Credit Facility [Member] \| Minimum [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.75%
London Interbank Offered Rate (LIBOR) [Member] \| Revolving Credit Facility [Member] \| Maximum [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	3.75%
London Interbank Offered Rate (LIBOR) [Member] \| Notes Payable to Banks [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.00%

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, 2019	Dec. 31, 2018
Fair Value, Inputs, Level 1 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current liabilities	$ 0
Total	0	$ 0
Commodity derivatives - current assets		0
Commodity derivatives - noncurrent assets		0
Fair Value, Inputs, Level 2 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current liabilities	(207,327)
Total	(207,327)	879,617
Commodity derivatives - current assets		644,786
Commodity derivatives - noncurrent assets		234,831
Fair Value, Inputs, Level 3 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current liabilities	0
Total	$ 0	0
Commodity derivatives - current assets		0
Commodity derivatives - noncurrent assets		$ 0

Risk Management (Details)

Risk Management (Details) - USD ($)	12 Months Ended
Risk Management (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Liability, Current	$ 207,327	$ 0
Derivative Asset		$ 900,000
Derivative, Gain on Derivative	$ 22,500

Risk Management (Details) - Der

Risk Management (Details) - Derivative Instruments, Gain (Loss) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Abstract]
Settlement loss on matured derivatives, net	$ (56,348)	$ 0
Gain (loss) on mark-to-market of derivatives	(1,086,944)	879,617
Gain (loss) on derivatives	$ (1,143,292)	$ 879,617

Risk Management (Details) - Sch

Risk Management (Details) - Schedule of Derivative Instruments - Price Risk Derivative [Member]	12 Months Ended
	Dec. 31, 2019USD ($)$ / iteml
Derivative [Line Items]
Basis	NYMEX
Oil (Barrels) (in Liters) \| l	107,000
Floor Price	45
Fair Value of Liability (in Dollars) \| $	$ (207,327)
Ceiling Price	61.20

Capital Contribution and Part_2

Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions	Dec. 30, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Oct. 24, 2019
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Contributions	$ 1,000
Partners' Capital Account, Return of Contribution Upon Minimum Offering				$ 990
Proceeds from Issuance of Common Limited Partners Units		$ 59,633,446	$ 87,634,447
Partners' Capital Account, Description of Units Sold		Under the agreement with the Managing Dealer, the Managing Dealer received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering as outlined in the prospectus based on the performance of the Partnership.
Managing Dealer, Selling Commissions, Percentage		6.00%
Managing Dealer, Maximum Contingent Incentive Fee on Gross Proceeds, Percentage		4.00%
Managing Dealer, Maximum Contingent Incentive Fee on Gross Proceeds		$ 8,700,000
Key Provisions of Operating or Partnership Agreement, Description		The Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”) provides that “Payout”, which is defined below, 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, 30%; (ii) to the Managing Dealer, the “Dealer Manager Incentive Fees”, 30%, until such time as the Managing Dealer receives 4% of the gross proceeds of the common units sold; and (iii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest. ● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 60%; and (ii) to the Record Holders of outstanding common units, 40%, pro rata based on their percentage interest. 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.
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share)		$ 1.396164	$ 1.396164
Distribution Made to Limited Partner, Cash Distributions Paid		$ 13,286,419	$ 7,044,859
Best-Efforts Offering [Member]
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares)					11
Proceeds from Issuance of Common Limited Partners Units					$ 218,000,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units					$ 204,300,000

Related Parties (Details)

Related Parties (Details) - USD ($)	Dec. 28, 2018	Feb. 01, 2018	Dec. 31, 2019	Dec. 31, 2018
Related Parties (Details) [Line Items]
Related Party Transaction, Description of Transaction			subsequent to the Partnership’s first asset purchase, which occurred on February 1, 2018, the Partnership is required to pay quarterly an annual fee of 0.5% of the total gross equity proceeds raised by the Partnership in its best-efforts offering.
Due to Related Parties, Current			$ 217,209	$ 212,117
Proceeds from Related Party Debt			0	7,000,000
General Partner [Member]
Related Parties (Details) [Line Items]
Due to Related Parties, Current			133,000	135,000
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party			414,000	402,000
Energy 11 [Member]
Related Parties (Details) [Line Items]
Due to Related Parties, Current			85,000	77,000
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party			285,000	252,000
Management Fee [Member] \| General Partner [Member]
Related Parties (Details) [Line Items]
Due to Related Parties, Current			$ 1,000,000	537,000
Consulting Services Provided to General Partner [Member] \| President [Member]
Related Parties (Details) [Line Items]
Payment Made By Related Party to Others				$ 500,000
Bakken Assets [Member] \| Acquisition No. 1 [Member]
Related Parties (Details) [Line Items]
Proceeds from Related Party Debt		$ 7,000,000
Bakken Assets [Member] \| Affiliated Entity [Member]
Related Parties (Details) [Line Items]
Asset Disposal Fee, Related Party, Percentage				5.00%
Capital Unit, Class B [Member]
Related Parties (Details) [Line Items]
In connection with termination of agreements with REI, the General Partner issued 500 of its non-voting Class B Units to entities controlled by related parties (in Shares)	500
Payment made by entities controlled by related parties to General Partner for non-voting Class B Units	$ 500
In connection with termination of agreements with REI, entities controlled by related parties have acquired a non-voting interest in the General Partner	50.00%

Supplementary Information on _3

Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details)		12 Months Ended
		Dec. 31, 2019Boe$ / bbl$ / Mcf		Dec. 31, 2018Boe$ / bbl$ / Mcf
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Purchase of Mineral in Place (Energy)		0
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		(401,688)	[1]	1,252,630	[2]
Oil and Gas, Development Well Drilled, Net Productive, Number		38		56
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)		(2,193,246)	[3]	(1,899,972)	[4]
Oil [Member] \| Before Price Differentials [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		55.69		65.56
Oil [Member] \| Including Effects of Price Differential Adjustments [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		49.42		59.56
Natural Gas [Member] \| Before Price Differentials [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)) \| $ / Mcf		2.58		3.10
Natural Gas [Member] \| Including Effects of Price Differential Adjustments [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)) \| $ / Mcf		(1.61)		2.43
Natural Gas Liquids [Member] \| Including Effects of Price Differential Adjustments [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		2.74		20.25
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)		(1,063,000)		870,000
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)		(402,000)		1,253,000
Adjustments 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)		(246,000)		1,248,000
Adjustments Related to Changes in Future Drill Schedule [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)		(246,000)		1,249,000
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)		13,000		7,000
Adjustments Related to Prices [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)		9,000		4,000
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)		(804,000)		385,000
Adjustments Related to Successful Drilling [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		52,000
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)		111,000
Changes in 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)		(147,000)
Measurement Input, Discount Rate [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Future Cash Flows Measurement Input		10.00%		10.00%
Acquisition No. 1 [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Purchase of Mineral in Place (Energy)	[5]			8,427,708
Acquisition No. 1 [Member] \| Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Purchase of Mineral in Place (Energy)				11,257,000
Acquisition No. 1 [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)				8,428,000
Acquisition No. 2 [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Purchase of Mineral in Place (Energy)	[6]			7,279,846
Acquisition No. 2 [Member] \| Proved Reserves [Member]
Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited) (Details) [Line Items]
Proved Developed and Undeveloped Reserve, Purchase of Mineral in Place (Energy)				11,792,000
Acquisition No. 2 [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)				7,280,000

[1]	The annual review of the PUDs resulted in a negative revision of approximately 402 MBOE. This revision was the result of 246 MBOE of downward adjustments attributable to changes in the future drill schedule, 147 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 9 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.
[2]	Revisions to previous estimates, from the respective closing dates for Acquisitions No. 1 and No. 2, increased PUDs by a net amount of 1,253 MBOE. These revisions result from 1,249 MBOE of upward adjustments attributable to changes in the future drill schedule and 4 MBOE of upward adjustments caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2018 to oil, natural gas and NGL prices at the dates of Acquisitions No. 1 and No. 2. There were no adjustments related to well performance.
[3]	The Partnership converted 38 wells to proved developed reserves during 2019 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 2,193 MBOE.
[4]	Since the Partnership completed its first acquisition, 56 wells have either been completed or are in-process by the Partnership’s operators (the in-process wells converted were substantially complete and required relatively minor costs to bring to production). This development led to 1,900 MBOE of PUDs being converted to proved developed reserves from February 1, 2018 to December 31, 2018.
[5]	The Partnership acquired 8,428 MBOE attributable to PUDs in conjunction with Acquisition No. 1 (see Note 3. Oil and Gas Investments).
[6]	The Partnership acquired 7,280 MBOE attributable to PUDs in conjunction with Acquisition No. 2 (see Note 3. Oil and Gas Investments).

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, 2019	Dec. 31, 2018
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
	$ 219,454,168	$ 186,968,473
Accumulated depreciation, depletion and amortization	(21,955,397)	(4,889,806)
Net capitalized costs	197,498,771	182,078,667
Producing Properties [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized Costs, Proved Properties	148,370,378	116,487,297
Non-Producing Properties [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Capitalized Costs, Proved Properties	$ 71,083,790	$ 70,481,176

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, 2019	Dec. 31, 2018
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Abstract]
Property acquisition costs	$ 256,536	$ 171,506,918
Development costs	32,229,159	15,461,555
	$ 32,485,695	$ 186,968,473

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, 2019BoebblMcf		Dec. 31, 2018BoebblMcf
Reserve Quantities [Line Items]
Balance		23,416,990		0
Proved developed reserves:
Balance proved developed reserves (in Barrels of Oil Equivalent) \| Boe		8,549,194		8,356,778
Proved undeveloped reserves:
Balance proved undeveloped reserves (in Barrels of Oil Equivalent) \| Boe		12,517,645		15,060,212
Balance proved undeveloped reserves (in Barrels of Oil Equivalent) \| Boe		15,060,212		0
Balance proved undeveloped reserves (in Barrels of Oil Equivalent) \| Boe		12,517,645		15,060,212
Acquisition		0
Extensions, discoveries and other additions		110,863	[1]	0
Revisions of previous estimates		(1,062,795)	[2]	869,507	[3]
Production		(1,398,219)		(501,150)
Proved undeveloped reserves acquired (in Barrels of Oil Equivalent) \| Boe		0
Revisions of previous estimates (in Barrels of Oil Equivalent) \| Boe		(401,688)	[4]	1,252,630	[5]
Extensions, discoveries and other additions (in Barrels of Oil Equivalent) \| Boe	[6]	52,367
Conversion to proved developed reserves (in Barrels of Oil Equivalent) \| Boe		(2,193,246)	[7]	(1,899,972)	[8]
Balance		21,066,839		23,416,990
Acquisition No. 1 [Member]
Proved undeveloped reserves:
Acquisition	[9]			11,257,058
Proved undeveloped reserves acquired (in Barrels of Oil Equivalent) \| Boe	[10]			8,427,708
Acquisition No. 2 [Member]
Proved undeveloped reserves:
Acquisition	[11]			11,791,575
Proved undeveloped reserves acquired (in Barrels of Oil Equivalent) \| Boe	[12]			7,279,846
Oil [Member]
Reserve Quantities [Line Items]
Balance		20,264,440		0
Proved developed reserves:
Balance proved developed reserves		6,986,035		6,982,216
Proved undeveloped reserves:
Balance proved undeveloped reserves		11,195,804		13,282,224
Acquisition		0
Extensions, discoveries and other additions		94,703	[1]	0
Revisions of previous estimates		(1,047,353)	[2]	653,770	[3]
Production		(1,129,951)		(405,581)
Balance		18,181,839		20,264,440
Oil [Member] \| Acquisition No. 1 [Member]
Proved undeveloped reserves:
Acquisition	[9]			9,717,859
Oil [Member] \| Acquisition No. 2 [Member]
Proved undeveloped reserves:
Acquisition	[11]			10,298,392
Natural Gas [Member]
Reserve Quantities [Line Items]
Balance \| Mcf		9,962,790		0
Proved developed reserves:
Balance proved developed reserves \| Mcf		4,733,090		4,126,780
Proved undeveloped reserves:
Balance proved undeveloped reserves \| Mcf		4,036,448		5,836,010
Acquisition \| Mcf		0
Extensions, discoveries and other additions \| Mcf		50,978	[1]	0
Revisions of previous estimates \| Mcf		(395,183)	[2]	545,023	[3]
Production \| Mcf		(849,047)		(319,445)
Balance \| Mcf		8,769,538		9,962,790
Natural Gas [Member] \| Acquisition No. 1 [Member]
Proved undeveloped reserves:
Acquisition \| Mcf	[9]			4,957,715
Natural Gas [Member] \| Acquisition No. 2 [Member]
Proved undeveloped reserves:
Acquisition \| Mcf	[11]			4,779,497
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Balance		1,492,085		0
Proved developed reserves:
Balance proved developed reserves		774,311		686,765
Proved undeveloped reserves:
Balance proved undeveloped reserves		649,100		805,320
Acquisition		0
Extensions, discoveries and other additions		7,664	[1]	0
Revisions of previous estimates		50,422	[2]	124,901	[3]
Production		(126,760)		(42,329)
Balance		1,423,411		1,492,085
Natural Gas Liquids [Member] \| Acquisition No. 1 [Member]
Proved undeveloped reserves:
Acquisition	[9]			712,913
Natural Gas Liquids [Member] \| Acquisition No. 2 [Member]
Proved undeveloped reserves:
Acquisition	[11]			696,600

[1]	In 2019, extensions, discoveries and other additions of 111 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.
[2]	Revisions to previous estimates decreased proved reserves by 1,063 MBOE. These revisions result from 804 MBOE of downward adjustments attributable to well performance, 246 MBOE of downward adjustments attributable to changes in the future drill schedule and 13 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.
[3]	Revisions to previous estimates increased proved reserves by a net amount of 870 MBOE. These revisions result from 1,248 MBOE of upward adjustments attributable to changes in the future drill schedule and 7 MBOE of upward adjustments caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2018 to the drill schedules and oil, natural gas and NGL prices at the dates of Acquisitions No. 1 and No. 2, which were partially offset by 385 MBOE of downward adjustments related to well performance post acquisition-closing dates.
[4]	The annual review of the PUDs resulted in a negative revision of approximately 402 MBOE. This revision was the result of 246 MBOE of downward adjustments attributable to changes in the future drill schedule, 147 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 9 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.
[5]	Revisions to previous estimates, from the respective closing dates for Acquisitions No. 1 and No. 2, increased PUDs by a net amount of 1,253 MBOE. These revisions result from 1,249 MBOE of upward adjustments attributable to changes in the future drill schedule and 4 MBOE of upward adjustments caused by higher oil, natural gas and NGL prices when comparing the Partnership’s reserve estimates at December 31, 2018 to oil, natural gas and NGL prices at the dates of Acquisitions No. 1 and No. 2. There were no adjustments related to well performance.
[6]	In 2019, extensions, discoveries and other additions of 52 MBOE were primarily attributable to successful drilling by the Partnership’s operators of the Bakken Assets.
[7]	The Partnership converted 38 wells to proved developed reserves during 2019 as these wells were complete or substantially complete and the costs to bring to production were relatively minor, which resulted in a downward adjustment to PUDs of 2,193 MBOE.
[8]	Since the Partnership completed its first acquisition, 56 wells have either been completed or are in-process by the Partnership’s operators (the in-process wells converted were substantially complete and required relatively minor costs to bring to production). This development led to 1,900 MBOE of PUDs being converted to proved developed reserves from February 1, 2018 to December 31, 2018.
[9]	The Partnership acquired 11,257 MBOE of reserves attributable to producing developed wells and PUDs in conjunction with Acquisition No. 1 (see Note 3. Oil and Gas Investments).
[10]	The Partnership acquired 8,428 MBOE attributable to PUDs in conjunction with Acquisition No. 1 (see Note 3. Oil and Gas Investments).
[11]	The Partnership acquired 11,792 MBOE of reserves attributable to producing developed wells and PUDs in conjunction with Acquisition No. 2 (see Note 3. Oil and Gas Investments).
[12]	The Partnership acquired 7,280 MBOE attributable to PUDs in conjunction with Acquisition No. 2 (see Note 3. Oil and Gas Investments).

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 ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Abstract]
Future cash inflows	$ 888,271	$ 1,256,302
Future production costs	(244,165)	(342,615)
Future development costs	(88,056)	(102,210)
Future net cash flows	556,050	811,477
10% annual discount	(312,901)	(440,982)
Standardized measure of discounted future net cash flows	$ 243,149	$ 370,495	$ 0

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, 2019	Dec. 31, 2018
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 ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Abstract]
Standardized measure at beginning of period	$ 370,495	$ 0
Changes resulting from:
Acquisition of reserves	0	273,568
Extensions, discoveries and other additions	1,093	0
Sales of oil, natural gas and NGLs, net of production costs	(41,631)	(17,733)
Net changes in prices and production costs	(97,776)	71,883
Development costs incurred during the period	32,229	15,462
Revisions to previous estimates	(40,287)	11,491
Accretion of discount	37,101	15,174
Change in estimated future development costs	(18,075)	650
Standardized measure of discounted future net cash flows	$ 243,149	$ 370,495

Quarterly Financial Data (Una_3

Quarterly Financial Data (Unaudited) (Details) - Quarterly Financial Information - USD ($)	3 Months Ended												12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	[1]	Sep. 30, 2018	[1]	Jun. 30, 2018	[1]	Mar. 31, 2018	[1]	Dec. 31, 2019	Dec. 31, 2018
Quarterly Financial Information [Abstract]
Total revenue	$ 18,352,989	$ 15,883,884	$ 18,832,114	$ 11,361,830	$ 9,189,155		$ 5,503,706		$ 7,531,096		$ 3,497,079		$ 64,430,817	$ 25,721,036
Net income	$ 2,741,099	$ 5,680,657	$ 8,277,089	$ 1,641,943	$ 3,589,444		$ 2,087,725		$ 3,400,535		$ 1,288,325		$ 18,340,788	$ 10,366,029
Basic and diluted net income per common share (in Dollars per share)	$ 0.25	$ 0.56	$ 0.92	$ 0.20	$ 0.51		$ 0.37		$ 0.82		$ 0.38		$ 1.92	$ 2.04

[1]	The Partnership did not acquire its first operating asset until February 1, 2018.

Subsequent Events (Details)

Subsequent Events (Details) - Subsequent Event [Member] - USD ($) $ / shares in Units, $ in Millions	1 Months Ended
	Feb. 29, 2020	Jan. 31, 2020
Subsequent Events (Details) [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid	$ 1.2	$ 1.5
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.107397	$ 0.134247