Energy 11 10-Q 22 Jun 20 2020 Q1 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	3 Months Ended
	Mar. 31, 2020	Jun. 22, 2020
Document Information Line Items
Entity Registrant Name	Energy 11, L.P.
Document Type	10-Q
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		18,973,474
Amendment Flag	false
Entity Central Index Key	0001581552
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Period End Date	Mar. 31, 2020
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q1
Entity Small Business	true
Entity Emerging Growth Company	true
Entity Shell Company	false
Entity Ex Transition Period	true
Document Quarterly Report	true
Document Transition Report	false
Entity File Number	000-55615
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-3070515
Entity Address, Address Line One	120 W 3rd Street, Suite 220
Entity Address, City or Town	Fort Worth
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	76102
City Area Code	817
Local Phone Number	882-9192
Title of 12(b) Security	None
Entity Interactive Data Current	Yes
No Trading Symbol Flag	true

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Mar. 31, 2020	Dec. 31, 2019
Assets
Cash and cash equivalents	$ 2,709,116	$ 348,550
Oil, natural gas and natural gas liquids revenue receivable	9,288,131	5,857,926
Other current assets	221,726	284,652
Total Current Assets	12,218,973	6,491,128
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $57,731,046 and $53,186,165, respectively	337,656,904	326,758,636
Total Assets	349,875,877	333,249,764
Liabilities
Revolving credit facility	40,000,000	0
Accounts payable, accrued expenses and other current liabilities	22,290,748	20,061,059
Total Current Liabilities	62,290,748	20,061,059
Revolving credit facility	0	24,000,000
Asset retirement obligations	1,500,557	1,452,734
Total Liabilities	63,791,305	45,513,793
Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)	286,086,299	287,737,698
General partner's interest	(1,727)	(1,727)
Class B Units (62,500 units issued and outstanding, respectively)	0	0
Total Partners’ Equity	286,084,572	287,735,971
Total Liabilities and Partners’ Equity	$ 349,875,877	$ 333,249,764

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - USD ($)	Mar. 31, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Oil and natural gas properties, accumulated depreciation, depletion and amortization (in Dollars)	$ 57,731,046	$ 53,186,165
Limited partners' interest, common units issued	18,973,474	18,973,474
Limited partners' interest, common units outstanding	18,973,474	18,973,474
Class B Units, units issued	62,500	62,500
Class B Units, units outstanding	62,500	62,500

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($)	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Revenues
Oil	$ 10,229,733	$ 8,092,070
Natural gas	354,574	961,112
Natural gas liquids	519,227	1,038,163
Total revenue	11,103,534	10,091,345
Operating costs and expenses
Production expenses	2,052,237	2,818,717
Production taxes	992,341	810,793
General and administrative expenses	565,297	494,482
Depreciation, depletion, amortization and accretion	4,564,861	3,433,551
Total operating costs and expenses	8,174,736	7,557,543
Operating income	2,928,798	2,533,802
Gain on derivatives	440,890	0
Interest expense, net	(436,261)	(193,828)
Total other expense, net	4,629	(193,828)
Net income	$ 2,933,427	$ 2,339,974
Basic and diluted net income per common unit (in Dollars per share)	$ 0.15	$ 0.12
Weighted average common units outstanding - basic and diluted (in Shares)	18,973,474	18,973,474

Consolidated Statements of Part

Consolidated Statements of Partners' Equity - USD ($)	Total	Limited Partner [Member]	General Partner [Member]	Member Units [Member]Capital Unit, Class B [Member]
Balance at Dec. 31, 2018	$ 305,745,602	$ 305,747,329	$ (1,727)
Balance (in Shares) at Dec. 31, 2018		18,973,474		62,500
Distributions declared and paid to common units	(6,622,520)	$ (6,622,520)
Net income	2,339,974	2,339,974
Balance at Mar. 31, 2019	301,463,056	$ 301,464,783	(1,727)
Balance (in Shares) at Mar. 31, 2019		18,973,474		62,500
Balance at Dec. 31, 2019	$ 287,735,971	$ 287,737,698	(1,727)
Balance (in Shares) at Dec. 31, 2019	18,973,474	18,973,474		62,500
Distributions declared and paid to common units	$ (4,584,826)	$ (4,584,826)
Net income	2,933,427	2,933,427
Balance at Mar. 31, 2020	$ 286,084,572	$ 286,086,299	$ (1,727)
Balance (in Shares) at Mar. 31, 2020	18,973,474	18,973,474		62,500

Consolidated Statements of Pa_2

Consolidated Statements of Partners' Equity (Parentheticals) - $ / shares	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Member Units [Member] | Capital Unit, Class B [Member]
Distributions declared and paid to common units, per unit	$ 0.241644	$ 0.349041

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Cash flow from operating activities:
Net income	$ 2,933,427	$ 2,339,974
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion	4,564,861	3,433,551
(Gain) / loss on mark-to-market of derivatives	(183,850)	0
Non-cash expenses, net	10,164	11,198
Changes in operating assets and liabilities:
Oil, natural gas and natural gas liquids revenue receivable	(3,430,205)	599,643
Other current assets	52,762	54,224
Accounts payable and accrued expenses	289,117	(723,746)
Net cash flow provided by operating activities	4,236,276	5,714,844
Cash flow from investing activities:
Additions to oil and natural gas properties	(13,290,884)	(235,449)
Net cash flow used in investing activities	(13,290,884)	(235,449)
Cash flow from financing activities:
Proceeds from revolving credit facility	16,000,000	0
Distributions paid to limited partners	(4,584,826)	(6,622,520)
Net cash flow (used in) provided by financing activities	11,415,174	(6,622,520)
Decrease in cash and cash equivalents	2,360,566	(1,143,125)
Cash and cash equivalents, beginning of period	348,550	3,685,327
Cash and cash equivalents, end of period	2,709,116	2,542,202
Interest paid	441,591	190,642
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$ 20,547,754	$ 20,972

Partnership Organization

Partnership Organization	3 Months Ended
	Mar. 31, 2020
Accounting Policies [Abstract]
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]	Note 1. Partnership Organization Energy 11, L.P. (the “Partnership”) is a Delaware limited partnership formed to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties. The initial capitalization of the Partnership of $1,000 occurred on July 9, 2013. The Partnership completed its best-efforts offering on April 24, 2017 with a total of approximately 19.0 million common units sold for gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million. As of March 31, 2020, the Partnership owned an approximate 25% non-operated working interest in 235 currently producing wells, an estimated approximate 20% non-operated working interest in 26 wells in various stages of the drilling and completion process and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). Whiting Petroleum Corporation (“Whiting”) (NYSE: WLL) and Oasis Petroleum North America, LLC (“Oasis”) (NYSE:OAS), two of the largest producers in the basin, operate substantially all of the Sanish Field Assets. The general partner of the Partnership is Energy 11 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership. The Partnership’s fiscal year ends on December 31. Drilling Program, Oil Demand, Current Pricing, Liquidity and Going Concern Considerations During 2019, the Partnership elected to participate in the drilling of 33 new wells at an estimated total investment cost to the Partnership of approximately $52 million. In the first quarter of 2020, the Partnership elected to participate in the drilling of an additional 10 new wells at an estimated total investment cost to the Partnership of approximately $13 million, for a total of 43 new wells at an estimated cost to the Partnership of approximately $65 million. In conjunction with this drilling program performed primarily by Whiting, the Partnership has incurred approximately $39 million in capital expenditures through March 31, 2020. New production from completed wells was expected to enhance the Partnership’s operating performance throughout 2020, providing incremental cash flow from operations to fund the Partnership’s investment in its undrilled acreage. During the fourth quarter of 2019 and into the first quarter of 2020, the Partnership primarily used availability under its $40 million revolving credit facility (“Credit Facility”, described in Note 4. Debt) to fund its capital expenditure requirements. As of March 31, 2020, the Partnership did not have any availability under its Credit Facility and has not been successful in securing additional financing. Subsequent to the Partnership’s election to participate in Whiting’s drilling program, the outbreak of a novel coronavirus (“COVID-19”) in China spread worldwide, forcing governments around the world to take drastic measures to halt the outbreak. These measures include significant restrictions on travel, forced quarantines, stay-at-home requirements and the closure of businesses in many industries for an undetermined period of time, creating extreme volatility in capital markets and the global economy. Because of COVID-19’s impact to the global economy, demand for oil, natural gas and other hydrocarbons substantially declined in March 2020, and demand for oil and natural gas is anticipated to be low for the remainder of 2020. This reduction in demand compounded an existing excess in supply of oil and natural gas, as the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia could not agree on daily production output of crude oil in March 2020. As a result, Russia announced its intention to increase production, and Saudi Arabia immediately countered with announced reductions to export prices. All of these factors led to oil prices falling in March 2020 and to 20-year lows in April 2020, and there is uncertainty as to when oil prices may stabilize at more economical levels for producers. With the anticipation that worldwide oil and natural gas prices will remain depressed during the remainder of 2020, operators within the United States have altered drilling programs and reduced forecasted capital expenditures. Further, because reduced demand and excess supply has strained storage facilities, operators may not be able to sell produced oil and natural gas at an economical price point. Operators may be forced to curtail production, shut-in producing wells or seek other cost-cutting measures until commodity prices increase. These factors are expected to have a significant adverse impact on the Partnership’s business and its financial condition. Due to the impacts to the global oil and gas industry described above, the General Partner approved the suspension of distributions to limited partners of the Partnership in March 2020. Further, Whiting suspended its Sanish field drilling program during the second quarter of 2020. As of March 31, 2020, the Partnership had approximately $21 million in accrued capital expenditures due to Whiting, and the Partnership estimates it may incur approximately $5 to $7 million in additional capital expenditures during the second quarter of 2020 based upon the status of the in-process wells when Whiting suspended its drilling program. As a result of the depressed commodity prices caused by the economic conditions and anticipated reduced production discussed above, in conjunction with having no current additional capital resources other than cash flow from operations, the Partnership may not be able to timely meet its obligations to Whiting as they come due. Currently, Whiting is offsetting Partnership revenue earned against Partnership amounts due to Whiting, which allows the Partnership to pay down its obligations to Whiting through cash flow from operations over time, but also fund its debt service and other working capital requirements as the Partnership works to pursue additional capital resources. The Partnership can offer no assurance that Whiting will not pursue other remedies allowable under the joint operating agreements between Whiting, as operator, and the Partnership, as a working interest owner, including foreclosure on the Partnership’s working and revenue interests on certain wells, which would affect the future revenues, operating expenses, reserve volumes and potential impairment reported by the Partnership. The Partnership’s ability to continue as a going concern is dependent on several factors including, but not limited to, (i) its lender group providing waivers to certain covenants and the Partnership’s ability to comply with other obligations under its loan agreement (see Note 4. Debt for further discussion); (ii) reaching an agreement with Whiting to resolve the Partnership’s obligations to Whiting; (iii) securing additional capital; (iv) an increase in demand for oil and natural gas as the global economy recovers from the effects of the COVID-19 pandemic and the existing oversupply of oil in the United States; and (v) an increase in oil and natural gas market prices, which will improve the Partnership’s cash flow generated from operations. The Partnership can provide no assurance that it will be able to achieve any of these objectives. Further, additional capital may not be available on favorable terms to the Partnership, if it is available at all. There also can be no assurance that economic activity and oil and natural gas market conditions, including commodity prices, will return to pre-COVID-19 levels. Since the Partnership has not fully and effectively implemented all of its plans detailed above and if the outstanding balance of the Credit Facility is accelerated and becomes immediately due and payable, the Partnership could be required to liquidate certain of its assets used for collateral to satisfy the obligations that create substantial doubt that exists about the ability of the Partnership to continue as a going concern for one year after the date these financial statements are issued. The accompanying financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classifications of liabilities that may result from the possible inability of the Partnership to continue as a going concern.

Summary of Significant Accounti

Summary of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2020
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	Note 2. Summary of Significant Accounting Policies Basis of Presentation The accompanying unaudited financial statements have been prepared in accordance with the instructions for Article 10 of SEC Regulation S-X. Accordingly, they do not include all of the information required by generally accepted accounting principles (“GAAP”) in the United States. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. These unaudited financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements included in its 2019 Annual Report on Form 10-K. Operating results for the three months ended March 31, 2020 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2020. Use of Estimates The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Revenue Recognition The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators two to three months after the date production is delivered by the operator. 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. Net Income Per Common Unit Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three months ended March 31, 2020 and 2019. As a result, basic and diluted outstanding common units were the same. The Class B units and Incentive Distribution Rights, as defined below, are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 7) will occur. Recently Adopted Accounting Standards In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-04, Reference Rate Reform (Topic 848), which provides optional guidance through December 31, 2022 to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments in ASU No. 2020-04 apply to contract modifications that replace a reference rate affected by reference rate reform, providing optional expedients regarding the measurement of hedge effectiveness in hedging relationships that have been modified to replace a reference rate. While the guidance in ASU No. 2020-04 became effective upon issuance, the provisions of the ASU did not have a material impact on the Partnership’s consolidated financial statements and related disclosures as of March 31, 2020.

Oil and Gas Investments

Oil and Gas Investments	3 Months Ended
	Mar. 31, 2020
Oil and Gas Property [Abstract]
Oil and Gas Properties [Text Block]	Note 3. Oil and Natural Gas Investments On December 18, 2015, the Partnership completed its first purchase (“Acquisition No. 1”) in the Sanish field, acquiring an approximate 11% non-operated working interest in the Sanish Field Assets for approximately $159.6 million. On January 11, 2017, the Partnership closed on its second purchase (“Acquisition No. 2”) in the Sanish field, acquiring an additional approximate 11% non-operated working interest in the Sanish Field Assets for approximately $128.5 million. On March 31, 2017, the Partnership closed on its third purchase (“Acquisition No. 3”) in the Sanish field, acquiring an additional approximate average 10.5% non-operated working interest in 82 of the Partnership’s then 216 existing producing wells and 150 of the Partnership’s then 253 future development locations in the Sanish Field Assets for approximately $52.4 million. During 2018, six wells were completed by the Partnership’s operators. Two wells were completed by and are being operated by Whiting; the Partnership has an approximate 29% non-operated working interest in these two wells. The other four wells were completed by and are operated by Oasis; the Partnership has an approximate 8% non-operated working interest in these four wells. In total, the Partnership’s capital expenditures for the drilling and completion of these six wells were approximately $7.8 million. During 2019 and the first quarter of 2020, the Partnership elected to participate in the drilling and completion of 43 new wells in the Sanish field. Fourteen (14) of these 43 wells have been completed and were producing at March 31, 2020; the Partnership has an approximate non-operated working interest of 22% in these 14 wells. The Partnership has an estimated approximate non-operated working interest of 20% in 26 wells that are in-process as of March 31, 2020. Drilling had not commenced on the remaining three wells as of March 31, 2020; the Partnership has an approximate non-operated working interest of 19% in these three wells. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 43 wells is approximately $65 million, of which approximately $39 million was incurred as of March 31, 2020. Whiting suspended its Sanish field drilling program during the second quarter of 2020 in response to the significant reduction in demand for oil caused by COVID-19 and the oversupply of oil in the United States. The Partnership estimates it will incur approximately $5 to $7 million in additional capital expenditures during the second quarter of 2020 based upon the status of these wells upon suspension of Whiting’s drilling program. However, it is difficult to predict the amount and timing of capital expenditures, and estimated capital expenditures could be significantly different from amounts actually invested. Evaluation for Potential Impairment of Oil and Natural Gas Investments The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. The Partnership considered the declines in the current and forecasted operating cash flows resulting from COVID-19, commodity price decreases and the oversupply of oil in the United States during the first quarter of 2020 to be potential indicators of impairment and, as a result, performed a test of recoverability for the Sanish Field Assets. Estimated future net cash flows calculated in the recoverability test were based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. The underlying commodity prices used in the determination of the Partnership’s estimated future net cash flows were based on NYMEX forward strip prices as of April 1, 2020, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believed will impact realizable prices. Future operating costs estimates were based on actual historical costs of the Sanish Field Assets. The Partnership’s recoverability analyses did not identify any impairment losses as of March 31, 2020. If current macro-economic conditions continue or worsen, the carrying value of the Partnership’s oil and natural gas properties may not be recoverable and impairment losses could be recorded in future periods.

Debt

Debt	3 Months Ended
	Mar. 31, 2020
Debt Disclosure [Abstract]
Debt Disclosure [Text Block]	Note 4. Debt On November 21, 2017, the Partnership, as the borrower, entered into a loan agreement (the “Loan Agreement”), which provided for a revolving credit facility with an approved initial commitment amount of $20 million, subject to borrowing base restrictions. The maturity date was November 21, 2019. Effective September 30, 2019, the Partnership entered into an amendment and restatement of the Loan Agreement (the “Amended Loan Agreement”), which provides for the Credit Facility with an approved initial commitment of $40 million (the “Revolver Commitment Amount”), subject to borrowing base restrictions. The terms of the Amended Loan Agreement are generally similar to the Partnership’s existing revolving credit facility and include the following: (i) a maturity date of September 30, 2022; (ii) subject to certain exceptions, an interest rate, which did not change from the existing revolving credit facility, equal to the London Inter-Bank Offered Rate (LIBOR) plus a margin ranging from 2.50% to 3.50%, depending upon the Partnership’s borrowing base utilization, as calculated under the terms of the Amended Loan Agreement; (iii) an increase to the borrowing base from $30 million to an initially stipulated $40 million; and (iv) an increase to the mortgage and lenders’ first lien position from 80% to 90% of the Partnership’s owned producing oil and natural gas properties. At March 31, 2020, the outstanding balance on the Credit Facility was $40 million, and the interest rate for the Credit Facility was approximately 4.4%. At closing in October 2019, the Partnership paid an origination fee of 0.45% on the change in Revolver Commitment Amount of the Credit Facility (increase from $20 million on previous credit facility to $40 million under revised Credit Facility, or $20 million), or $90,000. The Partnership is also required to pay an unused facility fee of 0.50% on the unused portion of the Revolver Commitment Amount, based on the amount of borrowings outstanding during a quarter. The Amended Loan Agreement requires the Partnership to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production if the Partnership’s borrowing base becomes equal to or greater than 50% of the Partnership’s producing reserves as calculated by its independent petroleum engineer. If this condition is met, the risk management program must cover at least 50% of the Partnership’s projected total production of oil and natural gas for a rolling 18-month period. At December 31, 2019, the Partnership’s borrowing base of $40 million did not exceed 50% of its estimated producing reserves, and the Partnership’s reserves are next subjected to redetermination at June 30, 2020. Therefore, as of March 31, 2020, the Partnership is not required to maintain a risk management program. The Amended Loan Agreement does permit the Partnership to enter into derivative contracts with a counterparty at its own discretion so long as the term does not exceed 36 months and does not cover more than 80% of the Partnership’s projected oil and gas volumes. The Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants, each as defined in the Amended Loan Agreement, include: ● A maximum ratio of funded debt to trailing 12-month EBITDAX of 3.50 to 1.00 ● A minimum ratio of current assets to current liabilities of 1.00 to 1.00 (“Current Ratio”) ● A minimum ratio of EBITDAX to cash interest expense of 2.50 to 1.00 for trailing 12-month period ● Partnership distributions may be limited if certain terms and conditions are not met; these limitations include (i) being limited to 50% of the previous quarter EBITDAX beginning April 1, 2020 or (ii) having distributions reduced to zero if the availability under the Revolver Commitment Amount is less than 20% of the Revolver Commitment Amount. The Partnership was in compliance with each of the covenants, except the Current Ratio covenant, at March 31, 2020. As a result of not being in compliance with the Current Ratio covenant, the Partnership notified the lender group of the Credit Facility and expects to enter into a waiver agreement with the lender group that would waive compliance with the Current Ratio covenant until the calculation is due as of September 30, 2020. The terms of the waiver agreement are anticipated to include, among other items, a restriction on the Partnership’s ability to make distributions until approved by the lender group. The Partnership anticipates, based on the current operating environment, it may not be able to meet the Current Ratio covenant at September 30, 2020. If the Partnership cannot meet the Current Ratio covenant or any other covenant in future periods, it may not be able to obtain waivers and the outstanding balance under the Credit Facility may become due on demand at that time. Because the Partnership has not entered into a waiver agreement as of the date of this Form 10-Q filing and as a result of the anticipated future failure to meet the Current Ratio covenant at September 30, 2020, the Partnership reclassified the outstanding balance due under the Credit Facility to current on its March 31, 2020 consolidated balance sheet. The Partnership estimated the fair value of its Credit Facility by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity. As of March 31, 2020, the carrying value and estimated fair value of the Partnership’s outstanding debt were approximately $40 million and $33 million, respectively. As of December 31, 2019, both the carrying value and estimated fair value of the Partnership’s outstanding debt were $24 million. 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.

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation Disclosure [Text Block]	Note 5. Asset Retirement Obligations The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement costs in oil and natural gas properties in the period in which the asset retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance. The changes in the aggregate ARO are as follows: 2020 2019 Balance at January 1 $ 1,452,734 $ 1,294,067 Well additions 27,844 - Accretion 19,979 17,964 Revisions - - Balance at March 31 $ 1,500,557 $ 1,312,031

Risk Management

Risk Management	3 Months Ended
	Mar. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	Note 6. Risk Management Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. Periodically, the Partnership utilizes derivative contracts to manage the commodity price risk on the Partnership’s future oil production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations. All derivative instruments are recorded on the Partnership’s balance sheet as assets or liabilities measured at fair value. As discussed in Note 4. Debt, the Partnership will be required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production if the Partnership’s borrowing base becomes equal to or greater than 50% of the Partnership’s producing reserves as calculated by its independent petroleum engineer. At December 31, 2019, the Partnership had three outstanding monthly costless collar derivative contracts, which hedged a total of 82,000 barrels of first quarter 2020 oil production. The Partnership settled these monthly derivative contracts during the first quarter of 2020 at a gain of approximately $257,000. The Partnership also recorded a non-cash gain during the first quarter of 2020, which represents the reversal of the $184,000 derivative liability recorded at December 31, 2019 on the Partnership’s consolidated balance sheet. The Partnership did not designate its derivative instruments as hedges for accounting purposes and did not enter into such instruments for speculative trading purposes. As a result, when derivatives did not qualify or were not designated as a hedge, the changes in the fair value were recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The Partnership had no outstanding contracts at March 31, 2020. The following table presents the Partnership’s gain at settlement of its matured derivative instruments and the non-cash gain the Partnership recorded during the three months ended March 31, 2020. Three Months Ended Settlements on matured derivatives $ 257,040 Gain on mark-to-market of derivatives 183,850 Gain on derivatives $ 440,890

Capital Contribution and Partne

Capital Contribution and Partners' Equity	3 Months Ended
	Mar. 31, 2020
Partners' Capital Notes [Abstract]
Partners' Capital Notes Disclosure [Text Block]	Note 7. Capital Contribution and Partners’ Equity At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990, and the General Partner received Incentive Distribution Rights (defined below). The Partnership completed its best-efforts offering of common units on April 24, 2017. As of the conclusion of the offering on April 24, 2017, the Partnership had completed the sale of approximately 19.0 million common units for total gross proceeds of $374.2 million and proceeds net of offerings costs of $349.6 million. Under the agreement with David Lerner Associates, Inc. (the “Dealer Manager”), the Dealer Manager received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager will also be paid a contingent incentive fee, which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold based on the performance of the Partnership. Based on the common units sold through the best-efforts offering, the total contingent fee is a maximum of approximately $15.0 million. Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units. Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights or with respect to Class B units and will not make the contingent incentive payments to the Dealer Manager, until Payout occurs. The Partnership Agreement provides that Payout occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per unit, regardless of the amount paid for the unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount. All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows: ● First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement; ● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%). For the three months ended March 31, 2020 and 2019, the Partnership paid distributions of $0.241644 and $0.349041 per common unit, or $4.6 million and $6.6 million, respectively. In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to recent market volatility and the impact on the Partnership’s operating cash flows. The Partnership will accumulate unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are required to be paid before final Payout occurs, as defined above. As of March 31, 2020, the unpaid Payout Accrual totaled $0.107397 per common unit, or approximately $2.0 million. The General Partner will continue to monitor the Partnership’s distribution policy on a monthly basis in conjunction with the Partnership’s projected cash requirements for operations, capital expenditures for new wells, debt service and any restrictions under its Credit Facility. As discussed in Note 4. Debt and pursuant to the anticipated waiver to be granted by the Partnership’s lending group, the Partnership will not be permitted to pay distributions without lender approval.

Related Parties

Related Parties	3 Months Ended
	Mar. 31, 2020
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. For the three months ended March 31, 2020 and 2019, approximately $92,000 and $68,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At March 31, 2020, approximately $92,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses on the consolidated balance sheets. The members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer, David S. McKenney, Chief Financial Officer, Anthony F. Keating, III, Co-Chief Operating Officer and Michael J. Mallick, Co-Chief Operating Officer. Mr. Knight and Mr. McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy Resources 12 GP, LLC, the general partner of Energy Resources 12, L.P. (“ER12”), a limited partnership that also invests in producing and non-producing oil and gas properties on-shore in the United States. On January 31, 2018, the Partnership entered into a cost sharing agreement with ER12 that gives ER12 access to the Partnership’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 Partnership leases office space in Oklahoma City, Oklahoma on a month-to-month basis from an affiliate of the General Partner. For the three months ended March 31, 2020 and 2019, the Partnership paid $25,611 in each period, respectively, to the affiliate of the General Partner. The office space is shared between the Partnership and ER12; therefore, under the cost-sharing agreement, the monthly payment of $8,537 is split between the two partnerships. In addition to the office space, the cost-sharing agreement reduces the costs to the Partnership for accounting and asset management services provided through a member of the General Partner noted above. The compensation due to Clifford J. Merritt, President of the General Partner, is also a shared cost between the Partnership and ER12. For the three months ended March 31, 2020 and 2019, approximately $76,000 and $65,000, respectively, of expenses subject to the cost-sharing agreement were paid by the Partnership and have been or will be reimbursed by ER12. At March 31, 2020, the approximately $76,000 due to the Partnership from ER12 is included in Other current assets in the consolidated balance sheets.

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2020
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Note 9. Subsequent Events On April 1, 2020, Whiting and certain of its subsidiaries declared bankruptcy under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas. Whiting has indicated its business will operate in the normal course without material disruption to its vendors, partners or employees, including the Partnership. At this time, the Partnership is unable to estimate the impact this will have on its operating results, if any.

Accounting Policies, by Policy

Accounting Policies, by Policy (Policies)	3 Months Ended
	Mar. 31, 2020
Accounting Policies [Abstract]
Basis of Accounting, Policy [Policy Text Block]	Basis of Presentation The accompanying unaudited financial statements have been prepared in accordance with the instructions for Article 10 of SEC Regulation S-X. Accordingly, they do not include all of the information required by generally accepted accounting principles (“GAAP”) in the United States. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. These unaudited financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements included in its 2019 Annual Report on Form 10-K. Operating results for the three months ended March 31, 2020 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2020.
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.
Earnings Per Share, Policy [Policy Text Block]	Net Income Per Common Unit Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three months ended March 31, 2020 and 2019. As a result, basic and diluted outstanding common units were the same. The Class B units and Incentive Distribution Rights, as defined below, are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 7) will occur.
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Adopted Accounting Standards In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-04, Reference Rate Reform (Topic 848), which provides optional guidance through December 31, 2022 to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments in ASU No. 2020-04 apply to contract modifications that replace a reference rate affected by reference rate reform, providing optional expedients regarding the measurement of hedge effectiveness in hedging relationships that have been modified to replace a reference rate. While the guidance in ASU No. 2020-04 became effective upon issuance, the provisions of the ASU did not have a material impact on the Partnership’s consolidated financial statements and related disclosures as of March 31, 2020.
Revenue [Policy Text Block]	Revenue Recognition The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators two to three months after the date production is delivered by the operator. 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.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations [Table Text Block]	The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement costs in oil and natural gas properties in the period in which the asset retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance. The changes in the aggregate ARO are as follows: 2020 2019 Balance at January 1 $ 1,452,734 $ 1,294,067 Well additions 27,844 - Accretion 19,979 17,964 Revisions - - Balance at March 31 $ 1,500,557 $ 1,312,031

Risk Management (Tables)

Risk Management (Tables)	3 Months Ended
	Mar. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	The Partnership 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 did not qualify or were not designated as a hedge, the changes in the fair value were recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The Partnership had no outstanding contracts at March 31, 2020. The following table presents the Partnership’s gain at settlement of its matured derivative instruments and the non-cash gain the Partnership recorded during the three months ended March 31, 2020. Three Months Ended Settlements on matured derivatives $ 257,040 Gain on mark-to-market of derivatives 183,850 Gain on derivatives $ 440,890

Partnership Organization (Detai

Partnership Organization (Details) shares in Millions	Jul. 09, 2013USD ($)	Mar. 31, 2020USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2019USD ($)	Mar. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Apr. 24, 2017USD ($)shares
Partnership Organization (Details) [Line Items]
Limited Liability Company or Limited Partnership, Business, Formation State	Delaware
Partners' Capital Account, Contributions	$ 1,000
Line of Credit, Current		$ 40,000,000		$ 0	$ 40,000,000	$ 0
Capital Expenditures Incurred but Not yet Paid		$ 20,547,754	$ 20,972
Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Wells Elected to Participate in Drilling		10		33	43
Capital Expenditures, Drilling and Completion of Wells		$ 13,000,000		$ 52,000,000	$ 65,000,000
Costs Incurred, Development Costs					$ 39,000,000
Capital Expenditures Incurred but Not yet Paid		21,000,000
Minimum [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Capital Expenditures, Drilling and Completion of Wells		5,000,000
Maximum [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Capital Expenditures, Drilling and Completion of Wells		7,000,000
Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Capital Expenditures, Drilling and Completion of Wells		65,000,000				$ 7,800,000
Costs Incurred, Development Costs		39,000,000
Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member]
Partnership Organization (Details) [Line Items]
Capital Expenditures, Drilling and Completion of Wells		5,000,000
Sanish Field Located in Mountrail County, North Dakota [Member] | Maximum [Member]
Partnership Organization (Details) [Line Items]
Capital Expenditures, Drilling and Completion of Wells		$ 7,000,000
Best-Efforts Offering [Member]
Partnership Organization (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares) | shares							19
Proceeds from Issuance of Common Limited Partners Units							$ 374,200,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units							$ 349,600,000
Non-operated Completed Wells [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net		25.00%
Oil, Productive Well, Number of Wells, Net		235			235
Non-operated Wells in the Process of Drilling [Member]
Partnership Organization (Details) [Line Items]
Oil and Gas, Present Activity, Well in Process of Drilling		26			26
Non-operated Wells in the Process of Drilling [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net		20.00%
Oil and Gas, Present Activity, Well in Process of Drilling		26			26

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Details) - shares	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Accounting Policies [Abstract]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0	0

Oil and Gas Investments (Detail

Oil and Gas Investments (Details) $ in Millions	Mar. 31, 2017	Jan. 11, 2017USD ($)	Dec. 18, 2015USD ($)	Mar. 31, 2017USD ($)	Mar. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018	Mar. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					$ 13	$ 52		$ 65
Wells Elected to Participate in Drilling					10	33		43
Costs Incurred, Development Costs (in Dollars)								$ 39
Minimum [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					$ 5
Maximum [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					7
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number							6
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					65				$ 7.8
Costs Incurred, Development Costs (in Dollars)					39
Sanish Field Located in Mountrail County, North Dakota [Member] | Acquisition No. 1 [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net			11.00%
Business Combination, Consideration Transferred (in Dollars)			$ 159.6
Sanish Field Located in Mountrail County, North Dakota [Member] | Acquisition No. 2 [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net		11.00%
Business Combination, Consideration Transferred (in Dollars)		$ 128.5
Sanish Field Located in Mountrail County, North Dakota [Member] | Acquisition No. 3 [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net	10.50%
Business Combination, Consideration Transferred (in Dollars)				$ 52.4
Number of Producing Partnership Wells Acquired	82
Oil, Productive Well, Number of Wells, Net	216			216
Number of Future Development Partnership Locations Acquired	150
Gas and Oil Area Undeveloped, Net	253
Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member]
Oil and Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					5
Sanish Field Located in Mountrail County, North Dakota [Member] | Maximum [Member]
Oil and Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					$ 7
Whiting Petroleum [Member]
Oil and Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number							2
Whiting Petroleum [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number							2
Working Interest							29.00%
Oasis Petroleum, Inc. [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number							4
Working Interest							8.00%
Non-operated Completed Wells [Member]
Oil and Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number								14
Working Interest					22.00%			22.00%
Non-operated Completed Wells [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net					25.00%
Oil, Productive Well, Number of Wells, Net					235			235
Non-operated Wells in the Process of Drilling [Member]
Oil and Gas Investments (Details) [Line Items]
Working Interest					20.00%			20.00%
Oil and Gas, Present Activity, Well in Process of Drilling					26			26
Non-operated Wells in the Process of Drilling [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net					20.00%
Oil and Gas, Present Activity, Well in Process of Drilling					26			26
Wells Drilling Not Yet Commenced {Member]
Oil and Gas Investments (Details) [Line Items]
Working Interest					19.00%			19.00%
Number of Wells, Drilling not yet Commenced					3

Debt (Details)

Debt (Details) - USD ($)	Sep. 30, 2019	Nov. 21, 2017	Mar. 31, 2020	Dec. 31, 2019
Debt (Details) [Line Items]
Line of Credit, Current			$ 40,000,000	$ 0
Line of Credit Facility, Fair Value of Amount Outstanding			33,000,000	24,000,000
Long-term Line of Credit			0	$ 24,000,000
Revolving Credit Facility [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount		$ 20,000,000
Debt Instrument, Maturity Date		Nov. 21, 2019
Line of Credit, Current			$ 40,000,000
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate			4.40%
Line of Credit Facility, Commitment Fee Description	the Partnership paid an origination fee of 0.45% on the change in Revolver Commitment Amount of the Credit Facility (increase from $20 million on previous credit facility to $40 million under revised Credit Facility, or $20 million), or $90,000
Line of Credit Facility, Commitment Fee Percentage	0.45%
Line of Credit Facility, Commitment Fee Amount	$ 90,000
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.50%
Debt, Risk Management, Description	The Amended Loan Agreement requires the Partnership to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production if the Partnership’s borrowing base becomes equal to or greater than 50% of the Partnership’s producing reserves as calculated by its independent petroleum engineer. If this condition is met, the risk management program must cover at least 50% of the Partnership’s projected total production of oil and natural gas for a rolling 18-month period. At December 31, 2019, the Partnership’s borrowing base of $40 million did not exceed 50% of its estimated producing reserves, and the Partnership’s reserves are next subjected to redetermination at June 30, 2020. Therefore, as of March 31, 2020, the Partnership is not required to maintain a risk management program. The Amended Loan Agreement does permit the Partnership to enter into derivative contracts with a counterparty at its own discretion so long as the term does not exceed 36 months and does not cover more than 80% of the Partnership’s projected oil and gas volumes
Line of Credit Facility, Covenant Terms	The Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants, each as defined in the Amended Loan Agreement, include:   ●A maximum ratio of funded debt to trailing 12-month EBITDAX of 3.50 to 1.00 ●A minimum ratio of current assets to current liabilities of 1.00 to 1.00 (“Current Ratio”) ●A minimum ratio of EBITDAX to cash interest expense of 2.50 to 1.00 for trailing 12-month period  ● Partnership distributions may be limited if certain terms and conditions are not met; these limitations include (i) being limited to 50% of the previous quarter EBITDAX beginning April 1, 2020 or (ii) having distributions reduced to zero if the availability under the Revolver Commitment Amount is less than 20% of the Revolver Commitment Amount.
Line of Credit Facility, Covenant Compliance			The Partnership was in compliance with each of the covenants, except the Current Ratio covenant, at March 31, 2020.
Revolving Credit Facility [Member] | Amended Loan Agreement [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount	$ 40,000,000
Debt Instrument, Maturity Date	Sep. 30, 2022
Line of Credit Facility, Borrowing Capacity, Description	an increase to the borrowing base from $30 million to an initially stipulated $40 million
Line of Credit Facility, Collateral	an increase to the mortgage and lenders’ first lien position from 80% to 90% of the Partnership’s owned producing oil and natural gas properties
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | Amended Loan Agreement [Member] | Minimum [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.50%
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | Amended Loan Agreement [Member] | Maximum [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	3.50%

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations - USD ($)	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Schedule of Asset Retirement Obligations [Abstract]
Balance	$ 1,452,734	$ 1,294,067
Well additions	27,844	0
Accretion	19,979	17,964
Revisions	0	0
Balance	$ 1,500,557	$ 1,312,031

Risk Management (Details)

Risk Management (Details)	3 Months Ended
	Mar. 31, 2020USD ($)bbl	Dec. 31, 2019USD ($)
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Discussion of Price Risk Derivative Risk Management Policy	As discussed in Note 4. Debt, the Partnership will be required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production if the Partnership’s borrowing base becomes equal to or greater than 50% of the Partnership’s producing reserves as calculated by its independent petroleum engineer.
Number of Price Risk Derivatives Held	3
Derivative, Nonmonetary Notional Amount, Volume (in Barrels (of Oil)) | bbl	82,000
Derivative, Gain on Derivative	$ 257,000
Derivative Liability		$ 184,000

Risk Management (Details) - Sch

Risk Management (Details) - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value - USD ($)	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Abstract]
Settlements on matured derivatives	$ 257,040
Gain on mark-to-market of derivatives	183,850	$ 0
Gain on derivatives	$ 440,890	$ 0

Capital Contribution and Part_2

Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions	Jul. 09, 2013	Mar. 31, 2020	Mar. 31, 2019	Apr. 24, 2017
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Contributions	$ 1,000
Distributions to organizational limited partner	$ 990
Partners' Capital Account, Description of Units Sold		Under the agreement with David Lerner Associates, Inc. (the “Dealer Manager”), the Dealer Manager received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager will also be paid a contingent incentive fee, which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold based on the performance of the Partnership.
Managing Dealer, Selling Commissions, Percentage		6.00%
Managing Dealer, Maximum Contingent Incentive Fee on Gross Proceeds, Percentage		4.00%
Maximum Contingent Offering Costs, Selling Commissions and Marketing Expenses		$ 15,000,000
Key Provisions of Operating or Partnership Agreement, Description		The Partnership Agreement provides that Payout occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per unit, regardless of the amount paid for the unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount. All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:  ● First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement;   ● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%).
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share)		$ 0.241644	$ 0.349041
Distribution Made to Limited Partner, Cash Distributions Paid		$ 4,584,826	$ 6,622,520
Annualized Rate of Retun			7.00%
Distribution at Payout to limited partner, per common unit (in Dollars per share)		$ 0.107397
Distribution at Payout to limited partner		$ 2,000,000
Best-Efforts Offering [Member]
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares)				19
Proceeds from Issuance of Common Limited Partners Units				$ 374,200,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units				$ 349,600,000

Related Parties (Details)

Related Parties (Details) - USD ($)	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
General Partner [Member]
Related Parties (Details) [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party	$ 92,000	$ 68,000
Due to Related Parties, Current	92,000
Affiliated Entity [Member]
Related Parties (Details) [Line Items]
Operating Leases, Rent Expense	25,611	25,611
Operating Leases, Rent Expense, Minimum Rentals	8,537
Reimbursements From Related Party	76,000	$ 65,000
Due from Related Parties	$ 76,000