Energy Resources 12 10-Q 14 Nov 18 2018 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 31, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	ENERGY RESOURCES 12, L.P.
Document Type	10-Q
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		7,078,120
Amendment Flag	false
Entity Central Index Key	1,696,088
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Entity Small Business	true
Entity Emerging Growth Company	true
Entity Ex Transition Period	true

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Assets
Cash and cash equivalents	$ 5,599,013	$ 46,859,728
Oil, natural gas and natural gas liquids revenue receivable, net	3,226,980	0
Deposit for potential acquisition	0	8,750,000
Deferred acquisition costs	0	4,884,208
Total Current Assets	8,825,993	60,493,936
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $3,035,014 and $0, respectively	172,973,512	0
Other assets, net	1,650,485	0
Total Assets	183,449,990	60,493,936
Liabilities
Term loan	15,000,000	0
Accounts payable and accrued expenses	3,960,126	164,786
Due to related parties	492,371	5,283,623
Derivative liability	57,306	0
Total Current Liabilities	19,509,803	5,448,409
Revolving credit facility	44,500,000	0
Asset retirement obligations	349,745	0
Total Liabilities	64,359,548	5,448,409
Partners’ Equity
Limited partners' interest (6,485,774 and 3,191,231 common units issued and outstanding, respectively)	119,090,657	55,045,742
General partner's interest	(215)	(215)
Total Partners’ Equity	119,090,442	55,045,527
Total Liabilities and Partners’ Equity	$ 183,449,990	$ 60,493,936

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Oil and natural gas properties, successful efforts method, accumulated depreciation, depletion and amortization (in Dollars)	$ 3,035,014	$ 0
Limited partners' interest, common units issued	6,485,774	3,191,231
Limited partners' interest, common units outstanding	6,485,774	3,191,231

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenue
Oil	$ 5,062,458	$ 0	$ 15,270,432	$ 0
Natural gas	252,829	0	628,436	0
Natural gas liquids	188,419	0	633,013	0
Total revenue	5,503,706	0	16,531,881	0
Operating costs and expenses
Production expenses	945,233	0	3,213,860	0
Production taxes	548,574	0	1,487,100	0
General and administrative expenses	360,382	28,226	1,104,416	49,331
Depreciation, depletion, amortization and accretion	1,024,676	0	3,040,755	0
Total operating costs and expenses	2,878,865	28,226	8,846,131	49,331
Operating income (loss)	2,624,841	(28,226)	7,685,750	(49,331)
Loss on derivatives	(57,306)	0	(57,306)	0
Interest income (expense), net	(479,810)	40,750	(851,859)	39,645
Net income (loss)	$ 2,087,725	$ 12,524	$ 6,776,585	$ (9,686)
Basic and diluted net income (loss) per common unit (in Dollars per share)	$ 0.37	$ 0.01	$ 1.53	$ (0.02)
Weighted average common units outstanding - basic and diluted (in Shares)	5,640,746	1,409,731	4,417,011	475,074

Consolidated Statement of Cash

Consolidated Statement of Cash Flows - USD ($)	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash flow from operating activities:
Net income (loss)	$ 6,776,585	$ (9,686)
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion	3,040,755	0
Loss on mark-to-market of derivatives	57,306	0
Non-cash expenses	47,157	0
Changes in operating assets and liabilities:
Oil, natural gas and natural gas liquids revenue receivable	(3,957,023)	0
Due to related parties	(66,252)	0
Accounts payable and accrued expenses	935,821	8,358
Net cash flow provided by (used in) operating activities	6,834,349	(1,328)
Cash flow from investing activities:
Cash paid for acquisition of oil and natural gas properties	(161,390,163)	0
Additions to oil and natural gas properties	(1,798,654)	0
Net cash flow used in investing activities	(163,188,817)	0
Cash flow from financing activities:
Cash paid for loan costs	(1,697,642)	0
Proceeds from line of credit	0	229,000
Payments on line of credit	0	(229,000)
Proceeds from term loan	25,000,000	0
Payments on term loan	(10,000,000)	0
Net proceeds from revolving credit facility	44,500,000	0
Proceeds from advance from member of general partner	7,000,000	0
Payments on advance from member of general partner	(7,000,000)	0
Net proceeds related to issuance of units	61,878,639	45,420,915
Distributions paid to limited partners	(4,587,244)	(477,744)
Net cash flow provided by financing activities	115,093,753	44,943,171
Increase (decrease) in cash and cash equivalents	(41,260,715)	44,941,843
Cash and cash equivalents, beginning of period	46,859,728	1,000
Cash and cash equivalents, end of period	5,599,013	44,942,843
Interest paid	$ 606,395	$ 1,420

Partnership Organization

Partnership Organization	9 Months Ended
	Sep. 30, 2018
Disclosure Text Block [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 is offering common units of limited partner interest (the “common units”) on a best-efforts basis with the intention of raising up to $350,000,001 of capital, consisting of 17,631,579 common units. The Partnership’s offering was declared effective by the Securities and Exchange Commission (“SEC”) on May 17, 2017. 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 has been admitting additional Limited Partners monthly since that time. As of September 30, 2018, the Partnership owned an approximate 6.0% non-operated working interest in 243 currently producing wells and 47 wells in various stages of the drilling and completion process, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, 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”), is acting as 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	9 Months Ended
	Sep. 30, 2018
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 for complete financial statements. 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 December 31, 2017 financial statements included in its 2017 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 2018 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2018. 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. Offering Costs The Partnership is raising capital through an on-going best-efforts offering of units by the Managing Dealer, which receives a selling commission and a marketing expense allowance based on proceeds of the units sold. Additionally, the Partnership has incurred other offering costs including legal, accounting and reporting services. These offering costs are recorded by the Partnership as a reduction of partners’ equity. As of September 30, 2018, the Partnership had completed the sale of 6.5 million common units for gross proceeds of approximately $127.1 million and proceeds net of offering costs of approximately $118.9 million. 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. The Partnership does not operate its oil and natural gas properties and receives actual oil, natural gas and natural gas liquids (“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. Therefore, the Partnership has used the most current available production data gathered from its operators and the Oil and Gas Division of the North Dakota Industrial Commission, and oil, natural gas and NGL national index prices 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 or the settlement proceeds are received. Reclassifications Certain prior period amounts in the consolidated financial statements have been reclassified to conform to the current period presentation with no effect on previously reported net income, partners’ equity or cash flows. Net Income (Loss) Per Common Unit Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three and nine months ended September 30, 2018. As a result, basic and diluted outstanding common units were the same. The Incentive Distribution Rights (as discussed in Note 8) are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 8) will occur. Revenue Recognition Since it did not acquire any assets until 2018, the Partnership did not record any revenue in 2017. The Partnership is bound by a joint operating agreement with the operator of each of its producing and in-process wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. 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. 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. Settlement receipts for sales of oil, natural gas and natural gas liquids may not be received for more than a month after the date production is delivered to the purchaser, and as a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Partnership records the differences between estimates and the actual amounts received for product sales in the month that settlement proceeds are received from the operator. The Partnership disaggregates its revenue on the face of the consolidated statements of operations for the three and nine months ended September 30, 2018. Recently Adopted Accounting Standards In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815), Targeted Improvements to Accounting for Hedging Activities In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) Recently Issued Accounting Standards In February 2016, the FASB issued 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 standard is effective for annual and interim periods beginning after December 15, 2018 with early adoption permitted. The Partnership expects to adopt this standard as of January 1, 2019. Although the Partnership has not yet identified any material impact, the Partnership is still evaluating the impact this standard will have on its consolidated financial statements and related disclosures.

Oil and Gas Investments

Oil and Gas Investments	9 Months Ended
	Sep. 30, 2018
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 purchase (“Acquisition No. 1”) of an approximate average 3.1% non-operated working interest in the Bakken Assets for approximately $87.5 million. Acquisition No. 1 was funded using proceeds from the Partnership’s best-efforts offering, proceeds from an unsecured term loan of $25.0 million (discussed below in Note 5. Debt), and an advance from a member of the General Partner, of $7.0 million. 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. At closing, the Partnership’s interest in the Bakken Assets was comprised of approximately 204 existing producing wells, 30 wells in various stages of the drilling and completion process and additional future development locations. 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 Partnership capitalized approximately $5.0 million in transaction costs in conjunction with Acquisition No. 1. The Partnership also recorded an asset retirement obligation liability of approximately $0.1 million in conjunction with this acquisition. See Note 4. Asset Retirement Obligation below. The Partnership adjusted the purchase price to reflect the operating revenues and expenses of Acquisition No. 1 between the acquisition effective date of September 1, 2017 and the closing date of February 1, 2018, in accordance with the closing conditions set forth in the purchase agreement. The net impact of the purchase price adjustments was a decrease to the purchase price of the asset of approximately $2.1 million. Since closing on Acquisition No. 1 on February 1, 2018, the Partnership participated in the drilling of 78 wells, of which 38 have been completed and 40 wells were in various stages of completion at August 30, 2018. As of August 30, 2018, the Partnership owned an approximate 3.1% non-operated working interest in 242 currently producing wells, 40 wells in various stages of the drilling and completion process, and additional future development locations in the Bakken Assets. On August 31, 2018, the Partnership completed its purchase (“Acquisition No. 2”) of an additional non-operated working interest in the Bakken Assets for approximately $82.5 million, subject to customary adjustments, and 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 5. Debt). 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. During the third quarter of 2018, the Partnership adjusted the purchase price of Acquisition No. 2 to reflect the Partnership’s estimate of 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 estimate, which is preliminary and was derived from operator revenue and expense statements received from the seller, reduced the purchase price of the Bakken Assets by approximately $5.7 million. In accordance with the terms of the purchase agreement, the Partnership and the seller will agree to the final settlement of operating revenues and expenses between the effective and closing dates of the acquisition after all operator information has been received, and the Partnership will adjust its estimate at that time. 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 will be amortized over the life of the revolving credit facility described in Note 5. Debt. The deferred loan costs are recorded as Other assets, net on the Partnership’s consolidated balance sheet. REI is 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 are available after Payout to the holders of the Partnership’s common units, as defined in Note 8 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. See Note 9. Related Parties below for additional information. The following unaudited pro forma financial information for the three and nine months ended September 30, 2018 and 2017 have been prepared as if Acquisitions No.1 and No. 2 of the Bakken Assets had occurred on January 1, 2017. 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. Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended Revenues $ 8,502,204 $ 8,662,277 $ 33,834,094 $ 21,124,520 Net income 4,482,246 3,819,872 15,388,742 7,715,023 As of September 30, 2018, the Partnership’s ownership of the Bakken Assets consisted of an approximate 6.0% non-operated working interest in 243 currently producing wells and 47 wells in various stages of the drilling and completion process. Since completing Acquisition No. 1 through September 30, 2018, the Partnership incurred approximately $5.6 million in capital drilling and completion costs. During this period, the Partnership participated in the drilling of 86 wells, of which 39 have been completed and 47 wells are in various stages of completion at September 30, 2018. The Partnership anticipates approximately $22 million remain to complete the 47 wells in various stages of completion.

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation Disclosure [Text Block]	Note 4. 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: 2018 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 40,025 Accretion 5,742 Balance as of September 30, 2018 $ 349,745

Debt

Debt	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Debt Disclosure [Text Block]	Note 5. Debt On January 16, 2018, the Partnership entered into a loan agreement with Bank of America, N.A. (“BOA”), as the lender, for an unsecured term loan (“Term Loan”) of $25.0 million. The Term Loan bears interest at a variable rate based on the London Inter-Bank Offered Rate (LIBOR) plus a margin of 2.00%. Interest is payable monthly. The Partnership used the $25.0 million proceeds from the Term Loan to fund Acquisition No. 1, as described in Note 3. Oil and Gas Investments above. Under the terms of the loan agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. However, as discussed below, prepayments are limited under the terms of the Credit Facility. The Term Loan contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Messrs. Knight and McKenney have guaranteed repayment of the Term Loan and have not and will 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 (collectively, the “Lender”), which provides for a revolving credit facility (the “Credit Facility”) with an initial commitment amount of $60 million (the “Revolver Commitment Amount”), subject to borrowing base restrictions. The commitment amount may be increased up to $100 million with Lender approval. At closing, the Partnership paid an origination fee of 0.50% of the Revolver Commitment Amount, or $300,000, and is subject to additional origination fees of 0.50% for any increase to the commitment made in excess of the Revolver Commitment Amount. The Partnership is also required to pay an unused facility fee at an annual rate of 0.50% on the unused portion of the Revolver Commitment Amount, based on the amount of borrowings outstanding during a quarter. The maturity date is August 31, 2021 (“Maturity Date”). Under the Loan Agreement, the initial borrowing base is $60 million. However, the borrowing base is subject to redetermination semi-annually based upon the Lender’s analysis of the Partnership’s proven oil and natural gas reserves. In addition, the Partnership’s monthly mandatory principal payments (discussed below) reduce the Partnership’s borrowing base; the borrowing base minimum is $40 million. Outstanding borrowings under the Credit Facility cannot exceed the lesser of the borrowing base or the Revolver Commitment Amount at any time. The interest rate, subject to certain exceptions, is equal to the London Inter-Bank Offered Rate (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. In addition to monthly interest payments on the outstanding principal balance of the note, the Partnership (subject to certain exceptions) must make mandatory principal payments monthly in an amount equal to 100% of the net proceeds the Partnership receives from the sale of its equity securities until the principal amount of the note is reduced to $40 million. The Partnership is required to reduce the outstanding principal amount of the note to at or below $40 million by March 15, 2019. The Loan Agreement also 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. The program must cover at least 80% of the Partnership’s total monthly production of oil and natural gas through March 31, 2019, and from April 1, 2019 to the Maturity Date, the program must cover at least 50% of the Partnership’s total monthly oil and natural gas production. See additional detail in Note 7. Risk Management. At closing, the Partnership borrowed $60.0 million. The proceeds were used to fund the purchase of Acquisition No. 2 described above and to pay closing costs. Subject to availability, the Credit Facility may also provide additional liquidity for future capital investments, including the drilling and completion of proposed wells by the operators of the Partnership’s properties, and other corporate working capital requirements. Under the terms of the Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells. The Credit Facility contains mandatory prepayment requirements (including those described above), customary affirmative and negative covenants and events of default. The financial covenants as defined in the Loan Agreement include: ● a maximum leverage ratio ● a minimum current ratio ● maximum distributions The Partnership was in compliance with the applicable covenants at September 30, 2018. As a condition to closing on the Credit Facility, the Partnership was required to extend the maturity of Term Loan with BOA to April 15, 2019 from its original maturity date of January 15, 2019. Also, BOA was required to consent to the Partnership entering into the Credit Facility. The Partnership and BOA amended the Term Loan on August 16, 2018, whereby BOA gave consent and extended the maturity date. Under the Credit Facility, no principal payments can be made on the BOA loan until the outstanding balance on the Credit Facility is less than $40.0 million. As of September 30, 2018, the outstanding balance and the applicable interest rate on the Term Loan were $15.0 million and 4.25%, respectively. As of September 30, 2018, the outstanding balance and the applicable interest rate on the Credit Facility were $44.5 million and 5.71%, respectively. The outstanding balances at September 30, 2018 approximate the fair market value of the Term Loan and Credit Facility. The Partnership estimated the fair values of its Term Loan and 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.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value Disclosures [Text Block]	Note 6. Fair Value of Financial Instruments The Partnership follows authoritative guidance related to fair value measurement and disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement using market participant assumptions at the measurement date. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The three levels are defined as follows: ● Level 1: Quoted prices in active markets for identical assets ● Level 2: Significant other observable inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, either directly or indirectly, for substantially the full term of the financial instrument ● Level 3: Significant unobservable inputs The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and the consideration of factors specific to the asset or liability. The Partnership’s policy is to recognize transfers in or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Partnership has consistently applied the valuation techniques discussed above for all periods presented. During the three and nine months ended September 30, 2018 and 2017, 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 Partnership did not have any financial assets and liabilities that were accounted for at fair value as of December 31, 2017, except for those instruments discussed below in “Fair Value of Other Financial Instruments.” The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2018. Fair Value Measurements at September 30, 2018 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current assets $ - $ - $ - Commodity derivatives - current liabilities - (57,306 ) - Total $ - $ (57,306 ) $ - 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 in Derivative liability at September 30, 2018. See additional detail in Note 7. Risk Management. Fair Value of Other Financial Instruments The carrying value of the Partnership’s cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments. In addition, see Note 5. Debt for the fair value discussion on the Partnership’s debt.

Risk Management

Risk Management	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	Note 7. Risk Management Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. As required under the Credit Facility, in September 2018, the Partnership began to utilize 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 of September 30, 2018, the Partnership’s costless collar derivative instruments were in a net loss position; therefore, a current liability of approximately $0.1 million, which approximates its fair value, was recognized as a Derivative liability on the Partnership’s consolidated balance sheet. The Partnership has not designated its derivative instruments as hedges for accounting purposes and has not entered into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value, in addition to gains or losses on settlements, are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The Partnership recognized a mark-to-market loss of approximately $0.1 million for the three and nine months ended September 30, 2018, which was recorded on the consolidated statements of operations as Loss on derivatives. No derivative contracts had been settled at September 30, 2018. The Partnership determines the estimated fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets and quotes from third parties, among other things. The Partnership also performs an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Partnership assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually-required payments. Additionally, the Partnership considers that it is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. See additional discussion above in Note 6. Fair Value of Financial Instruments. At September 30, 2018, the Partnership had one derivative contract, which was a costless collar, and was used to establish floor and ceiling prices on future anticipated oil production. The Partnership did not pay or receive a premium related to the costless collar agreement. The contract is settled monthly and there were no settlement payables or receivables at September 30, 2018. The follow table reflects the open costless collar agreement as of September 30, 2018. Settlement Period Basis Oil (Barrels) Floor / Ceiling Prices ($) Fair Value of Asset / (Liability) at 10/01/18 - 10/31/18 NYMEX 42,000 $ 65.00 / 73.10 $ (57,306 ) The Partnership’s outstanding derivative instrument is covered by an International Swap Dealers Association Master Agreement (“ISDA”) entered into with the counterparty. The ISDA may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately. The Partnership has netting arrangements with the counterparty that provide for offsetting payables against receivables from separate derivative instruments.

Capital Contribution and Partne

Capital Contribution and Partners' Equity	9 Months Ended
	Sep. 30, 2018
Partners' Capital Notes [Abstract]
Partners' Capital Notes Disclosure [Text Block]	Note 8 . Capital Contribution and Partners’ Equity At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990, 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. As of July 25, 2017, the Partnership completed its minimum offering of 1,315,790 common units at $19.00 per common unit. In October 2017, the Partnership completed the sale of all common units at $19.00 (2,631,579 common units). In accordance with the prospectus, all subsequent common units are being sold at $20.00 per common unit. As of September 30, 2018, the Partnership had completed the sale of 6.5 million common units for gross proceeds of approximately $127.1 million and proceeds net of offering costs of approximately $118.9 million. The Partnership intends to continue to raise capital through its best-efforts offering of common units by the Managing Dealer at $20.00. Under the agreement with the Managing Dealer, the Managing Dealer receives 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 September 30, 2018, the Dealer Manager Incentive Fees are approximately $5.1 million, subject to Payout (defined below). 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 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 three and nine months ended September 30, 2018, the Partnership paid distributions of $0.349041 and $1.047123 per common unit, or $2.0 million and $4.6 million, respectively. For the three and nine months ended September 30, 2017, the Partnership paid distributions of $0.249316 per common unit, or $0.5 million.

Related Parties

Related Parties	9 Months Ended
	Sep. 30, 2018
Related Party Transactions [Abstract]
Related Party Transactions Disclosure [Text Block]	Note 9 . 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 September 30, 2018, the management fee for the three and nine months ended September 30, 2018 due to the General Partner is approximately $159,000 and $344,000, respectively. As of September 30, 2018, the accrued management fee due to the General Partner is approximately $344,000, which has been accrued on the consolidated balance sheets in Due to related parties at September 30, 2018 and 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 three and nine months ended September 30, 2018, approximately $84,000 and $267,000 of general and administrative costs were incurred by a member of the General Partner and will be reimbursed by the Partnership. At September 30, 2018, approximately $84,000 was due to a member of the General Partner and is included in Due to related parties in the consolidated balance sheets. 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. 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. As noted above, 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 three and nine months ended September 30, 2018, approximately $64,000 and $175,000, respectively, of expenses subject to the cost sharing agreement were incurred by the Partnership and will be reimbursed to Energy 11. At September 30, 2018, approximately $64,000 is due from the Partnership to Energy 11 and is included in Due to related parties in the consolidated balance sheets.

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2018
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Note 10 . Subsequent Events In October 2018, the Partnership declared and paid $0.7 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units. In October 2018, the Partnership closed on the issuance of approximately 0.6 million common units through its ongoing best-efforts offering, representing gross proceeds to the Partnership of approximately $11.8 million and proceeds net of selling and marketing costs of approximately $11.1 million. The Partnership used the net proceeds to reduce its outstanding debt obligations discussed in Note 5. Debt. The Partnership paid $5.0 million against the Credit Facility, reducing the outstanding balance to $39.5 million. Therefore, because the outstanding balance of the Credit Facility was reduced below $40.0 million, the Partnership is no longer required to make monthly mandatory principal repayments. The Partnership also paid $5.0 million against the Term Loan, reducing the outstanding balance to $10.0 million.

Accounting Policies, by Policy

Accounting Policies, by Policy (Policies)	9 Months Ended
	Sep. 30, 2018
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 for complete financial statements. 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 December 31, 2017 financial statements included in its 2017 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 2018 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2018.
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.
Offering Costs, Policy [Policy Text Block]	Offering Costs The Partnership is raising capital through an on-going best-efforts offering of units by the Managing Dealer, which receives a selling commission and a marketing expense allowance based on proceeds of the units sold. Additionally, the Partnership has incurred other offering costs including legal, accounting and reporting services. These offering costs are recorded by the Partnership as a reduction of partners’ equity. As of September 30, 2018, the Partnership had completed the sale of 6.5 million common units for gross proceeds of approximately $127.1 million and proceeds net of offering costs of approximately $118.9 million.
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. The Partnership does not operate its oil and natural gas properties and receives actual oil, natural gas and natural gas liquids (“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. Therefore, the Partnership has used the most current available production data gathered from its operators and the Oil and Gas Division of the North Dakota Industrial Commission, and oil, natural gas and NGL national index prices 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 or the settlement proceeds are received.
Reclassification, Policy [Policy Text Block]	Reclassifications Certain prior period amounts in the consolidated financial statements have been reclassified to conform to the current period presentation with no effect on previously reported net income, partners’ equity or cash flows.
Earnings Per Share, Policy [Policy Text Block]	Net Income (Loss) Per Common Unit Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three and nine months ended September 30, 2018. As a result, basic and diluted outstanding common units were the same. The Incentive Distribution Rights (as discussed in Note 8) are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 8) will occur.
Revenue Recognition, Policy [Policy Text Block]	Revenue Recognition Since it did not acquire any assets until 2018, the Partnership did not record any revenue in 2017. The Partnership is bound by a joint operating agreement with the operator of each of its producing and in-process wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. 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. 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. Settlement receipts for sales of oil, natural gas and natural gas liquids may not be received for more than a month after the date production is delivered to the purchaser, and as a result, the Partnership is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Partnership records the differences between estimates and the actual amounts received for product sales in the month that settlement proceeds are received from the operator. The Partnership disaggregates its revenue on the face of the consolidated statements of operations for the three and nine months ended September 30, 2018.
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Adopted Accounting Standards In August 2017, the FASB issued ASU No. 2017-12, Derivatives and Hedging (Topic 815), Targeted Improvements to Accounting for Hedging Activities In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606) Recently Issued Accounting Standards In February 2016, the FASB issued 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 standard is effective for annual and interim periods beginning after December 15, 2018 with early adoption permitted. The Partnership expects to adopt this standard as of January 1, 2019. Although the Partnership has not yet identified any material impact, the Partnership is still evaluating the impact this standard will have on its consolidated financial statements and related disclosures.

Oil and Gas Investments (Tables

Oil and Gas Investments (Tables)	9 Months Ended
	Sep. 30, 2018
Oil and Gas Property [Abstract]
Business Acquisition, Pro Forma Information [Table Text Block]	The following unaudited pro forma financial information for the three and nine months ended September 30, 2018 and 2017 have been prepared as if Acquisitions No.1 and No. 2 of the Bakken Assets had occurred on January 1, 2017. 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. Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended Revenues $ 8,502,204 $ 8,662,277 $ 33,834,094 $ 21,124,520 Net income 4,482,246 3,819,872 15,388,742 7,715,023

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations [Table Text Block]	The changes in the aggregate ARO are as follows: 2018 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 40,025 Accretion 5,742 Balance as of September 30, 2018 $ 349,745

Fair Value of Financial Instr_2

Fair Value of Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2018. Fair Value Measurements at September 30, 2018 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current assets $ - $ - $ - Commodity derivatives - current liabilities - (57,306 ) - Total $ - $ (57,306 ) $ -

Risk Management (Tables)

Risk Management (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments [Table Text Block]	The follow table reflects the open costless collar agreement as of September 30, 2018. Settlement Period Basis Oil (Barrels) Floor / Ceiling Prices ($) Fair Value of Asset / (Liability) at 10/01/18 - 10/31/18 NYMEX 42,000 $ 65.00 / 73.10 $ (57,306 )

Partnership Organization (Detai

Partnership Organization (Details)	Dec. 30, 2016USD ($)shares	Jul. 25, 2017shares	Sep. 30, 2018
Partnership Organization (Details) [Line Items]
Limited Liability Company or Limited Partnership, Business, Formation State	Delaware
Partners' Capital Account, Contributions (in Dollars) | $	$ 1,000
Total Amount of Unit Offering (in Dollars) | $	$ 350,000,001
Total Amount of Units Offered (in Shares) | shares	17,631,579
Minimum Unit Offering, Shares (in Shares) | shares		1,315,790
Bakken Assets [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net			6.00%
Productive Oil Wells, Number of Wells, Net			243
Wells in Process of Drilling			47
Number of Operators			14

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	1 Months Ended	21 Months Ended
	Oct. 31, 2017	Sep. 30, 2018
Accounting Policies [Abstract]
Partners' Capital Account, Units, Sale of Units (in Shares)	2,631,579	6,500,000
Proceeds from Issuance of Common Limited Partners Units		$ 127.1
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units		$ 118.9

Oil and Gas Investments (Detail

Oil and Gas Investments (Details) - Bakken Assets [Member] $ in Millions	Aug. 31, 2018USD ($)	Aug. 30, 2018	Feb. 01, 2018USD ($)	Sep. 30, 2018USD ($)	Mar. 31, 2018USD ($)	Aug. 30, 2018	Sep. 30, 2018USD ($)	Sep. 30, 2018USD ($)
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net		3.10%						6.00%
Productive Oil Wells, Number of Wells, Net		242		243		242	243	243
Wells in Process of Drilling		40		47		40	47	47
Wells Drilled						78	86
Development Wells Drilled, Net Productive		38					39
Costs Incurred, Development Costs				$ 2.7			$ 5.6
Deferred Costs				1.4			$ 1.4	$ 1.4
Capital Expenditures Drilling and Completion of Wells								$ 22
Affiliated Entity [Member]
Oil and Gas Investments (Details) [Line Items]
Advisory and Consulting Services Related Party					$ 5.3
Asset Disposal Fee, Related Party, Percentage					5.00%
Acquisition No. 1 [Member]
Oil and Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net			3.10%
Business Combination, Consideration Transferred			$ 87.5
Proceeds from Issuance of Unsecured Debt			25
Proceeds from Related Party Debt			$ 7
Productive Oil Wells, Number of Wells, Net			204
Wells in Process of Drilling			30
Acquisition Costs, Period Cost					$ 5
Asset Retirement Obligation, Liabilities Incurred					0.1
Non-cash Transaction Increase in Accounts Receivable Settlement of Pre-close Activity			$ 2.1
Acquisition No. 1 [Member] | Affiliated Entity [Member]
Oil and Gas Investments (Details) [Line Items]
Acquisition Costs, Period Cost					$ 4.7
Acquisition No. 2 [Member]
Oil and Gas Investments (Details) [Line Items]
Business Combination, Consideration Transferred	$ 82.5
Acquisition Costs, Period Cost	2.9
Proceeds from Lines of Credit	$ 60
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Financial Assets				5.7
Acquisition No. 2 [Member] | Affiliated Entity [Member]
Oil and Gas Investments (Details) [Line Items]
Acquisition Costs, Period Cost				$ 4.1

Oil and Gas Investments (Deta_2

Oil and Gas Investments (Details) - Business Acquisition, Pro Forma Information - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Business Acquisition, Pro Forma Information [Abstract]
Revenues	$ 8,502,204	$ 8,662,277	$ 33,834,094	$ 21,124,520
Net income	$ 4,482,246	$ 3,819,872	$ 15,388,742	$ 7,715,023

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2018USD ($)
Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations [Line Items]
Balance	$ 0
Well additions	40,025
Accretion	5,742
Balance	349,745
Acquisition No. 1 [Member]
Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations [Line Items]
Well additions	133,155
Acquisition No. 2 [Member]
Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations [Line Items]
Well additions	$ 170,823

Debt (Details)

Debt (Details) - USD ($)	Aug. 31, 2018	Jan. 16, 2018	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Debt (Details) [Line Items]
Proceeds from Issuance of Unsecured Debt			$ 25,000,000	$ 0
Proceeds from Lines of Credit			0	$ 229,000
Unsecured Debt, Current			$ 15,000,000		$ 0
Debt Instrument, Interest Rate at Period End			4.25%
Long-term Line of Credit			$ 44,500,000		$ 0
Line of Credit Facility, Interest Rate at Period End			5.71%
Revolving Credit Facility [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount	$ 60,000,000
Debt Instrument, Payment Terms	In addition to monthly interest payments on the outstanding principal balance of the note, the Partnership (subject to certain exceptions) must make mandatory principal payments monthly in an amount equal to 100% of the net proceeds the Partnership receives from the sale of its equity securities until the principal amount of the note is reduced to $40 million. The Partnership is required to reduce the outstanding principal amount of the note to at or below $40 million by March 15, 2019.
Line of Credit Facility, Borrowing Capacity, Description	The commitment amount may be increased up to $100 million with Lender approval.
Line of Credit Facility, Commitment Fee Percentage	0.50%
Line of Credit Facility, Commitment Fee Amount	$ 300,000
Line of Credit Facility, Commitment Fee in Excess of Revolver Amount, Percentage	0.50%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.50%
Debt Instrument, Maturity Date	Aug. 31, 2021
Proceeds from Lines of Credit	$ 60,000,000
Line of Credit, Commodity Price Risk, Description	The Loan Agreement also 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. The program must cover at least 80% of the Partnership’s total monthly production of oil and natural gas through March 31, 2019, and from April 1, 2019 to the Maturity Date, the program must cover at least 50% of the Partnership’s total monthly oil and natural gas production.
Line of Credit Facility, Collateral	The Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells.
Line of Credit Facility, Covenant Terms	The Credit Facility contains mandatory prepayment requirements (including those described above), customary affirmative and negative covenants and events of default. The financial covenants as defined in the Loan Agreement include: ●a maximum leverage ratio ●a minimum current ratio ●maximum distributions
Line of Credit Facility, Covenant Compliance			The Partnership was in compliance with the applicable covenants at September 30, 2018.
Notes Payable to Banks [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount		$ 25,000,000
Proceeds from Issuance of Unsecured Debt		$ 25,000,000
Debt Instrument, Payment Terms	Under the Credit Facility, no principal payments can be made on the BOA loan until the outstanding balance on the Credit Facility is less than $40.0 million.	Under the terms of the loan agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. However, as discussed below, prepayments are limited under the terms of the Credit Facility. The Term Loan contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default.
Guarantor Obligations, Origin and Purpose		Knight and McKenney have guaranteed repayment of the Term Loan and have not and will not receive any consideration in exchange for providing this guarantee.
Debt Instrument, Maturity Date	Apr. 15, 2019	Jan. 15, 2019
London Interbank Offered Rate (LIBOR) [Member] | Notes Payable to Banks [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate		2.00%
London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member] | Revolving Credit Facility [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.75%
London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member] | Revolving Credit Facility [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	3.75%

Fair Value of Financial Instr_3

Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	Sep. 30, 2018USD ($)
Fair Value, Inputs, Level 1 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current assets	$ 0
Commodity derivatives - current liabilities	0
Total	0
Fair Value, Inputs, Level 2 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current assets	0
Commodity derivatives - current liabilities	(57,306)
Total	(57,306)
Fair Value, Inputs, Level 3 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current assets	0
Commodity derivatives - current liabilities	0
Total	$ 0

Risk Management (Details)

Risk Management (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Liability, Current	$ 57,306		$ 57,306		$ 0
Derivative, Gain (Loss) on Derivative, Net	$ (57,306)	$ 0	$ (57,306)	$ 0

Risk Management (Details) - Sch

Risk Management (Details) - Schedule of Derivative Instruments - 10/01/18 - 10/31/18 [Member] - Price Risk Derivative [Member] - Costless Collar Agreements #1 [Member]	9 Months Ended
	Sep. 30, 2018USD ($)$ / itembbl
Derivative [Line Items]
Basis	NYMEX
Oil (Barrels) (in Barrels (of Oil)) | bbl	42,000
Floor Price	65
Ceiling Price	73.10
Fair Value of Asset / (Liability) (in Dollars) | $	$ (57,306)

Capital Contribution and Part_2

Capital Contribution and Partners' Equity (Details) - USD ($)	Dec. 30, 2016	Oct. 31, 2017	Sep. 30, 2018	Sep. 30, 2017	Jul. 25, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017	Sep. 30, 2018
Partners' Capital Notes [Abstract]
Partners' Capital Account, Contributions	$ 1,000
Partners' Capital Account, Return of Contribution Upon Minimum Offering								$ 990
Minimum Unit Offering, Shares (in Shares)					1,315,790
Partners Capital Account, Units Sold, Price Per Unit (in Dollars per share)		$ 19			$ 19
Partners' Capital Account, Units, Sale of Units (in Shares)		2,631,579							6,500,000
Proceeds from Issuance of Common Limited Partners Units									$ 127,100,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units									$ 118,900,000
Partners' Capital Account, Description of Units Sold						The Partnership intends to continue to raise capital through its best-efforts offering of common units by the Managing Dealer at $20.00. Under the agreement with the Managing Dealer, the Managing Dealer receives 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						$ 5,100,000
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)			$ 0.349041	$ 0.249316		$ 1.047123	$ 0.249316
Distribution Made to Limited Partner, Cash Distributions Paid			$ 2,000,000	$ 500,000		$ 4,587,244	$ 477,744

Related Parties (Details)

Related Parties (Details) - USD ($)	1 Months Ended	3 Months Ended	9 Months Ended
	Jan. 31, 2018	Sep. 30, 2018	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
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		$ 492,371	$ 492,371		$ 5,283,623
Proceeds from Related Party Debt			7,000,000	$ 0
General Partner [Member]
Related Parties (Details) [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party		84,000	267,000
Due to Related Parties, Current		84,000	84,000
Proceeds from Related Party Debt	$ 7,000,000
Energy 11 [Member]
Related Parties (Details) [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party		64,000	175,000
Due to Related Parties, Current		64,000	64,000
Management Fee [Member] | General Partner [Member]
Related Parties (Details) [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party		159,000	344,000
Due to Related Parties, Current		$ 344,000	$ 344,000

Subsequent Events (Details)

Subsequent Events (Details) - Subsequent Event [Member] $ / shares in Units, shares in Millions, $ in Millions	1 Months Ended
	Oct. 31, 2018USD ($)$ / sharesshares
Subsequent Events (Details) [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid	$ 0.7
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share) | $ / shares	$ 0.107397
Best-Efforts Offering [Member]
Subsequent Events (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares) | shares	0.6
Proceeds from Issuance of Common Limited Partners Units	$ 11.8
Proceeds, Net of Selling Commissions and Marketing Expenses, from Issuance of Common Limited Partners Units	11.1
Revolving Credit Facility [Member]
Subsequent Events (Details) [Line Items]
Repayments of Lines of Credit	5
Long-term Line of Credit	39.5
Bank of America Term Loan [Member]
Subsequent Events (Details) [Line Items]
Repayments of Debt	5
Notes Payable	$ 10