Energy 11 10-Q 2 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 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	1,581,552
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	$ 1,067,725	$ 11,090,846
Oil, natural gas and natural gas liquids revenue receivable	8,857,375	6,219,193
Other current assets	239,644	162,930
Total Current Assets	10,164,744	17,472,969
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $37,589,707 and $24,934,190, respectively	316,315,999	321,766,616
Total Assets	326,480,743	339,239,585
Liabilities
Accounts payable and accrued expenses	3,515,177	2,733,131
Derivative liability	1,437,732	1,026,965
Total Current Liabilities	4,952,909	3,760,096
Revolving credit facility	13,800,000	20,000,000
Asset retirement obligations	1,277,270	1,226,879
Total Liabilities	20,030,179	24,986,975
Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)	306,452,291	314,254,337
General partner's interest	(1,727)	(1,727)
Class B Units (62,500 units issued and outstanding, respectively)	0	0
Total Partners’ Equity	306,450,564	314,252,610
Total Liabilities and Partners’ Equity	$ 326,480,743	$ 339,239,585

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parentheticals) - USD ($)	Sep. 30, 2018	Dec. 31, 2017
Oil and natural gas properties, accumulated depreciation, depletion and amortization (in Dollars)	$ 37,589,707	$ 24,934,190
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		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues
Oil	$ 13,600,381	$ 8,044,196	$ 36,403,912	$ 25,027,671
Natural gas	748,818	701,681	2,233,675	2,212,921
Natural gas liquids	1,339,689	972,119	3,542,357	2,827,410
Total revenue	15,688,888	9,717,996	42,179,944	30,068,002
Operating costs and expenses
Production expenses	2,914,785	3,163,269	8,536,265	8,730,586
Production taxes	1,365,925	818,455	3,657,937	2,549,454
General and administrative expenses	343,955	290,094	1,042,228	1,123,992
Depreciation, depletion, amortization and accretion	4,481,712	4,058,852	12,705,908	11,295,441
Total operating costs and expenses	9,106,377	8,330,670	25,942,338	23,699,473
Operating income	6,582,511	1,387,326	16,237,606	6,368,529
Loss on derivatives	(38,921)	0	(2,943,000)	0
Interest expense, net	(183,480)	(106,767)	(574,127)	(480,495)
Total other expense, net	(222,401)	(106,767)	(3,517,127)	(480,495)
Net income	$ 6,360,110	$ 1,280,559	$ 12,720,479	$ 5,888,034
Basic and diluted net income per common unit (in Dollars per share)	$ 0.34	$ 0.07	$ 0.67	$ 0.33
Weighted average common units outstanding - basic and diluted (in Shares)	18,973,474	18,973,474	18,973,474	17,822,804

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($)	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash flow from operating activities:
Net income (loss)	$ 12,720,479	$ 5,888,034
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion	12,705,908	11,295,441
Loss on derivatives	410,768	0
Non-cash expenses, net	33,749	71,128
Oil, natural gas and natural gas liquids revenue receivable	(2,638,182)	(2,752,079)
Other current assets	(108,618)	(85,529)
Accounts payable and accrued expenses	837,721	1,178,839
Net cash flow provided by operating activities	23,961,825	15,595,834
Cash flow from investing activities:
Cash paid for acquisition of oil and natural gas properties	0	(98,250,130)
Additions to oil and natural gas properties	(7,260,576)	(1,301,065)
Net cash flow used in investing activities	(7,260,576)	(99,551,195)
Cash flow from financing activities:
Cash paid for loan costs	(1,845)	0
Payments on revolving credit facility	(6,200,000)	0
Net proceeds related to issuance of units	0	82,510,325
Distributions paid to limited partners	(20,522,525)	(18,610,687)
Payments on note payable	0	(66,700,000)
Net cash flow provided by (used in) financing activities	(26,724,370)	(2,800,362)
Increase (decrease) in cash and cash equivalents	(10,023,121)	(86,755,723)
Cash and cash equivalents, beginning of period	11,090,846	86,800,596
Cash and cash equivalents, end of period	1,067,725	44,873
Interest paid	564,701	433,013
Supplemental non-cash information:
Decrease in note payable, settlement of pre-close activity	0	292,644
Acquisition No. 2 [Member]
Supplemental non-cash information:
Note payable assumed in Acquisition	0	40,000,000
Acquisition No. 3 [Member]
Supplemental non-cash information:
Note payable assumed in Acquisition	$ 0	$ 33,000,000

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 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 September 30, 2018, the Partnership owned an approximate 25-26% non-operated working interest in 221 currently producing wells and approximately 247 future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”), which is part of the Bakken shale formation in the Greater Williston Basin. Whiting Petroleum Corporation (“Whiting”) and Oasis Petroleum North America, LLC (“Oasis”), 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.

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. 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 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. 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. 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 and nine months ended September 30, 2018 and 2017. 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 8) will occur. Recently Adopted Accounting Standards In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) Impact of Topic 606 Adoption In accordance with Topic 606, the Partnership completed a detailed review of its revenue contracts, which represent all of the Partnership’s revenue, including oil, natural gas and natural gas liquids sales, to determine the effect of the new standard for the three and nine months ended September 30, 2018. The Partnership did not record a change to its opening retained earnings as of January 1, 2018, as there was no material change to the timing or pattern of revenue recognition due to the adoption of Topic 606. 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. 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 two to three months after the date production is delivered by the operator, and as a result, the Partnership is required to estimate the amount of production delivered by the operator 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 payment is received from the operator. Historically, differences between the Partnership’s revenue estimates and actual revenue received have not been significant. The Partnership disaggregates its revenue on the face of the consolidated statements of operations for the three and nine months ended September 30, 2018 and 2017. Recently Issued Accounting Standards In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842)

Oil and Natural Gas Investments

Oil and Natural Gas Investments	9 Months Ended
	Sep. 30, 2018
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 purchase (“Acquisition No. 1”) of an approximate 11% non-operated working interest in the Sanish Field Assets for approximately $159.6 million. The Partnership accounted for Acquisition No. 1 as a business combination, and therefore expensed, as incurred, transaction costs associated with this acquisition. These costs included, but were not limited to, due diligence, reserve reports, legal and engineering services and site visits. On January 11, 2017, the Partnership completed its purchase (“Acquisition No. 2”) of an additional approximate 11% non-operated working interest in the Sanish Field Assets for approximately $128.5 million. The Partnership accounted for Acquisition No. 2 as a purchase of a group of similar assets, and therefore capitalized transaction costs associated with this acquisition. Total transaction costs incurred for Acquisition No. 2 were approximately $43,000. The Partnership also recorded an asset retirement obligation liability of approximately $0.8 million in conjunction with this acquisition. Acquisition No. 2 increased the Partnership’s non-operated working interest in the Sanish Field Assets to approximately 22-23%. On March 31, 2017, the Partnership completed its purchase (“Acquisition No. 3”) of 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. The Partnership accounted for Acquisition No. 3 as a purchase of a group of similar assets, and therefore capitalized transaction costs associated with this acquisition. Total transaction costs incurred for Acquisition No. 3 were approximately $80,000. The Partnership also recorded an asset retirement obligation liability of approximately $0.3 million in conjunction with this acquisition. Acquisition No. 3 increased the Partnership’s total non-operated working interest in the Sanish Field Assets to approximately 26-27%. The following unaudited pro forma financial information for the three- and nine-month periods ended September 30, 2017 has been prepared as if Acquisitions No. 2 and No. 3 of the Sanish Field 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 information provided by the sellers. The unaudited pro forma financial information does not purport to be indicative of the results of operations that would have occurred had the acquisitions of the Sanish Field 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 Nine Months Ended (Unaudited) (Unaudited) Revenues $ 9,717,996 $ 32,413,448 Net income $ 1,517,198 $ 6,210,488 In October and November 2017, the Partnership elected to participate in the drilling and completion of six new wells. Two wells were completed in March 2018 and are being operated by Whiting. The Partnership has an estimated approximate 29% non-operated working interest in these two wells. The other four wells were completed in April, June and July of 2018 and are operated by Oasis. The Partnership has an estimated approximate 8% non-operated working interest in these four wells. In total, the Partnership’s capital expenditures for the drilling and completion of the six wells discussed above were approximately $7.8 million, including approximately $0.5 million and $6.5 million in the three and nine months ended September 30, 2018, respectively.

Debt

Debt	9 Months Ended
	Sep. 30, 2018
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”) with Bank SNB (the “Lender”), which provides for a revolving credit facility (the “Credit Facility”) with an approved initial commitment amount of $20 million (the “Revolver Commitment Amount”), subject to borrowing base restrictions. The commitment amount may be increased up to $75 million with Lender approval. The Partnership paid an origination fee of 0.30% of the Revolver Commitment Amount, or $60,000, and is subject to additional origination fees of 0.30% for any borrowings made in excess of the Revolver Commitment Amount. 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 maturity date is November 21, 2019. The interest rate, subject to certain exceptions, is 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 Loan Agreement. At September 30, 2018, the borrowing base was $30 million and the interest rate for the Credit Facility was 5.07%. The Credit Facility is available to provide additional liquidity for capital investments 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 80% of the Partnership’s producing wells. The Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. The financial covenants 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 of September 30, 2018, the outstanding balance on the Credit Facility was $13.8 million, which approximates its fair market value. The Partnership estimated the fair value of its Credit Facility by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity.

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2018
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: 2018 2017 Balance as of January 1 $ 1,226,879 $ 70,623 Liabilities incurred - Acquisition No. 2 - 781,628 Liabilities incurred - Acquisition No. 3 - 289,827 Revisions - 28,866 Accretion expense 50,391 43,104 Balance as of September 30 $ 1,277,270 $ 1,214,048

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 September 30, 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 - (1,437,732 ) - Total $ - $ (1,437,732 ) $ - 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 4. 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. In December 2017, 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. At September 30, 2018 and December 31, 2017, the Partnership’s costless collar derivative instruments were in a net loss position; therefore, the current Derivative liability on the consolidated balance sheets was approximately $1.4 million and $1.0 million, respectively, which approximated fair value. The Partnership has not designated its derivative instruments as hedges for accounting purposes and has not entered into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The Partnership recognized a total net loss on its derivative instruments of approximately $40,000 for the three months ended September 30, 2018, which was recorded in the consolidated statements of operations as Loss on derivatives. The loss was comprised of (i) $1.10 million of losses the Partnerships recognized on settled derivatives during the period, offset by (ii) $1.06 million of a mark-to-market gain on derivative instruments outstanding at period end. The Partnership recognized a total net loss on its derivative instruments of approximately $2.9 million for the nine months ended September 30, 2018, which was recorded in the consolidated statements of operations as Loss on derivatives. The loss was comprised of (i) $2.5 million of losses the Partnerships recognized on settled derivatives during the period and (ii) $0.4 million of a mark-to-market loss incurred on derivative instruments outstanding at period end. 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. The following table presents settlements on matured derivative instruments and non-cash losses on open derivative instruments for the periods presented. Settlements on matured derivatives below reflect losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. Non-cash losses below represent the change in fair value of derivative instruments which were held at period-end. Three Months Ended Nine Months Ended Settlements on matured derivatives $ (1,100,682 ) $ (2,532,232 ) Gain (loss) on mark-to-market of derivatives 1,061,761 (410,768 ) Loss on derivatives $ (38,921 ) $ (2,943,000 ) The Partnership’s derivative contracts are costless collars, which are 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 agreements. The contracts are settled monthly. The following table reflects the open costless collar agreements as of September 30, 2018. Settlement Period Basis Oil (Barrels) Floor / Ceiling Prices ($) Fair Value of Asset / (Liability) at 10/01/18 - 12/31/18 NYMEX 69,000 52.00 / 57.05 $ (1,098,657 ) 10/01/18 - 12/31/18 NYMEX 9,000 55.00 / 61.35 $ (105,620 ) 10/01/18 - 12/31/18 NYMEX 9,000 55.00 / 62.25 $ (97,966 ) 10/01/18 - 12/31/18 NYMEX 9,000 56.00 / 65.25 $ (72,819 ) 10/01/18 - 12/31/18 NYMEX 9,000 58.00 / 66.50 $ (62,670 ) $ (1,437,732 ) All of the Partnership’s outstanding derivative instruments are 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, 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 and nine months ended September 30, 2018, the Partnership paid distributions of $0.413424 and $1.081643 per common unit, or $7.8 million and $20.5 million, respectively. For the three and nine months ended September 30, 2017, the Partnership paid distributions of $0.349041 and $1.047123 per common unit, or $6.6 million and $18.6 million, respectively. In the fourth quarter of 2017, the General Partner approved an adjustment to the annualized distribution rate to an annualized return of six percent based on a limited partner’s Net Investment Amount of $20.00 per common unit. The six percent distribution rate was effective with the November 29, 2017 distribution. In March 2018, the General Partner approved an increase to the annualized distribution rate back to seven percent based on a limited partner’s Net Investment Amount. The seven percent distribution rate was effective with the April 26, 2018 distribution. The accumulated unpaid distributions, measured as the difference between an annualized return of six percent (starting with the November 29, 2017 distribution) and the restoration of the annualized return of seven percent (starting with the April 26, 2018 distribution), totaled $0.084383 per common unit, or approximately $1.6 million. As of September 30, 2018, the Partnership has paid the $1.6 million in accumulated unpaid distributions.

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. For the three and nine months ended September 30, 2018, approximately $58,000 and $188,000 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 September 30, 2018, approximately $58,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses on the consolidated balance sheets. For the three and nine months ended September 30, 2017, approximately $72,000 and $242,000 of general and administrative costs were incurred by a member of the General Partner and have been reimbursed by the Partnership. 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 and nine months ended September 30, 2018 and 2017, the Partnership paid $25,611 and $76,833 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 and nine months ended September 30, 2018, approximately $64,000 and $175,000 of expenses subject to the cost sharing agreement were incurred by the Partnership and have been or will be reimbursed by ER12. At September 30, 2018, the approximately $64,000 due to the Partnership from ER12 is included in Other current assets in the consolidated balance sheets. In November 2017, ER12 engaged Regional Energy Investors, LP (“REI”) to perform advisory and consulting services, including supporting ER12 through closing and post-closing on ER12’s first purchase of certain oil and gas properties in North Dakota. In June 2018, ER12 re-engaged REI to perform advisory and consulting services, including supporting ER12 through closing, financing and post-closing of ER12’s second purchase of certain oil and gas properties in North Dakota. REI is owned by entities that are controlled by Mr. Keating and Mr. Mallick and has engaged Mr. Merritt to support its operations. With the fees received from ER12 for advisory and consulting services, REI paid certain personnel utilized by the Partnership, including Mr. Merritt, an aggregate total of $500,000.

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 $2.0 million, or $0.107397 per outstanding common unit, in distributions to its holders of common units.

Accounting Policies, by Policy

Accounting Policies, by Policy (Policies)	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. 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 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.
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 and nine months ended September 30, 2018 and 2017. 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 8) will occur.
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Adopted Accounting Standards In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606) Impact of Topic 606 Adoption In accordance with Topic 606, the Partnership completed a detailed review of its revenue contracts, which represent all of the Partnership’s revenue, including oil, natural gas and natural gas liquids sales, to determine the effect of the new standard for the three and nine months ended September 30, 2018. The Partnership did not record a change to its opening retained earnings as of January 1, 2018, as there was no material change to the timing or pattern of revenue recognition due to the adoption of Topic 606. 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. 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 two to three months after the date production is delivered by the operator, and as a result, the Partnership is required to estimate the amount of production delivered by the operator 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 payment is received from the operator. Historically, differences between the Partnership’s revenue estimates and actual revenue received have not been significant. The Partnership disaggregates its revenue on the face of the consolidated statements of operations for the three and nine months ended September 30, 2018 and 2017. Recently Issued Accounting Standards In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842)

Oil and Natural Gas Investmen_2

Oil and Natural 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-month periods ended September 30, 2017 has been prepared as if Acquisitions No. 2 and No. 3 of the Sanish Field 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 information provided by the sellers. The unaudited pro forma financial information does not purport to be indicative of the results of operations that would have occurred had the acquisitions of the Sanish Field 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 Nine Months Ended (Unaudited) (Unaudited) Revenues $ 9,717,996 $ 32,413,448 Net income $ 1,517,198 $ 6,210,488

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 2017 Balance as of January 1 $ 1,226,879 $ 70,623 Liabilities incurred - Acquisition No. 2 - 781,628 Liabilities incurred - Acquisition No. 3 - 289,827 Revisions - 28,866 Accretion expense 50,391 43,104 Balance as of September 30 $ 1,277,270 $ 1,214,048

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 - (1,437,732 ) - Total $ - $ (1,437,732 ) $ -

Risk Management (Tables)

Risk Management (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	The following table presents settlements on matured derivative instruments and non-cash losses on open derivative instruments for the periods presented. Settlements on matured derivatives below reflect losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. Non-cash losses below represent the change in fair value of derivative instruments which were held at period-end. Three Months Ended Nine Months Ended Settlements on matured derivatives $ (1,100,682 ) $ (2,532,232 ) Gain (loss) on mark-to-market of derivatives 1,061,761 (410,768 ) Loss on derivatives $ (38,921 ) $ (2,943,000 )
Schedule of Derivative Instruments [Table Text Block]	The following table reflects the open costless collar agreements as of September 30, 2018. Settlement Period Basis Oil (Barrels) Floor / Ceiling Prices ($) Fair Value of Asset / (Liability) at 10/01/18 - 12/31/18 NYMEX 69,000 52.00 / 57.05 $ (1,098,657 ) 10/01/18 - 12/31/18 NYMEX 9,000 55.00 / 61.35 $ (105,620 ) 10/01/18 - 12/31/18 NYMEX 9,000 55.00 / 62.25 $ (97,966 ) 10/01/18 - 12/31/18 NYMEX 9,000 56.00 / 65.25 $ (72,819 ) 10/01/18 - 12/31/18 NYMEX 9,000 58.00 / 66.50 $ (62,670 ) $ (1,437,732 )

Partnership Organization (Detai

Partnership Organization (Details) shares in Millions	Jul. 09, 2013USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Apr. 24, 2017USD ($)shares
Partnership Organization (Details) [Line Items]
Limited Liability Company or Limited Partnership, Business, Formation State	Delaware
Partners' Capital Account, Contributions (in Dollars)	$ 1,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units (in Dollars)		$ 0	$ 82,510,325
Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Productive Oil Wells, Number of Wells, Net		221
Gas and Oil Area Undeveloped, Net		247
Minimum [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net		25.00%
Maximum [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net		26.00%
Best-Efforts Offering [Member]
Partnership Organization (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares) | shares				19
Proceeds from Issuance of Common Limited Partners Units (in Dollars)				$ 374,200,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units (in Dollars)				$ 349,600,000

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Details) - shares	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Accounting Policies [Abstract]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0	0	0	0

Oil and Natural Gas Investmen_3

Oil and Natural Gas Investments (Details)	Mar. 31, 2017USD ($)	Jan. 11, 2017USD ($)	Dec. 18, 2015USD ($)	Mar. 31, 2017USD ($)	Sep. 30, 2018USD ($)	Mar. 31, 2018	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)	Dec. 31, 2017USD ($)	Nov. 30, 2017
Oil and Natural Gas Investments (Details) [Line Items]
Development Wells Drilled, Net Productive						2
Acquisition No. 2 [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Asset Retirement Obligation, Liabilities Incurred (in Dollars)							$ 0	$ 781,628
Acquisition No. 3 [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Asset Retirement Obligation, Liabilities Incurred (in Dollars)							$ 0	$ 289,827
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Wells in Process of Drilling											6
Oasis Petroleum, Inc. [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Working Interest											8.00%
Wells in Process of Drilling											4
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Productive Oil Wells, Number of Wells, Net					221		221		221
Gas and Oil Area Undeveloped, Net							247
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)									$ 7,800,000
Costs Incurred, Development Costs (in Dollars)					$ 500,000		$ 6,500,000
Sanish Field Located in Mountrail County, North Dakota [Member] | Acquisition No. 1 [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net			11.00%
Business Combination, Consideration Transferred (in Dollars)			$ 159,600,000
Sanish Field Located in Mountrail County, North Dakota [Member] | Acquisition No. 2 [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net		11.00%
Business Combination, Consideration Transferred (in Dollars)		$ 128,500,000
Acquisition Costs, Period Cost (in Dollars)										$ 43,000
Asset Retirement Obligation, Liabilities Incurred (in Dollars)		$ 800,000
Sanish Field Located in Mountrail County, North Dakota [Member] | Acquisition No. 3 [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net	10.50%
Business Combination, Consideration Transferred (in Dollars)				$ 52,400,000
Acquisition Costs, Period Cost (in Dollars)										$ 80,000
Asset Retirement Obligation, Liabilities Incurred (in Dollars)	$ 300,000
Number of Producing Partnership Wells Acquired	82
Productive Oil Wells, 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] | Whiting Petroleum [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Working Interest											29.00%
Wells in Process of Drilling											2
Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net							25.00%
Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member] | Acquisition No. 2 [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Working Interest		22.00%
Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member] | Acquisition No. 3 [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Working Interest	26.00%			26.00%
Sanish Field Located in Mountrail County, North Dakota [Member] | Maximum [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net							26.00%
Sanish Field Located in Mountrail County, North Dakota [Member] | Maximum [Member] | Acquisition No. 2 [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Working Interest		23.00%
Sanish Field Located in Mountrail County, North Dakota [Member] | Maximum [Member] | Acquisition No. 3 [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Working Interest	27.00%			27.00%

Oil and Natural Gas Investmen_4

Oil and Natural Gas Investments (Details) - Business Acquisition, Pro Forma Information - USD ($)	3 Months Ended	9 Months Ended
	Sep. 30, 2017	Sep. 30, 2017
Business Acquisition, Pro Forma Information [Abstract]
Revenues	$ 9,717,996	$ 32,413,448
Net income	$ 1,517,198	$ 6,210,488

Debt (Details)

Debt (Details) - USD ($)	Nov. 21, 2017	Sep. 30, 2018	Dec. 31, 2017
Debt (Details) [Line Items]
Long-term Line of Credit (in Dollars)		$ 13,800,000	$ 20,000,000
Revolving Credit Facility [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount (in Dollars)	$ 20,000,000
Line of Credit Facility, Borrowing Capacity, Description	The commitment amount may be increased up to $75 million
Line of Credit Facility, Commitment Fee Percentage	0.30%
Line of Credit Facility, Commitment Fee Amount (in Dollars)	$ 60,000
Line of Credit Facility, Commitment Fee in Excess of Revolver Amount, Percentage	0.30%
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage	0.50%
Debt Instrument, Maturity Date	Nov. 21, 2019
Line of Credit Facility, Maximum Borrowing Capacity (in Dollars)		$ 30,000,000
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate		5.07%
Line of Credit Facility, Collateral	The Credit Facility is secured by a mortgage and first lien position on at least 80% of the Partnership’s producing wells.
Line of Credit Facility, Covenant Terms	The Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. The financial covenants 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.
London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member] | Revolving Credit Facility [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.50%
London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member] | Revolving Credit Facility [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 ($)	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations [Line Items]
Balance	$ 1,226,879	$ 70,623
Revisions	0	28,866
Accretion expense	50,391	43,104
Balance	1,277,270	1,214,048
Acquisition No. 2 [Member]
Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations [Line Items]
Liabilities incurred	0	781,628
Acquisition No. 3 [Member]
Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations [Line Items]
Liabilities incurred	$ 0	$ 289,827

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	(1,437,732)
Total	(1,437,732)
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	$ 1,400,000		$ 1,400,000		$ 1,000,000
Gain (Loss) on Price Risk Derivatives, Net	(38,921)	$ 0	(2,943,000)	$ 0
Derivative, Loss on Derivative	1,100,682		2,532,232
Derivative, Gain (Loss) on Derivative, Net	$ 1,061,761		$ (410,768)	$ 0

Risk Management (Details) - Sch

Risk Management (Details) - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Abstract]
Settlements on matured derivatives	$ (1,100,682)		$ (2,532,232)
Gain (loss) on mark-to-market of derivatives	1,061,761		(410,768)	$ 0
Loss on derivatives	$ (38,921)	$ 0	$ (2,943,000)	$ 0

Risk Management (Details) - S_2

Risk Management (Details) - Schedule of Derivative Instruments	9 Months Ended
	Sep. 30, 2018USD ($)$ / itembbl
Derivative [Line Items]
Fair Value of Asset (Liability) (in Dollars) | $	$ (1,437,732)
Price Risk Derivative [Member] | 10/01/18 - 12/31/18 [Member] | Costless Collar Agreements #1 [Member]
Derivative [Line Items]
Basis	NYMEX
Oil (Barrels) (in Barrels (of Oil)) | bbl	69,000
Floor Price	52
Ceiling Price	57.05
Fair Value of Asset (Liability) (in Dollars) | $	$ (1,098,657)
Price Risk Derivative [Member] | 10/01/18 - 12/31/18 [Member] | Costless Collar Agreements #2 [Member]
Derivative [Line Items]
Basis	NYMEX
Oil (Barrels) (in Barrels (of Oil)) | bbl	9,000
Floor Price	55
Ceiling Price	61.35
Fair Value of Asset (Liability) (in Dollars) | $	$ (105,620)
Price Risk Derivative [Member] | 10/01/18 - 12/31/18 [Member] | Costless Collar Agreements #3 [Member]
Derivative [Line Items]
Basis	NYMEX
Oil (Barrels) (in Barrels (of Oil)) | bbl	9,000
Floor Price	55
Ceiling Price	62.25
Fair Value of Asset (Liability) (in Dollars) | $	$ (97,966)
Price Risk Derivative [Member] | 10/01/18 - 12/31/18 [Member] | Costless Collar Agreements #4 [Member]
Derivative [Line Items]
Basis	NYMEX
Oil (Barrels) (in Barrels (of Oil)) | bbl	9,000
Floor Price	56
Ceiling Price	65.25
Fair Value of Asset (Liability) (in Dollars) | $	$ (72,819)
Price Risk Derivative [Member] | 10/01/18 - 12/31/18 [Member] | Costless Collar Agreements #5 [Member]
Derivative [Line Items]
Basis	NYMEX
Oil (Barrels) (in Barrels (of Oil)) | bbl	9,000
Floor Price	58
Ceiling Price	66.50
Fair Value of Asset (Liability) (in Dollars) | $	$ (62,670)

Capital Contribution and Part_2

Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions	Apr. 26, 2018	Nov. 29, 2017	Jul. 09, 2013	Sep. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2016	Apr. 24, 2017
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Contributions			$ 1,000
Distributions to organizational limited partner			$ 990
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units								$ 0	$ 82,510,325
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				$ 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)				$ 0.413424			$ 0.349041	$ 1.081643	$ 1.047123
Distribution Made to Limited Partner, Cash Distributions Paid				$ 7,800,000			$ 6,600,000	$ 20,522,525	$ 18,610,687
Distribution Made to Limited Partner, Distribution Rate	7.00%	6.00%			7.00%	6.00%				7.00%
Partners Capital Account, Units Sold, Price Per Unit		$ 20
Distribution at Payout to limited partner, per common unit (in Dollars per share)								$ 0.084383
Distribution at Payout to limited partner								$ 1,600,000
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		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
General Partner [Member]
Related Parties (Details) [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party	$ 58,000	$ 72,000	$ 188,000	$ 242,000
Due to Related Parties, Current	58,000		58,000
Affiliated Entity [Member]
Related Parties (Details) [Line Items]
Operating Leases, Rent Expense	25,611	$ 25,611	76,833	$ 76,833
Operating Leases, Rent Expense, Minimum Rentals			8,537
Reimbursements From Related Party	64,000		175,000
Due from Related Parties	$ 64,000		64,000
President [Member] | Consulting Services Provided to General Partner [Member]
Related Parties (Details) [Line Items]
Payment Made By Related Party to Others			$ 500,000

Subsequent Events (Details)

Subsequent Events (Details) - Subsequent Event [Member] $ / shares in Units, $ in Millions	1 Months Ended
	Oct. 31, 2018USD ($)$ / shares
Subsequent Events (Details) [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid | $	$ 2
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ / shares	$ 0.107397