Document And Entity Information
Document And Entity Information - shares | 3 Months Ended | |
Mar. 31, 2018 | Apr. 30, 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 Voluntary Filers | No | |
Entity Filer Category | Smaller Reporting Company | |
Entity Well-known Seasoned Issuer | No | |
Document Period End Date | Mar. 31, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q1 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) | Mar. 31, 2018 | Dec. 31, 2017 |
Assets | ||
Cash and cash equivalents | $ 2,734,467 | $ 11,090,846 |
Oil, natural gas and natural gas liquids revenue receivable | 7,035,455 | 6,219,193 |
Other current assets | 158,803 | 162,930 |
Total Current Assets | 9,928,725 | 17,472,969 |
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $28,885,163 and $24,934,190, respectively | 322,409,071 | 321,766,616 |
Total Assets | 332,337,796 | 339,239,585 |
Liabilities | ||
Accounts payable and accrued expenses | 4,476,869 | 2,733,131 |
Derivative liability | 1,715,642 | 1,026,965 |
Total Current Liabilities | 6,192,511 | 3,760,096 |
Revolving credit facility | 13,000,000 | 20,000,000 |
Asset retirement obligations | 1,243,676 | 1,226,879 |
Total Liabilities | 20,436,187 | 24,986,975 |
Partners’ Equity | ||
Limited partners’ interest (18,973,474 common units issued and outstanding, respectively) | 311,903,336 | 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 | 311,901,609 | 314,252,610 |
Total Liabilities and Partners’ Equity | $ 332,337,796 | $ 339,239,585 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parentheticals) - USD ($) | Mar. 31, 2018 | Dec. 31, 2017 |
Oil and natural gas properties, accumulated depreciation, depletion and amortization (in Dollars) | $ 28,885,163 | $ 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 | 12 Months Ended |
Mar. 31, 2018 | Dec. 31, 2017 | |
Oil, natural gas and natural gas liquids revenues | $ 13,067,734 | $ 10,141,266 |
Operating costs and expenses | ||
Production expenses | 2,934,666 | 2,731,854 |
Production taxes | 1,075,125 | 857,733 |
General and administrative expenses | 381,616 | 501,741 |
Depreciation, depletion, amortization and accretion | 3,967,770 | 3,256,258 |
Total operating costs and expenses | 8,359,177 | 7,347,586 |
Operating income | 4,708,557 | 2,793,680 |
Loss on derivatives | (1,162,255) | 0 |
Interest expense, net | (220,857) | (172,609) |
Total other expense, net | (1,383,112) | (172,609) |
Net income | $ 3,325,445 | $ 2,621,071 |
Basic and diluted net income per common unit (in Dollars per share) | $ 0.18 | $ 0.17 |
Weighted average common units outstanding - basic and diluted (in Shares) | 18,973,474 | 15,809,588 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Cash flow from operating activities: | ||
Net income (loss) | $ 3,325,445 | $ 2,621,071 |
Adjustments to reconcile net income to cash from operating activities: | ||
Depreciation, depletion, amortization and accretion | 3,967,770 | 3,256,258 |
Loss on derivatives | 688,677 | 0 |
Non-cash expenses, net | 11,352 | 23,449 |
Changes in operating assets and liabilities: | ||
Oil, natural gas and natural gas liquids revenue receivable | (816,262) | (2,977,569) |
Other current assets | (5,380) | 22,933 |
Accounts payable and accrued expenses | (118,935) | 717,514 |
Net cash flow provided by operating activities | 7,052,667 | 3,663,656 |
Cash flow from investing activities: | ||
Cash paid for acquisition of oil and natural gas properties | 0 | (98,327,930) |
Additions to oil and natural gas properties | (2,730,755) | (114,612) |
Net cash flow used in investing activities | (2,730,755) | (98,442,542) |
Cash flow from financing activities: | ||
Cash paid for loan costs | (1,845) | 0 |
Net proceeds from revolving credit facility | (7,000,000) | 0 |
Net proceeds related to issuance of units | 0 | 58,504,622 |
Distributions paid to limited partners | (5,676,446) | (5,488,149) |
Payments on note payable | 0 | (40,000,000) |
Net cash flow provided by (used in) financing activities | (12,678,291) | 13,016,473 |
Increase (decrease) in cash and cash equivalents | (8,356,379) | (81,762,413) |
Cash and cash equivalents, beginning of period | 11,090,846 | 86,800,596 |
Cash and cash equivalents, end of period | 2,734,467 | 5,038,183 |
Interest paid | 231,792 | 158,904 |
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 | 3 Months Ended |
Mar. 31, 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 March 31, 2018, the Partnership owned an approximate 26-27% non-operated working interest in 217 currently producing wells, 4 wells currently being drilled 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”), one of the largest producers in the basin, operates substantially all of the Sanish Field Assets. The general partner of the Partnership is Energy 11 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership. The Partnership’s fiscal year ends on December 31. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 3 Months Ended |
Mar. 31, 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 months ended March 31, 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 months ended March 31, 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 streams, including oil, natural gas and natural gas liquids sales, to determine the effect of the new standard for the three months ended March 31, 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 ASC 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 following table disaggregates the Partnership’s revenue streams that are summarized as “Oil, natural gas and natural gas liquids revenues” on the consolidated statements of operations for the three months ended March 31, 2018 and 2017. Three Months Ended March 31, 2018 Three Months Ended March 31, 2017 Oil revenues $ 10,644,693 $ 8,443,214 Natural gas revenues 932,998 670,282 Natural gas liquids revenues 1,490,043 1,027,770 $ 13,067,734 $ 10,141,266 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. The Partnership is still evaluating the impact this standard will have on its consolidated financial statements and related disclosures. |
Oil and Natural Gas Investments
Oil and Natural Gas Investments | 3 Months Ended |
Mar. 31, 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-month period ended March 31, 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 March 31, 2017 Revenues $ 12,456,650 Net income $ 2,869,027 In October and November 2017, the Partnership elected to participate in the drilling and completion of six new wells. Two of the six wells were completed in March 2018. These two wells were completed and are being operated by Whiting, and the Partnership has an estimated approximate 29% non-operated working interest in these two wells. The other four wells are being drilled and will be operated by Oasis Petroleum, Inc. (NYSE: OAS), and the Partnership will have an estimated approximate 7-9% non-operated working interest in these four wells. These four wells are anticipated to be completed in the second quarter of 2018. In total, the Partnership’s capital expenditures for the drilling and completion of the six wells discussed above are estimated to be approximately $7.0 million, of which approximately $5.3 million had been incurred as of March 31, 2018, including approximately $4.0 million in the first quarter of 2018. |
Debt
Debt | 3 Months Ended |
Mar. 31, 2018 | |
Debt Disclosure [Abstract] | |
Debt Disclosure [Text Block] | Note 4. Debt As part of the financing for Acquisition No. 2 completed on January 11, 2017, the Partnership executed a note (“Seller Note 2”) in favor of the sellers in the original principal amount of $40.0 million. The Partnership paid the $40.0 million Seller Note 2, which bore interest at 5%, in full on February 23, 2017. As part of the financing for Acquisition No. 3 completed on March 31, 2017, the Partnership executed a note (“Seller Note 3”) in favor of the sellers in the original principal amount of $33.0 million. Seller Note 3 bore interest at 5% per annum and was payable in full no later than August 1, 2017 (“Maturity Date”). In July 2017, the Partnership and the sellers executed a First Amendment to Seller Note 3 (“Amended Note”), which extended the maturity date to June 29, 2018 (“Extended Maturity Date”). The Amended Note also bore interest at 5% per annum. The Partnership paid the outstanding balance on the Amended Note of approximately $5.9 million, including interest, on November 21, 2017 in conjunction with the closing on the credit facility discussed below. There was no penalty for prepayment of the Amended Note. 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 March 31, 2018, the borrowing base was $30 million and the interest rate for the Credit Facility was 5.06%. The Credit Facility is available to provide additional liquidity for capital investments, including the completion of the four wells described in “Note 3. Oil and Gas 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 March 31, 2018. As of March 31, 2018, the outstanding balance on the Credit Facility was $13.0 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 | 3 Months Ended |
Mar. 31, 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 - 36,625 Accretion expense 16,797 11,172 Balance as of March 31 $ 1,243,676 $ 1,189,875 |
Fair Value of Financial Instrum
Fair Value of Financial Instruments | 3 Months Ended |
Mar. 31, 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 months ended March 31, 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 March 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 March 31, 2018. Fair Value Measurements at March 31, 2018 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity derivatives - current assets $ - $ - $ - Commodity derivatives - current liabilities - (1,715,642 ) - Total $ - $ (1,715,642 ) $ - 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 March 31, 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 | 3 Months Ended |
Mar. 31, 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 March 31, 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 $1.7 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 $1.2 million for the three months ended March 31, 2018, which was recorded in the consolidated statements of operations as Loss on derivatives. The loss was comprised of (i) $0.5 million of losses the Partnerships recognized on settled derivatives during the period and (ii) $0.7 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 period 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 March 31, 2018 Settlements on matured derivatives $ (473,578 ) Loss on mark-to-market of derivatives (688,677 ) Loss on derivatives $ (1,162,255 ) 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 follow table reflects the open costless collar agreements as of March 31, 2018. Settlement Period Basis Oil (Barrels) Floor / Ceiling Prices ($) Fair Value of Asset / (Liability) at March 31, 2018 04/01/18 - 12/31/18 NYMEX 216,000 $ 52.00 / 57.05 $ (1,500,989 ) 04/01/18 - 12/31/18 NYMEX 27,000 $ 55.00 / 61.35 (93,432 ) 04/01/18 - 12/31/18 NYMEX 27,000 $ 55.00 / 62.25 (78,638 ) 04/01/18 - 12/31/18 NYMEX 27,000 $ 56.00 / 65.25 (33,223 ) 04/01/18 - 12/31/18 NYMEX 27,000 $ 58.00 / 66.50 (9,360 ) $ (1,715,642 ) 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 | 3 Months Ended |
Mar. 31, 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). The Partnership completed its best-efforts offering of common units on April 24, 2017. As of the conclusion of the offering on April 24, 2017, the Partnership had completed the sale of approximately 19.0 million common units for total gross proceeds of $374.2 million and proceeds net of offerings costs of $349.6 million. Under the agreement with David Lerner Associates, Inc. (the “Dealer Manager”), the Dealer Manager received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager will also be paid a contingent incentive fee, which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold based on the performance of the Partnership. Based on the common units sold through the best-efforts offering, the total contingent fee is a maximum of approximately $15.0 million. Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units. Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights or with respect to Class B units and will not make the contingent incentive payments to the Dealer Manager, until Payout occurs. The Partnership Agreement provides that Payout occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per unit, regardless of the amount paid for the unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount. All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows: · First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement; · Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%). For the three months ended March 31, 2018 and 2017, the Partnership paid distributions of $0.299178 and $0.349041 per common unit, or $5.7 million and $5.5 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. The difference between any distribution and an annualized return of seven percent based on the Net Investment Amount is required to be paid before final Payout occurs as defined above. As of March 31, 2018, the accumulated unpaid distributions totaled $0.084383 per common unit, or approximately $1.6 million. 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. |
Related Parties
Related Parties | 3 Months Ended |
Mar. 31, 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 months ended March 31, 2018 and 2017, approximately $71,000 and $80,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At March 31, 2018, approximately $71,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses on the consolidated balance sheets. The members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer, David S. McKenney, Chief Financial Officer, Anthony F. Keating, III, Co-Chief Operating Officer and Michael J. Mallick, Co-Chief Operating Officer. Mr. Knight and Mr. McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy Resources 12 GP, LLC, the general partner of Energy Resources 12, L.P. (“ER12”), a limited partnership that also invests in producing and non-producing oil and gas properties on-shore in the United States. On January 31, 2018, the Partnership entered into a cost sharing agreement with ER12 that gives ER12 access to the Partnership’s personnel and administrative resources, including accounting, asset management and other day-to-day management support. The shared day-to-day costs are split evenly between the two partnerships and any direct third-party costs are paid by the party receiving the services. The shared costs are based on actual costs incurred with no mark-up or profit to the Partnership. The agreement may be terminated at any time by either party upon 60 days written notice. The Partnership leases office space in Oklahoma City, Oklahoma on a month-to-month basis from an affiliate of the General Partner. For the three months ended March 31, 2018 and 2017, the Partnership paid $25,611 to the affiliate of the General Partner. The office space is shared between the Partnership and ER12; therefore, under the cost sharing agreement, the monthly payment of $8,537 is split between the two partnerships. In addition to the office space, the cost sharing agreement reduces the costs to the Partnership for accounting and asset management services provided through a member of the General Partner noted above. The compensation due to Clifford J. Merritt, President of the General Partner, is also a shared cost between the Partnership and ER12. For the three months ended March 31, 2018, approximately $47,000 of expenses subject to the cost sharing agreement were incurred by the Partnership and will be reimbursed by ER12. At March 31, 2018, the approximately $47,000 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 the 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 | 3 Months Ended |
Mar. 31, 2018 | |
Subsequent Events [Abstract] | |
Subsequent Events [Text Block] | Note 10. Subsequent Events In April 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) | 3 Months Ended |
Mar. 31, 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 months ended March 31, 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 months ended March 31, 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 streams, including oil, natural gas and natural gas liquids sales, to determine the effect of the new standard for the three months ended March 31, 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 ASC 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 following table disaggregates the Partnership’s revenue streams that are summarized as “Oil, natural gas and natural gas liquids revenues” on the consolidated statements of operations for the three months ended March 31, 2018 and 2017. Three Months Ended March 31, 2018 Three Months Ended March 31, 2017 Oil revenues $ 10,644,693 $ 8,443,214 Natural gas revenues 932,998 670,282 Natural gas liquids revenues 1,490,043 1,027,770 $ 13,067,734 $ 10,141,266 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. The Partnership is still evaluating the impact this standard will have on its consolidated financial statements and related disclosures. |
Summary of Significant Accoun17
Summary of Significant Accounting Policies (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Accounting Policies [Abstract] | |
Disaggregation of Revenue [Table Text Block] | The following table disaggregates the Partnership’s revenue streams that are summarized as “Oil, natural gas and natural gas liquids revenues” on the consolidated statements of operations for the three months ended March 31, 2018 and 2017. Three Months Ended March 31, 2018 Three Months Ended March 31, 2017 Oil revenues $ 10,644,693 $ 8,443,214 Natural gas revenues 932,998 670,282 Natural gas liquids revenues 1,490,043 1,027,770 $ 13,067,734 $ 10,141,266 |
Oil and Natural Gas Investmen18
Oil and Natural Gas Investments (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Oil and Gas Property [Abstract] | |
Business Acquisition, Pro Forma Information [Table Text Block] | The following unaudited pro forma financial information for the three-month period ended March 31, 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 March 31, 2017 Revenues $ 12,456,650 Net income $ 2,869,027 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 3 Months Ended |
Mar. 31, 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 - 36,625 Accretion expense 16,797 11,172 Balance as of March 31 $ 1,243,676 $ 1,189,875 |
Fair Value of Financial Instr20
Fair Value of Financial Instruments (Tables) | 3 Months Ended |
Mar. 31, 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 March 31, 2018. Fair Value Measurements at March 31, 2018 Quoted Prices in Active Markets for Identical Assets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Commodity derivatives - current assets $ - $ - $ - Commodity derivatives - current liabilities - (1,715,642 ) - Total $ - $ (1,715,642 ) $ - |
Risk Management (Tables)
Risk Management (Tables) | 3 Months Ended |
Mar. 31, 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 period 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 March 31, 2018 Settlements on matured derivatives $ (473,578 ) Loss on mark-to-market of derivatives (688,677 ) Loss on derivatives $ (1,162,255 ) |
Schedule of Derivative Instruments [Table Text Block] | The follow table reflects the open costless collar agreements as of March 31, 2018. Settlement Period Basis Oil (Barrels) Floor / Ceiling Prices ($) Fair Value of Asset / (Liability) at March 31, 2018 04/01/18 - 12/31/18 NYMEX 216,000 $ 52.00 / 57.05 $ (1,500,989 ) 04/01/18 - 12/31/18 NYMEX 27,000 $ 55.00 / 61.35 (93,432 ) 04/01/18 - 12/31/18 NYMEX 27,000 $ 55.00 / 62.25 (78,638 ) 04/01/18 - 12/31/18 NYMEX 27,000 $ 56.00 / 65.25 (33,223 ) 04/01/18 - 12/31/18 NYMEX 27,000 $ 58.00 / 66.50 (9,360 ) $ (1,715,642 ) |
Partnership Organization (Detai
Partnership Organization (Details) shares in Millions | Jul. 09, 2013USD ($) | Mar. 31, 2018USD ($) | Mar. 31, 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 | $ 58,504,622 | ||
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 | |||
Sanish Field Located in Mountrail County, North Dakota [Member] | ||||
Partnership Organization (Details) [Line Items] | ||||
Productive Oil Wells, Number of Wells, Net | 217 | |||
Wells in Process of Drilling | 4 | |||
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 | 26.00% | |||
Maximum [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | ||||
Partnership Organization (Details) [Line Items] | ||||
Gas and Oil Area Developed, Net | 27.00% |
Summary of Significant Accoun23
Summary of Significant Accounting Policies (Details) - shares | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Accounting Policies [Abstract] | ||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 0 | 0 |
Summary of Significant Accoun24
Summary of Significant Accounting Policies (Details) - Disaggregation of Revenue - USD ($) | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | |
Disaggregation of Revenue [Line Items] | |||
$ 13,067,734 | $ 10,141,266 | $ 10,141,266 | |
Oil [Member] | |||
Disaggregation of Revenue [Line Items] | |||
Oil revenues | 10,644,693 | 8,443,214 | |
Natural Gas [Member] | |||
Disaggregation of Revenue [Line Items] | |||
Natural gas revenues | 932,998 | 670,282 | |
Natural Gas Liquids [Member] | |||
Disaggregation of Revenue [Line Items] | |||
Natural gas liquids revenues | $ 1,490,043 | $ 1,027,770 |
Oil and Natural Gas Investmen25
Oil and Natural Gas Investments (Details) | Mar. 31, 2017USD ($) | Jan. 11, 2017USD ($) | Dec. 18, 2015USD ($) | Mar. 31, 2017USD ($) | Mar. 31, 2018USD ($) | Mar. 31, 2017USD ($) | Mar. 31, 2018USD ($) | Dec. 31, 2017USD ($) | Nov. 30, 2017 |
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Development Wells Drilled, Net Productive | 2 | ||||||||
Sanish Field Located in Mountrail County, North Dakota [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Productive Oil Wells, Number of Wells, Net | 217 | 217 | |||||||
Gas and Oil Area Undeveloped, Net | 247 | ||||||||
Wells in Process of Drilling | 4 | 4 | |||||||
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars) | $ 7,000,000 | ||||||||
Costs Incurred, Development Costs (in Dollars) | $ 4,000,000 | $ 5,300,000 | |||||||
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 | 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 | 27.00% | ||||||||
Acquisition No. 1 [Member] | Sanish Field Located in Mountrail County, North Dakota [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 | ||||||||
Acquisition No. 2 [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Asset Retirement Obligation, Liabilities Incurred (in Dollars) | $ 0 | $ 781,628 | |||||||
Acquisition No. 2 [Member] | Sanish Field Located in Mountrail County, North Dakota [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 | ||||||||
Acquisition No. 2 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Working Interest | 22.00% | ||||||||
Acquisition No. 2 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | Maximum [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Working Interest | 23.00% | ||||||||
Acquisition No. 3 [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Asset Retirement Obligation, Liabilities Incurred (in Dollars) | $ 0 | $ 289,827 | |||||||
Acquisition No. 3 [Member] | Sanish Field Located in Mountrail County, North Dakota [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 | 216 | ||||||
Number of Future Development Partnership Locations Acquired | 150 | ||||||||
Gas and Oil Area Undeveloped, Net | 253 | ||||||||
Acquisition No. 3 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Working Interest | 26.00% | 26.00% | 26.00% | ||||||
Acquisition No. 3 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | Maximum [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Working Interest | 27.00% | 27.00% | 27.00% | ||||||
Sanish Field Located in Mountrail County, North Dakota [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Wells in Process of Drilling | 6 | ||||||||
Sanish Field Located in Mountrail County, North Dakota [Member] | Oasis Petroleum, Inc. [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Wells in Process of Drilling | 4 | ||||||||
Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member] | Oasis Petroleum, Inc. [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Working Interest | 7.00% | ||||||||
Sanish Field Located in Mountrail County, North Dakota [Member] | Maximum [Member] | Oasis Petroleum, Inc. [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Working Interest | 9.00% |
Oil and Natural Gas Investmen26
Oil and Natural Gas Investments (Details) - Business Acquisition, Pro Forma Information | 3 Months Ended |
Mar. 31, 2017USD ($) | |
Business Acquisition, Pro Forma Information [Abstract] | |
Revenues | $ 12,456,650 |
Net income | $ 2,869,027 |
Debt (Details)
Debt (Details) - USD ($) | Nov. 21, 2017 | Mar. 31, 2017 | Feb. 23, 2017 | Jan. 11, 2017 | Jul. 31, 2017 | Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 |
Debt (Details) [Line Items] | ||||||||
Repayments of Debt | $ 0 | $ 40,000,000 | ||||||
Long-term Line of Credit | 13,000,000 | $ 20,000,000 | ||||||
Lines of Credit, Fair Value Disclosure | 13,000,000 | |||||||
Revolving Credit Facility [Member] | ||||||||
Debt (Details) [Line Items] | ||||||||
Debt Instrument, Face Amount | $ 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 | $ 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% | |||||||
Line of Credit Facility, Maximum Borrowing Capacity | $ 30,000,000 | |||||||
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | 5.06% | |||||||
Wells in Process of Drilling | 4 | |||||||
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 March 31, 2018. | |||||||
Minimum [Member] | Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||||
Debt (Details) [Line Items] | ||||||||
Debt Instrument, Basis Spread on Variable Rate | 2.50% | |||||||
Maximum [Member] | Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||||
Debt (Details) [Line Items] | ||||||||
Debt Instrument, Basis Spread on Variable Rate | 3.50% | |||||||
Acquisition No. 2 [Member] | Notes Payable, Other Payables [Member] | ||||||||
Debt (Details) [Line Items] | ||||||||
Repayments of Debt | $ 40,000,000 | |||||||
Debt Instrument, Outstanding Balance | $ 40,000,000 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.00% | |||||||
Debt Instrument, Maturity Date | Feb. 23, 2017 | |||||||
Acquisition No. 3 [Member] | Notes Payable, Other Payables [Member] | ||||||||
Debt (Details) [Line Items] | ||||||||
Repayments of Debt | $ 5,900,000 | |||||||
Debt Instrument, Interest Rate, Stated Percentage | 5.00% | 5.00% | ||||||
Debt Instrument, Maturity Date | Aug. 1, 2017 | Jun. 29, 2018 | ||||||
Debt Instrument, Face Amount | $ 33,000,000 | $ 33,000,000 |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations - USD ($) | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations [Line Items] | ||
Balance | $ 1,226,879 | $ 70,623 |
Revisions | 0 | 36,625 |
Accretion expense | 16,797 | 11,172 |
Balance | 1,243,676 | 1,189,875 |
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 Instr29
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis - USD ($) | Mar. 31, 2018 | Dec. 31, 2017 |
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items] | ||
Commodity derivatives - current liabilities | $ (1,715,642) | $ (1,026,965) |
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 | (1,715,642) | |
Total | (1,715,642) | |
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 | 12 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||
Derivative Liability | $ 1,700,000 | $ 1,000,000 | |
Gain (Loss) on Price Risk Derivatives, Net | (1,162,255) | $ 0 | |
Derivative, Loss on Derivative | 473,578 | ||
Derivative, Gain (Loss) on Derivative, Net | $ (688,677) | $ 0 |
Risk Management (Details) - Sch
Risk Management (Details) - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value - USD ($) | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | Dec. 31, 2017 | |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Abstract] | |||
Settlements on matured derivatives | $ (473,578) | ||
Loss on mark-to-market of derivatives | (688,677) | $ 0 | |
Loss on derivatives | $ (1,162,255) | $ 0 |
Risk Management (Details) - S32
Risk Management (Details) - Schedule of Derivative Instruments | 3 Months Ended |
Mar. 31, 2018USD ($)$ / itembbl | |
Derivative [Line Items] | |
Fair Value of Asset (Liability) (in Dollars) | $ | $ (1,715,642) |
04/01/18 - 12/31/18 [Member] | Price Risk Derivative [Member] | Costless Collar Agreements #1 [Member] | |
Derivative [Line Items] | |
Basis | NYMEX |
Oil (Barrels) (in Barrels (of Oil)) | bbl | 216,000 |
Floor Price | 52 |
Ceiling Price | 57.05 |
Fair Value of Asset (Liability) (in Dollars) | $ | $ (1,500,989) |
04/01/18 - 12/31/18 [Member] | Price Risk Derivative [Member] | Costless Collar Agreements #2 [Member] | |
Derivative [Line Items] | |
Basis | NYMEX |
Oil (Barrels) (in Barrels (of Oil)) | bbl | 27,000 |
Floor Price | 55 |
Ceiling Price | 61.35 |
Fair Value of Asset (Liability) (in Dollars) | $ | $ (93,432) |
04/01/18 - 12/31/18 [Member] | Price Risk Derivative [Member] | Costless Collar Agreements #3 [Member] | |
Derivative [Line Items] | |
Basis | NYMEX |
Oil (Barrels) (in Barrels (of Oil)) | bbl | 27,000 |
Floor Price | 55 |
Ceiling Price | 62.25 |
Fair Value of Asset (Liability) (in Dollars) | $ | $ (78,638) |
04/01/18 - 12/31/18 [Member] | Price Risk Derivative [Member] | Costless Collar Agreements #4 [Member] | |
Derivative [Line Items] | |
Basis | NYMEX |
Oil (Barrels) (in Barrels (of Oil)) | bbl | 27,000 |
Floor Price | 56 |
Ceiling Price | 65.25 |
Fair Value of Asset (Liability) (in Dollars) | $ | $ (33,223) |
04/01/18 - 12/31/18 [Member] | Price Risk Derivative [Member] | Costless Collar Agreements #5 [Member] | |
Derivative [Line Items] | |
Basis | NYMEX |
Oil (Barrels) (in Barrels (of Oil)) | bbl | 27,000 |
Floor Price | 58 |
Ceiling Price | 66.50 |
Fair Value of Asset (Liability) (in Dollars) | $ | $ (9,360) |
Capital Contribution and Part33
Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions | Apr. 26, 2018 | Nov. 29, 2017 | Jul. 09, 2013 | Apr. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2017 | Mar. 31, 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 | $ 58,504,622 | |||||||
Managing Dealer, Selling Commissions, Percentage | 6.00% | ||||||||
Managing Dealer, Maximum Contingent Incentive Fee on Gross Proceeds, Percentage | 4.00% | ||||||||
Maximum Contingent Offering Costs, Selling Commissions and Marketing Expenses | $ 15,000,000 | ||||||||
Key Provisions of Operating or Partnership Agreement, Description | The Partnership Agreement provides that Payout occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per unit, regardless of the amount paid for the unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:·First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement;·Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%). | ||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share) | $ 0.299178 | $ 0.349041 | |||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 5,676,446 | $ 5,488,149 | |||||||
Distribution Made to Limited Partner, Distribution Rate | 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 | ||||||||
Subsequent Event [Member] | |||||||||
Capital Contribution and Partners' Equity (Details) [Line Items] | |||||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share) | $ 0.107397 | ||||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 2,000,000 | ||||||||
Distribution Made to Limited Partner, Distribution Rate | 7.00% |
Related Parties (Details)
Related Parties (Details) - USD ($) | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
General Partner [Member] | ||
Related Parties (Details) [Line Items] | ||
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party | $ 71,000 | $ 80,000 |
Due to Related Parties, Current | 71,000 | |
Affiliated Entity [Member] | ||
Related Parties (Details) [Line Items] | ||
Operating Leases, Rent Expense | 25,611 | $ 25,611 |
Operating Leases, Rent Expense, Minimum Rentals | 8,537 | |
General Partner Reimbursement | (47,000) | |
Due from Related Parties | 47,000 | |
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) - USD ($) | 1 Months Ended | 3 Months Ended | |
Apr. 30, 2018 | Mar. 31, 2018 | Mar. 31, 2017 | |
Subsequent Events (Details) [Line Items] | |||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 5,676,446 | $ 5,488,149 | |
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.299178 | $ 0.349041 | |
Subsequent Event [Member] | |||
Subsequent Events (Details) [Line Items] | |||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 2,000,000 | ||
Distribution Made to Limited Partner, Distributions Paid, Per Unit | $ 0.107397 |