Document And Entity Information
Document And Entity Information - shares | 9 Months Ended | |
Sep. 30, 2019 | Oct. 31, 2019 | |
Document Information Line Items | ||
Entity Registrant Name | Energy 11, L.P | |
Document Type | 10-Q | |
Current Fiscal Year End Date | --12-31 | |
Entity Common Stock, Shares Outstanding | 18,973,474 | |
Amendment Flag | false | |
Entity Central Index Key | 0001581552 | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Document Period End Date | Sep. 30, 2019 | |
Document Fiscal Year Focus | 2019 | |
Document Fiscal Period Focus | Q3 | |
Entity Small Business | true | |
Entity Emerging Growth Company | true | |
Entity Shell Company | false | |
Entity Ex Transition Period | true | |
Document Quarterly Report | true | |
Document Transition Report | false | |
Entity File Number | 000-55615 | |
Entity Incorporation, State or Country Code | DE | |
Entity Tax Identification Number | 46-3070515 | |
Entity Address, Address Line One | 120 W 3rd Street | |
Entity Address, Address Line Two | Suite 220 | |
Entity Address, City or Town | Fort Worth | |
Entity Address, State or Province | TX | |
Entity Address, Postal Zip Code | 76102 | |
City Area Code | (817) | |
Local Phone Number | 882-9192 | |
Title of 12(b) Security | None | |
Entity Interactive Data Current | Yes | |
No Trading Symbol Flag | true |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) | Sep. 30, 2019 | Dec. 31, 2018 |
Assets | ||
Cash and cash equivalents | $ 85,134 | $ 3,685,327 |
Oil, natural gas and natural gas liquids revenue receivable | 3,856,520 | 6,269,243 |
Derivative asset | 498,790 | 0 |
Other current assets | 207,611 | 198,770 |
Total Current Assets | 4,648,055 | 10,153,340 |
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $50,157,260 and $40,806,378, respectively | 311,647,373 | 313,116,985 |
Total Assets | 316,295,428 | 323,270,325 |
Liabilities | ||
Revolving credit facility | 16,800,000 | 13,800,000 |
Accounts payable and accrued expenses | 6,104,661 | 2,430,656 |
Total Current Liabilities | 22,904,661 | 16,230,656 |
Asset retirement obligations | 1,419,645 | 1,294,067 |
Total Liabilities | 24,324,306 | 17,524,723 |
Partners’ Equity | ||
Limited partners' interest (18,973,474 common units issued and outstanding) | 291,972,849 | 305,747,329 |
General partner's interest | (1,727) | (1,727) |
Class B Units (62,500 units issued and outstanding) | 0 | 0 |
Total Partners’ Equity | 291,971,122 | 305,745,602 |
Total Liabilities and Partners’ Equity | $ 316,295,428 | $ 323,270,325 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parentheticals) - USD ($) | Sep. 30, 2019 | Dec. 31, 2018 |
Oil and natural gas properties, accumulated depreciation, depletion and amortization (in Dollars) | $ 50,157,260 | $ 40,806,378 |
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, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Revenues | ||||
Oil | $ 6,649,652 | $ 13,600,381 | $ 22,612,030 | $ 36,403,912 |
Natural gas | 429,347 | 748,818 | 2,066,813 | 2,233,675 |
Natural gas liquids | 260,110 | 1,339,689 | 2,069,270 | 3,542,357 |
Total revenue | 7,339,109 | 15,688,888 | 26,748,113 | 42,179,944 |
Operating costs and expenses | ||||
Production expenses | 2,228,933 | 2,914,785 | 7,977,046 | 8,536,265 |
Production taxes | 558,288 | 1,365,925 | 2,132,056 | 3,657,937 |
General and administrative expenses | 281,308 | 343,955 | 1,043,293 | 1,042,228 |
Depreciation, depletion, amortization and accretion | 2,767,479 | 4,481,712 | 9,403,364 | 12,705,908 |
Total operating costs and expenses | 5,836,008 | 9,106,377 | 20,555,759 | 25,942,338 |
Operating income | 1,503,101 | 6,582,511 | 6,192,354 | 16,237,606 |
Gain (loss) on derivatives | 498,790 | (38,921) | 498,790 | (2,943,000) |
Interest expense, net | (207,847) | (183,480) | (598,063) | (574,127) |
Total other expense, net | 290,943 | (222,401) | (99,273) | (3,517,127) |
Net income | $ 1,794,044 | $ 6,360,110 | $ 6,093,081 | $ 12,720,479 |
Basic and diluted net income per common unit (in Dollars per share) | $ 0.09 | $ 0.34 | $ 0.32 | $ 0.67 |
Weighted average common units outstanding - basic and diluted (in Shares) | 18,973,474 | 18,973,474 | 18,973,474 | 18,973,474 |
Consolidated Statements of Part
Consolidated Statements of Partners' Equity - USD ($) | Total | Limited Partner [Member] | General Partner [Member] | Member Units [Member]Capital Unit, Class B [Member] |
Balance at Dec. 31, 2017 | $ 314,252,610 | $ 314,254,337 | $ (1,727) | |
Balance (in Shares) at Dec. 31, 2017 | 18,973,474 | 62,500 | ||
Distributions declared and to common units paid | (5,676,446) | $ (5,676,446) | ||
Net Income | 3,325,445 | 3,325,445 | ||
Balance at Mar. 31, 2018 | 311,901,609 | $ 311,903,336 | (1,727) | |
Balance (in Shares) at Mar. 31, 2018 | 18,973,474 | 62,500 | ||
Balance at Dec. 31, 2017 | 314,252,610 | $ 314,254,337 | (1,727) | |
Balance (in Shares) at Dec. 31, 2017 | 18,973,474 | 62,500 | ||
Distributions declared and to common units paid | (20,522,525) | |||
Net Income | 12,720,479 | |||
Balance at Sep. 30, 2018 | 306,450,564 | $ 306,452,291 | (1,727) | |
Balance (in Shares) at Sep. 30, 2018 | 18,973,474 | 62,500 | ||
Balance at Mar. 31, 2018 | 311,901,609 | $ 311,903,336 | (1,727) | |
Balance (in Shares) at Mar. 31, 2018 | 18,973,474 | 62,500 | ||
Distributions declared and to common units paid | (7,001,990) | $ (7,001,990) | ||
Net Income | 3,034,924 | 3,034,924 | ||
Balance at Jun. 30, 2018 | 307,934,543 | $ 307,936,270 | (1,727) | |
Balance (in Shares) at Jun. 30, 2018 | 18,973,474 | 62,500 | ||
Distributions declared and to common units paid | (7,844,089) | $ (7,844,089) | ||
Net Income | 6,360,110 | 6,360,110 | ||
Balance at Sep. 30, 2018 | 306,450,564 | $ 306,452,291 | (1,727) | |
Balance (in Shares) at Sep. 30, 2018 | 18,973,474 | 62,500 | ||
Balance at Dec. 31, 2018 | $ 305,745,602 | $ 305,747,329 | (1,727) | |
Balance (in Shares) at Dec. 31, 2018 | 18,973,474 | 18,973,474 | 62,500 | |
Distributions declared and to common units paid | $ (6,622,520) | $ (6,622,520) | ||
Net Income | 2,339,974 | 2,339,974 | ||
Balance at Mar. 31, 2019 | 301,463,056 | $ 301,464,783 | (1,727) | |
Balance (in Shares) at Mar. 31, 2019 | 18,973,474 | 62,500 | ||
Balance at Dec. 31, 2018 | $ 305,745,602 | $ 305,747,329 | (1,727) | |
Balance (in Shares) at Dec. 31, 2018 | 18,973,474 | 18,973,474 | 62,500 | |
Distributions declared and to common units paid | $ (19,867,561) | |||
Net Income | 6,093,081 | |||
Balance at Sep. 30, 2019 | $ 291,971,122 | $ 291,972,849 | (1,727) | |
Balance (in Shares) at Sep. 30, 2019 | 18,973,474 | 18,973,474 | 62,500 | |
Balance at Mar. 31, 2019 | $ 301,463,056 | $ 301,464,783 | (1,727) | |
Balance (in Shares) at Mar. 31, 2019 | 18,973,474 | 62,500 | ||
Distributions declared and to common units paid | (6,622,521) | $ (6,622,521) | ||
Net Income | 1,959,063 | 1,959,063 | ||
Balance at Jun. 30, 2019 | 296,799,598 | $ 296,801,325 | (1,727) | |
Balance (in Shares) at Jun. 30, 2019 | 18,973,474 | 62,500 | ||
Distributions declared and to common units paid | (6,622,520) | $ (6,622,520) | ||
Net Income | 1,794,044 | 1,794,044 | ||
Balance at Sep. 30, 2019 | $ 291,971,122 | $ 291,972,849 | $ (1,727) | |
Balance (in Shares) at Sep. 30, 2019 | 18,973,474 | 18,973,474 | 62,500 |
Consolidated Statements of Pa_2
Consolidated Statements of Partners' Equity (Parentheticals) - $ / shares | 3 Months Ended | |||||
Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | |
Member Units [Member] | Capital Unit, Class B [Member] | ||||||
Distributions declared and paid, per common unit | $ 0.349041 | $ 0.349041 | $ 0.349041 | $ 0.413424 | $ 0.369041 | $ 0.299178 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) | 9 Months Ended | |
Sep. 30, 2019 | Sep. 30, 2018 | |
Cash flow from operating activities: | ||
Net income | $ 6,093,081 | $ 12,720,479 |
Adjustments to reconcile net income to cash from operating activities: | ||
Depreciation, depletion, amortization and accretion | 9,403,364 | 12,705,908 |
(Gain) / loss on mark-to-market of derivatives | (498,790) | 410,768 |
Non-cash expenses, net | 37,328 | 33,749 |
Changes in operating assets and liabilities: | ||
Oil, natural gas and natural gas liquids revenue receivable | 2,412,723 | (2,638,182) |
Other current assets | (36,170) | (108,618) |
Accounts payable and accrued expenses | (603,796) | 837,721 |
Net cash flow provided by operating activities | 16,807,740 | 23,961,825 |
Cash flow from investing activities: | ||
Additions to oil and natural gas properties | (3,540,372) | (7,260,576) |
Net cash flow used in investing activities | (3,540,372) | (7,260,576) |
Cash flow from financing activities: | ||
Cash paid for loan costs | 0 | (1,845) |
Proceeds from revolving credit facility | 3,000,000 | 0 |
Payments on revolving credit facility | 0 | (6,200,000) |
Distributions paid to limited partners | (19,867,561) | (20,522,525) |
Net cash flow (used in) provided by financing activities | (16,867,561) | (26,724,370) |
Decrease in cash and cash equivalents | (3,600,193) | (10,023,121) |
Cash and cash equivalents, beginning of period | 3,685,327 | 11,090,846 |
Cash and cash equivalents, end of period | 85,134 | 1,067,725 |
Interest paid | $ 574,334 | $ 564,701 |
Partnership Organization
Partnership Organization | 9 Months Ended |
Sep. 30, 2019 | |
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, 2019, the Partnership owned an approximate 25-26% non-operated working interest in 222 currently producing wells, 12 wells in various stages of the drilling and completion process and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”), 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, 2019 | |
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 2018 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 2019 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2019. 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, 2019 and 2018. 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 5) will occur. Recently Adopted Accounting Standards In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) No. 2016-02, Leases (Topic 842) |
Oil and Natural Gas Investments
Oil and Natural Gas Investments | 9 Months Ended |
Sep. 30, 2019 | |
Oil and Gas Property [Abstract] | |
Oil and Gas Properties [Text Block] | Note 3. Oil and Natural Gas Investments On December 18, 2015, the Partnership completed its first purchase (“Acquisition No. 1”) in the Sanish field, acquiring an approximate 11% non-operated working interest in the Sanish Field Assets for approximately $159.6 million. On January 11, 2017, the Partnership closed on its second purchase (“Acquisition No. 2”) in the Sanish field, acquiring an additional approximate 11% non-operated working interest in the Sanish Field Assets for approximately $128.5 million. On March 31, 2017, the Partnership closed on its third purchase (“Acquisition No. 3”) in the Sanish field, acquiring an additional approximate average 10.5% non-operated working interest in 82 of the Partnership’s then 216 existing producing wells and 150 of the Partnership’s then 253 future development locations in the Sanish Field Assets for approximately $52.4 million. During 2018, six wells were completed by the Partnership’s operators. Two wells were completed by and are being operated by Whiting; the Partnership has an approximate 29% non-operated working interest in these two wells. The other four wells were completed by and are operated by Oasis; the Partnership has an approximate 8% non-operated working interest in these four wells. In total, the Partnership’s capital expenditures for the drilling and completion of these six wells were approximately $7.8 million. The Partnership has elected to participate in the drilling and completion of 19 new wells during the nine months ended September 30, 2019. In total, capital expenditures for the drilling and completion of the 19 wells are estimated to be approximately $31 million, and the Partnership will have an average approximate non-operated working interest of 22% in these 19 wells upon completion. One well has been completed and drilling activities have commenced for 12 of the remaining 18 wells. The Partnership has incurred approximately $7.1 million in capital expenditures for these 13 wells as of September 30, 2019. The remaining 18 wells are expected to be completed over the next one to six months from September 30, 2019. As of September 30, 2019 and December 31, 2018, the Partnership had approximately $4.4 million and $0.1 million, respectively, in outstanding capital expenditures, which are included in Accounts payable and accrued liabilities on the Partnership’s consolidated balance sheets. |
Debt
Debt | 9 Months Ended |
Sep. 30, 2019 | |
Debt Disclosure [Abstract] | |
Debt Disclosure [Text Block] | Note 4. Debt On November 21, 2017, the Partnership, as the borrower, entered into a loan agreement (the “Loan Agreement”), which provided for a revolving credit facility with an approved initial commitment amount of $20 million, subject to borrowing base restrictions. The maturity date was November 21, 2019. Effective September 30, 2019, the Partnership entered into an amendment and restatement of the Loan Agreement (the “Amended Loan Agreement”), which provides for a revolving credit facility (“Credit Facility”) with an approved initial commitment of $40 million (the “Revolver Commitment Amount”), subject to borrowing base restrictions. The terms of the Amended Loan Agreement are generally similar to those of the original Loan Agreement and include the following: (i) a maturity date of September 30, 2022; (ii) subject to certain exceptions, an interest rate, which did not change from the existing revolving credit facility, equal to the London Inter-Bank Offered Rate (LIBOR) plus a margin ranging from 2.50% to 3.50%, depending upon the Partnership’s borrowing base utilization, as calculated under the terms of the Amended Loan Agreement; (iii) an increase to the borrowing base from $30 million to an initially stipulated $40 million; and (iv) an increase to the mortgage and lenders’ first lien position from 80% to 90% of the Partnership’s owned producing oil and natural gas properties. The Revolver Commitment Amount may be increased up to $75 million with lender approval. At September 30, 2019, the outstanding balance on the Credit Facility was $16.8 million, and the interest rate for the Credit Facility was approximately 4.87%. Outstanding borrowings under the Credit Facility cannot exceed the lesser of the borrowing base or the Revolver Commitment Amount at any time; the effective borrowing base and the Revolver Commitment Amount were both $40 million at September 30, 2019. At closing, the Partnership paid an origination fee of 0.45% on the increase in Revolver Commitment Amount of the Credit Facility (increase from $20 million on previous credit facility to $40 million under revised Credit Facility, or $20 million), or $90,000, and is subject to origination fees of 0.45% for any borrowings made in excess of the Revolver Commitment Amount (as noted above, an increase to the Revolver Commitment Amount would require lender approval). The Partnership is also required to pay an unused facility fee of 0.50% on the unused portion of the Revolver Commitment Amount, based on the amount of borrowings outstanding during a quarter. The Amended Loan Agreement requires the Partnership to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production if the Partnership’s borrowing base becomes equal to or greater than 50% of the Partnership’s producing reserves as calculated by its independent petroleum engineer,. If this condition is met, the risk management program must cover at least 50% of the Partnership’s projected total production of oil and natural gas for a rolling 18-month period. At September 30, 2019, the Partnership’s borrowing base of $40 million does not exceed 50% of its estimated producing reserves; therefore, the Partnership is not required to maintain a risk management program. The Amended Loan Agreement does permit the Partnership to enter into derivative contracts with a counterparty at its own discretion so long as the term does not exceed 36 months and does not cover more than 80% of the Partnership’s projected oil and gas volumes. The Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants, each as defined in the Amended Loan Agreement, include: - A maximum ratio of funded debt to trailing 12-month EBITDAX of 3.50 to 1.00 - A minimum ratio of current assets to current liabilities of 1.00 to 1.00 - A minimum ratio of EBITDAX to cash interest expense of 2.50 to 1.00 for trailing 12-month period - A limit to Partnership distributions if certain terms and conditions are not met, including being limited to 50% of the previous quarter EBITDAX beginning April 1, 2020. The Partnership was in compliance with the applicable covenants at September 30, 2019. Subject to availability, the Credit Facility may provide additional liquidity for future capital investments, including the drilling and completion of wells currently being developed and proposed wells by the Partnership’s operators, and other corporate working capital requirements. Under the Credit Facility, the Partnership may make voluntary prepayments in whole or in part at any time without penalty. As of September 30, 2019 and December 31, 2018, the outstanding balance on the Credit Facility was $16.8 million and $13.8 million, respectively, 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, 2019 | |
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: 2019 2018 Balance at January 1 $ 1,294,067 $ 1,226,879 Well additions 73,096 - Accretion 52,482 50,391 Revisions - - Balance at September 30 $ 1,419,645 $ 1,277,270 |
Fair Value of Financial Instrum
Fair Value of Financial Instruments | 9 Months Ended |
Sep. 30, 2019 | |
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, 2019 and 2018, there were no transfers in or out of Level 1, Level 2, or Level 3 assets and liabilities measured on a recurring basis. As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2019. The Partnership had no outstanding derivative contracts as of December 31, 2018. Fair Value Measurements at September 30, 2019 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current assets $ - $ 498,790 $ - Total $ - $ 498,790 $ - 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 asset at September 30, 2019. 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, 2019 | |
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 September 2019, the Partnership entered into derivative contracts to manage the commodity price risk on the Partnership’s future oil production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations. All derivative instruments are recorded on the Partnership’s balance sheet as assets or liabilities measured at fair value. As discussed in Note 4. Debt, the Partnership will be required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production if the Partnership’s borrowing base becomes equal to or greater than 50% of the Partnership’s producing reserves as calculated by its independent petroleum engineer. At September 30, 2019, the Partnership’s costless collar derivative instrument was in a gain position; therefore, a current asset of approximately $0.5 million, which approximates fair value, was recognized as a Derivative asset on the Partnership’s consolidated balance sheet. The fair value of the Derivative asset at September 30, 2019 was determined based on Level 2 inputs as defined under the fair value hierarchy, which include future prices, volatility and time to maturity, among other things. Counterparty statements were utilized to determine the value of the commodity derivative instruments, and the Partnership reviewed and corroborated the counterparty statements using various methodologies and significant observable inputs. 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 mark-to-market gain of approximately $0.5 million for the three and nine months ended September 30, 2019, which was recorded on the consolidated statements of operations as Gain (loss) on derivatives. No derivative contracts were settled during the three and nine months ended September 30, 2019. 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 gains or 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 gains or losses below represent the change in fair value of derivative instruments which were held at period-end. Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended Settlements on matured derivatives $ - $ (1,100,682 ) $ - $ (2,532,232 ) Gain (loss) on mark-to-market of derivatives 498,790 1,061,761 498,790 (410,768 ) Gain (loss) on derivatives $ 498,790 $ (38,921 ) $ 498,790 $ (2,943,000 ) At September 30, 2019, the Partnership had one derivative contract, which was a costless collar, and was used to establish floor and ceiling prices on future anticipated oil production. The Partnership did not pay or receive a premium related to the costless collar agreement. The contract is settled monthly and there were no settlement payables or receivables at September 30, 2019. The following table reflects information on the open costless collar contract as of September 30, 2019. Settlement Period Basis Oil (Barrels) Floor / Ceiling Prices Fair Value of Asset / (Liability) at 10/01/19 - 03/31/20 NYMEX (WTI) 167,000 $ 55.00 / 59.25 $ 498,790 The Partnership’s outstanding derivative instrument is covered by an International Swap Dealers Association Master Agreement (“ISDA”) entered into with the counterparty. The ISDA may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately. The Partnership has netting arrangements with the counterparty that provide for offsetting payables against receivables from separate derivative instruments. |
Capital Contribution and Partne
Capital Contribution and Partners' Equity | 9 Months Ended |
Sep. 30, 2019 | |
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, 2019, the Partnership paid distributions of $0.349041 and $1.047123 per common unit, or $6.6 million and $19.9 million, respectively. 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. |
Related Parties
Related Parties | 9 Months Ended |
Sep. 30, 2019 | |
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, 2019, approximately $88,000 and $236,000 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, 2019, approximately $88,000 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, 2018, approximately $58,000 and $188,000 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, 2019 and 2018, the Partnership paid $25,611 and $76,833 in each period, respectively, to the affiliate of the General Partner. The office space is shared between the Partnership and ER12; therefore, under the cost sharing agreement, the monthly payment of $8,537 is split between the two partnerships. In addition to the office space, the cost sharing agreement reduces the costs to the Partnership for accounting and asset management services provided through a member of the General Partner noted above. The compensation due to Clifford J. Merritt, President of the General Partner, is also a shared cost between the Partnership and ER12. For the three and nine months ended September 30, 2019, approximately $65,000 and $200,000, respectively, of expenses subject to the cost sharing agreement were paid by the Partnership and have been or will be reimbursed by ER12. At September 30, 2019, the approximately $65,000 due to the Partnership from ER12 is included in Other current assets in the consolidated balance sheets. 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 reimbursed by ER12. |
Subsequent Events
Subsequent Events | 9 Months Ended |
Sep. 30, 2019 | |
Subsequent Events [Abstract] | |
Subsequent Events [Text Block] | Note 10. Subsequent Events In October 2019, the Partnership entered into an amendment and restatement of its existing revolving credit facility, effective September 30, 2019. At closing, the Partnership borrowed an incremental $0.2 million under the restated Credit Facility to pay closing costs. See further discussion above in Note 4. Debt. In October 2019, 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, 2019 | |
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 2018 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 2019 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2019. |
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, 2019 and 2018. 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 5) will occur. |
New Accounting Pronouncements, Policy [Policy Text Block] | Recently Adopted Accounting Standards In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) No. 2016-02, Leases (Topic 842) |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Asset Retirement Obligations [Table Text Block] | The changes in the aggregate ARO are as follows: 2019 2018 Balance at January 1 $ 1,294,067 $ 1,226,879 Well additions 73,096 - Accretion 52,482 50,391 Revisions - - Balance at September 30 $ 1,419,645 $ 1,277,270 |
Fair Value of Financial Instr_2
Fair Value of Financial Instruments (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
Fair Value Disclosures [Abstract] | |
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block] | As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2019. The Partnership had no outstanding derivative contracts as of December 31, 2018. Fair Value Measurements at September 30, 2019 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current assets $ - $ 498,790 $ - Total $ - $ 498,790 $ - |
Risk Management (Tables)
Risk Management (Tables) | 9 Months Ended |
Sep. 30, 2019 | |
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 gains or 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 gains or losses below represent the change in fair value of derivative instruments which were held at period-end. Three Months Ended Three Months Ended Nine Months Ended Nine Months Ended Settlements on matured derivatives $ - $ (1,100,682 ) $ - $ (2,532,232 ) Gain (loss) on mark-to-market of derivatives 498,790 1,061,761 498,790 (410,768 ) Gain (loss) on derivatives $ 498,790 $ (38,921 ) $ 498,790 $ (2,943,000 ) |
Schedule of Derivative Instruments [Table Text Block] | At September 30, 2019, the Partnership had one derivative contract, which was a costless collar, and was used to establish floor and ceiling prices on future anticipated oil production. The Partnership did not pay or receive a premium related to the costless collar agreement. The contract is settled monthly and there were no settlement payables or receivables at September 30, 2019. The following table reflects information on the open costless collar contract as of September 30, 2019. Settlement Period Basis Oil (Barrels) Floor / Ceiling Prices Fair Value of Asset / (Liability) at 10/01/19 - 03/31/20 NYMEX (WTI) 167,000 $ 55.00 / 59.25 $ 498,790 |
Partnership Organization (Detai
Partnership Organization (Details) shares in Millions | Jul. 09, 2013USD ($) | Sep. 30, 2019 | Apr. 24, 2017USD ($)shares |
Partnership Organization (Details) [Line Items] | |||
Limited Liability Company or Limited Partnership, Business, Formation State | Delaware | ||
Partners' Capital Account, Contributions (in Dollars) | $ 1,000 | ||
Oil and Gas, Present Activity, Well in Process of Drilling | 12 | ||
Sanish Field Located in Mountrail County, North Dakota [Member] | |||
Partnership Organization (Details) [Line Items] | |||
Oil, Productive Well, Number of Wells, Net | 222 | ||
Oil and Gas, Present Activity, Well in Process of Drilling | 12 | ||
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 |
Oil and Natural Gas Investmen_2
Oil and Natural Gas Investments (Details) $ in Millions | Mar. 31, 2017 | Jan. 11, 2017USD ($) | Dec. 18, 2015USD ($) | Mar. 31, 2017USD ($) | Sep. 30, 2019USD ($) | Sep. 30, 2019USD ($) | Dec. 31, 2018USD ($) | Sep. 30, 2019USD ($) |
Oil and Natural Gas Investments (Details) [Line Items] | ||||||||
Oil and Gas, Development Well Drilled, Net Productive, Number | 1 | 2 | ||||||
Working Interest | 22.00% | 22.00% | 22.00% | |||||
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars) | $ 31 | |||||||
Wells Elected to Participate in Drilling | 19 | |||||||
Oil and Gas, Present Activity, Well in Process of Drilling | 12 | 12 | 12 | |||||
Number of Remaining AFE Wells | 18 | |||||||
Costs Incurred, Development Costs (in Dollars) | $ 4.4 | $ 0.1 | ||||||
Sanish Field Located in Mountrail County, North Dakota [Member] | ||||||||
Oil and Natural Gas Investments (Details) [Line Items] | ||||||||
Oil and Gas, Development Well Drilled, Net Productive, Number | 6 | |||||||
Capital Expenditures for 13 Wells [Member] | ||||||||
Oil and Natural Gas Investments (Details) [Line Items] | ||||||||
Oil and Gas, Present Activity, Well in Process of Drilling | 13 | 13 | 13 | |||||
Costs Incurred, Development Costs (in Dollars) | $ 7.1 | |||||||
Minimum [Member] | ||||||||
Oil and Natural Gas Investments (Details) [Line Items] | ||||||||
Expected Time to Completion | 1 month | |||||||
Maximum [Member] | ||||||||
Oil and Natural Gas Investments (Details) [Line Items] | ||||||||
Expected Time to Completion | 6 months | |||||||
Sanish Field Located in Mountrail County, North Dakota [Member] | ||||||||
Oil and Natural Gas Investments (Details) [Line Items] | ||||||||
Oil, Productive Well, Number of Wells, Net | 222 | 222 | 222 | |||||
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars) | $ 7.8 | |||||||
Oil and Gas, Present Activity, Well in Process of Drilling | 12 | 12 | 12 | |||||
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) | $ 159.6 | |||||||
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) | $ 128.5 | |||||||
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) | $ 52.4 | |||||||
Number of Producing Partnership Wells Acquired | 82 | |||||||
Oil, Productive Well, Number of Wells, Net | 216 | 216 | ||||||
Number of Future Development Partnership Locations Acquired | 150 | |||||||
Gas and Oil Area Undeveloped, Net | 253 | |||||||
Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member] | ||||||||
Oil and Natural Gas Investments (Details) [Line Items] | ||||||||
Gas and Oil Area Developed, Net | 25.00% | |||||||
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% | |||||||
Whiting Petroleum [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | ||||||||
Oil and Natural Gas Investments (Details) [Line Items] | ||||||||
Oil and Gas, Development Well Drilled, Net Productive, Number | 2 | |||||||
Working Interest | 29.00% | |||||||
Oasis Petroleum, Inc. [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | ||||||||
Oil and Natural Gas Investments (Details) [Line Items] | ||||||||
Oil and Gas, Development Well Drilled, Net Productive, Number | 4 | |||||||
Working Interest | 8.00% |
Debt (Details)
Debt (Details) - USD ($) | Sep. 30, 2019 | Dec. 31, 2018 | Nov. 21, 2017 |
Debt (Details) [Line Items] | |||
Line of Credit, Current | $ 16,800,000 | $ 13,800,000 | |
Revolving Credit Facility [Member] | |||
Debt (Details) [Line Items] | |||
Debt Instrument, Face Amount | $ 20,000,000 | ||
Line of Credit Facility, Borrowing Capacity, Description | The Revolver Commitment Amount may be increased up to $75 million | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 75,000,000 | ||
Line of Credit, Current | $ 16,800,000 | ||
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | 4.87% | ||
Line of Credit Facility, Current Borrowing Capacity | $ 40,000,000 | ||
Line of Credit Facility, Commitment Fee Description | the Partnership paid an origination fee of 0.45% on the increase in Revolver Commitment Amount of the Credit Facility (increase from $20 million on previous credit facility to $40 million under revised Credit Facility, or $20 million), or $90,000 | ||
Line of Credit Facility, Commitment Fee Percentage | 0.45% | ||
Line of Credit Facility, Commitment Fee Amount | $ 90,000 | ||
Line of Credit Facility, Commitment Fee in Excess of Revolver Amount, Percentage | 0.45% | ||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.50% | ||
Debt, Risk Management, Description | The Amended Loan Agreement requires the Partnership to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production if the Partnership’s borrowing base becomes equal to or greater than 50% of the Partnership’s producing reserves as calculated by its independent petroleum engineer,. If this condition is met, the risk management program must cover at least 50% of the Partnership’s projected total production of oil and natural gas for a rolling 18-month period. At September 30, 2019, the Partnership’s borrowing base of $40 million does not exceed 50% of its estimated producing reserves; therefore, the Partnership is not required to maintain a risk management program. The Amended Loan Agreement does permit the Partnership to enter into derivative contracts with a counterparty at its own discretion so long as the term does not exceed 36 months and does not cover more than 80% of the Partnership’s projected oil and gas volumes. | ||
Line of Credit Facility, Covenant Terms | The Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants, each as defined in the Amended Loan Agreement, include: - A maximum ratio of funded debt to trailing 12-month EBITDAX of 3.50 to 1.00 - A minimum ratio of current assets to current liabilities of 1.00 to 1.00 - A minimum ratio of EBITDAX to cash interest expense of 2.50 to 1.00 for trailing 12-month period - A limit to Partnership distributions if certain terms and conditions are not met, including being limited to 50% of the previous quarter EBITDAX beginning April 1, 2020. | ||
Line of Credit Facility, Covenant Compliance | The Partnership was in compliance with the applicable covenants at September 30, 2019. | ||
Revolving Credit Facility [Member] | Amended Loan Agreement [Member] | |||
Debt (Details) [Line Items] | |||
Debt Instrument, Face Amount | $ 40,000,000 | ||
Debt Instrument, Maturity Date | Sep. 30, 2022 | ||
Line of Credit Facility, Borrowing Capacity, Description | an increase to the borrowing base from $30 million to an initially stipulated $40 million | ||
Line of Credit Facility, Collateral | an increase to the mortgage and lenders’ first lien position from 80% to 90% of the Partnership’s owned producing oil and natural gas properties | ||
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | Amended Loan Agreement [Member] | Minimum [Member] | |||
Debt (Details) [Line Items] | |||
Debt Instrument, Basis Spread on Variable Rate | 2.50% | ||
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member] | Amended Loan Agreement [Member] | Maximum [Member] | |||
Debt (Details) [Line Items] | |||
Debt Instrument, Basis Spread on Variable Rate | 3.50% |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations - USD ($) | 9 Months Ended | |
Sep. 30, 2019 | Sep. 30, 2018 | |
Schedule of Asset Retirement Obligations [Abstract] | ||
Balance | $ 1,294,067 | $ 1,226,879 |
Well additions | 73,096 | 0 |
Accretion | 52,482 | 50,391 |
Revisions | 0 | 0 |
Balance | $ 1,419,645 | $ 1,277,270 |
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, 2019USD ($) |
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 |
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 | 498,790 |
Total | 498,790 |
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 |
Total | $ 0 |
Risk Management (Details)
Risk Management (Details) | 3 Months Ended | 9 Months Ended | |||
Sep. 30, 2019USD ($) | Sep. 30, 2018USD ($) | Sep. 30, 2019USD ($) | Sep. 30, 2018USD ($) | Dec. 31, 2018USD ($) | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||
Discussion of Price Risk Derivative Risk Management Policy | As discussed in Note 4. Debt, the Partnership will be required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production if the Partnership’s borrowing base becomes equal to or greater than 50% of the Partnership’s producing reserves as calculated by its independent petroleum engineer. | ||||
Derivative Asset, Current | $ 498,790 | $ 498,790 | $ 0 | ||
Derivative, Gain (Loss) on Derivative, Net | $ 498,790 | $ 1,061,761 | $ 498,790 | $ (410,768) | |
Number of Price Risk Derivatives Held | 1 | 1 |
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, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Abstract] | ||||
Settlements on matured derivatives | $ 0 | $ (1,100,682) | $ 0 | $ (2,532,232) |
Gain (loss) on mark-to-market of derivatives | 498,790 | 1,061,761 | 498,790 | (410,768) |
Gain (loss) on derivatives | $ 498,790 | $ (38,921) | $ 498,790 | $ (2,943,000) |
Risk Management (Details) - S_2
Risk Management (Details) - Schedule of Derivative Instruments - Price Risk Derivative [Member] | 9 Months Ended |
Sep. 30, 2019USD ($)$ / item$ / bblbbl | |
Derivative [Line Items] | |
Basis | NYMEX (WTI) |
Oil (in Barrels (of Oil)) | bbl | 167,000 |
Floor Prices | $ / item | 55 |
Ceiling Prices | $ / bbl | 59.25 |
Fair Value of Asset / (Liability) (in Dollars) | $ | $ 498,790 |
Capital Contribution and Part_2
Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions | Jul. 09, 2013 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | Apr. 24, 2017 |
Capital Contribution and Partners' Equity (Details) [Line Items] | ||||||||||
Partners' Capital Account, Contributions | $ 1,000 | |||||||||
Distributions to organizational limited partner | $ 990 | |||||||||
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) | $ 0.349041 | $ 0.413424 | $ 1.047123 | $ 1.081643 | ||||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 6,622,520 | $ 6,622,521 | $ 6,622,520 | $ 7,844,089 | $ 7,001,990 | $ 5,676,446 | $ 19,867,561 | $ 20,522,525 | ||
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, 2019 | Sep. 30, 2018 | Sep. 30, 2019 | Sep. 30, 2018 | |
General Partner [Member] | ||||
Related Parties (Details) [Line Items] | ||||
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party | $ 88,000 | $ 58,000 | $ 236,000 | $ 188,000 |
Due to Related Parties, Current | 88,000 | 88,000 | ||
Affiliated Entity [Member] | ||||
Related Parties (Details) [Line Items] | ||||
Operating Leases, Rent Expense | 25,611 | 76,833 | ||
Operating Leases, Rent Expense, Minimum Rentals | 8,537 | |||
Reimbursements From Related Party | 65,000 | $ 64,000 | 200,000 | $ 175,000 |
Due from Related Parties | $ 65,000 | $ 65,000 |
Subsequent Events (Details)
Subsequent Events (Details) - Subsequent Event [Member] $ / shares in Units, $ in Millions | 1 Months Ended |
Oct. 31, 2019USD ($)$ / shares | |
Subsequent Events (Details) [Line Items] | |
Proceeds from Lines of Credit | $ 0.2 |
Distribution Made to Limited Partner, Cash Distributions Paid | $ 2 |
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share) | $ / shares | $ 0.107397 |