Document And Entity Information
Document And Entity Information - shares | 9 Months Ended | |
Sep. 30, 2020 | Nov. 05, 2020 | |
Document Information Line Items | ||
Entity Registrant Name | Energy 11, L.P. | |
Document Type | 10-Q | |
Current Fiscal Year End Date | --12-31 | |
Entity Common Stock, Shares Outstanding | 18,973,474 | |
Amendment Flag | false | |
Entity Central Index Key | 0001581552 | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Non-accelerated Filer | |
Document Period End Date | Sep. 30, 2020 | |
Document Fiscal Year Focus | 2020 | |
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, 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, 2020 | Dec. 31, 2019 |
Assets | ||
Cash and cash equivalents | $ 5,254,981 | $ 348,550 |
Restricted cash and cash equivalents | 1,288,884 | 0 |
Oil, natural gas and natural gas liquids revenue receivable | 4,714,775 | 5,857,926 |
Other current assets | 418,001 | 284,652 |
Total Current Assets | 11,676,641 | 6,491,128 |
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $69,699,954 and $53,186,165, respectively | 328,844,767 | 326,758,636 |
Total Assets | 340,521,408 | 333,249,764 |
Liabilities | ||
Accounts payable, accrued expenses and other current liabilities | 3,208,326 | 20,061,059 |
Revolving credit facility | 40,000,000 | 0 |
Affiliate term loan | 15,000,000 | 0 |
Total Current Liabilities | 58,208,326 | 20,061,059 |
Revolving credit facility | 0 | 24,000,000 |
Asset retirement obligations | 1,549,927 | 1,452,734 |
Total Liabilities | 59,758,253 | 45,513,793 |
Partners’ Equity | ||
Limited partners' interest (18,973,474 common units issued and outstanding, respectively) | 280,764,882 | 287,737,698 |
General partner's interest | (1,727) | (1,727) |
Class B Units (62,500 units issued and outstanding, respectively) | 0 | 0 |
Total Partners’ Equity | 280,763,155 | 287,735,971 |
Total Liabilities and Partners’ Equity | $ 340,521,408 | $ 333,249,764 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parentheticals) - USD ($) | Sep. 30, 2020 | Dec. 31, 2019 |
Statement of Financial Position [Abstract] | ||
Oil and natural gas properties, accumulated depreciation, depletion and amortization (in Dollars) | $ 69,699,954 | $ 53,186,165 |
Limited partners' interest, common units issued | 18,973,474 | 18,973,474 |
Limited partners' interest, common units outstanding | 18,973,474 | 18,973,474 |
Class B Units, units issued | 62,500 | 62,500 |
Class B Units, units outstanding | 62,500 | 62,500 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Revenues | ||||
Oil | $ 8,187,180 | $ 6,649,652 | $ 22,412,183 | $ 22,612,030 |
Natural gas | 636,971 | 429,347 | 1,392,651 | 2,066,813 |
Natural gas liquids | 826,117 | 260,110 | 1,701,486 | 2,069,270 |
Total revenue | 9,650,268 | 7,339,109 | 25,506,320 | 26,748,113 |
Operating costs and expenses | ||||
Production expenses | 2,825,472 | 2,228,933 | 6,997,839 | 7,977,046 |
Production taxes | 777,012 | 558,288 | 2,185,903 | 2,132,056 |
General and administrative expenses | 379,569 | 281,308 | 1,300,003 | 1,043,293 |
Depreciation, depletion, amortization and accretion | 6,112,621 | 2,767,479 | 16,575,336 | 9,403,364 |
Total operating costs and expenses | 10,094,674 | 5,836,008 | 27,059,081 | 20,555,759 |
Operating income (loss) | (444,406) | 1,503,101 | (1,552,761) | 6,192,354 |
Gain on derivatives | 94,299 | 498,790 | 535,189 | 498,790 |
Interest expense, net | (529,789) | (207,847) | (1,370,418) | (598,063) |
Total other expense, net | (435,490) | 290,943 | (835,229) | (99,273) |
Net income (loss) | $ (879,896) | $ 1,794,044 | $ (2,387,990) | $ 6,093,081 |
Basic and diluted net income (loss) per common unit (in Dollars per share) | $ (0.05) | $ 0.09 | $ (0.13) | $ 0.32 |
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] | Capital Unit, Class B [Member]Member Units [Member] |
Balance at Dec. 31, 2018 | $ 305,745,602 | $ 305,747,329 | $ (1,727) | |
Balance (in Shares) at Dec. 31, 2018 | 18,973,474 | 62,500 | ||
Distributions declared and paid to common units | (6,622,520) | $ (6,622,520) | ||
Net income (loss) | 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 | 62,500 | ||
Distributions declared and paid to common units | (19,867,561) | |||
Net income (loss) | 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 | 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 paid to common units | (6,622,521) | $ (6,622,521) | ||
Net income (loss) | 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 paid to common units | (6,622,520) | $ (6,622,520) | ||
Net income (loss) | 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 | 62,500 | ||
Balance at Dec. 31, 2019 | $ 287,735,971 | $ 287,737,698 | (1,727) | |
Balance (in Shares) at Dec. 31, 2019 | 18,973,474 | 18,973,474 | 62,500 | |
Distributions declared and paid to common units | $ (4,584,826) | $ (4,584,826) | ||
Net income (loss) | 2,933,427 | 2,933,427 | ||
Balance at Mar. 31, 2020 | 286,084,572 | $ 286,086,299 | (1,727) | |
Balance (in Shares) at Mar. 31, 2020 | 18,973,474 | 62,500 | ||
Balance at Dec. 31, 2019 | $ 287,735,971 | $ 287,737,698 | (1,727) | |
Balance (in Shares) at Dec. 31, 2019 | 18,973,474 | 18,973,474 | 62,500 | |
Distributions declared and paid to common units | $ (4,584,826) | |||
Net income (loss) | (2,387,990) | |||
Balance at Sep. 30, 2020 | $ 280,763,155 | $ 280,764,882 | (1,727) | |
Balance (in Shares) at Sep. 30, 2020 | 18,973,474 | 18,973,474 | 62,500 | |
Balance at Mar. 31, 2020 | $ 286,084,572 | $ 286,086,299 | (1,727) | |
Balance (in Shares) at Mar. 31, 2020 | 18,973,474 | 62,500 | ||
Net income (loss) | (4,441,521) | $ (4,441,521) | ||
Balance at Jun. 30, 2020 | 281,643,051 | $ 281,644,778 | (1,727) | |
Balance (in Shares) at Jun. 30, 2020 | 18,973,474 | 62,500 | ||
Net income (loss) | (879,896) | $ (879,896) | ||
Balance at Sep. 30, 2020 | $ 280,763,155 | $ 280,764,882 | $ (1,727) | |
Balance (in Shares) at Sep. 30, 2020 | 18,973,474 | 18,973,474 | 62,500 |
Consolidated Statements of Pa_2
Consolidated Statements of Partners' Equity (Parentheticals) - $ / shares | 3 Months Ended | |||
Mar. 31, 2020 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | |
Capital Unit, Class B [Member] | Member Units [Member] | ||||
Distributions declared and paid to common units, per unit | $ 0.241644 | $ 0.349041 | $ 0.369041 | $ 0.349041 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) | 3 Months Ended | 9 Months Ended | |
Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Cash flow from operating activities: | |||
Net income | $ 1,794,044 | $ (2,387,990) | $ 6,093,081 |
Depreciation, depletion, amortization and accretion | 2,767,479 | 16,575,336 | 9,403,364 |
(Gain) / loss on mark-to-market of derivatives | (250,149) | (498,790) | |
Non-cash expenses, net | 67,232 | 37,328 | |
Oil, natural gas and natural gas liquids revenue receivable | 1,143,151 | 2,412,723 | |
Other current assets | (134,283) | (36,170) | |
Accounts payable and accrued expenses | 39,550 | (603,796) | |
Net cash flow provided by operating activities | 15,052,847 | 16,807,740 | |
Cash flow from investing activities: | |||
Additions to oil and natural gas properties | (35,272,706) | (3,540,372) | |
Net cash flow used in investing activities | (35,272,706) | (3,540,372) | |
Cash flow from financing activities: | |||
Proceeds from revolving credit facility | 16,000,000 | 3,000,000 | |
Proceeds from affiliate term loan | 15,000,000 | 0 | |
Distributions paid to limited partners | (6,622,520) | (4,584,826) | (19,867,561) |
Net cash flow (used in) provided by financing activities | 26,415,174 | (16,867,561) | |
Decrease in cash and cash equivalents | 6,195,315 | (3,600,193) | |
Cash and cash equivalents, beginning of period | 348,550 | 3,685,327 | |
Cash and cash equivalents, end of period | $ 85,134 | 6,543,865 | 85,134 |
Interest paid | 1,336,840 | 574,334 | |
Accrued capital expenditures related to additions to oil and natural gas properties | $ 1,714,900 | $ 4,366,105 |
Partnership Organization
Partnership Organization | 9 Months Ended |
Sep. 30, 2020 | |
Accounting Policies [Abstract] | |
Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block] | Note 1. Partnership Organization Energy 11, L.P. (the “Partnership”) is a Delaware limited partnership formed to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties. The initial capitalization of the Partnership of $1,000 occurred on July 9, 2013. The Partnership completed its best-efforts offering on April 24, 2017 with a total of approximately 19.0 million common units sold for gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million. As of September 30, 2020, the Partnership owned an approximate 25% non-operated working interest in 243 producing wells, an estimated approximate 18% non-operated working interest in 21 wells in various stages of the drilling and completion process and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). Whiting Petroleum Corporation (“Whiting”) (NYSE: WLL) and Oasis Petroleum North America, LLC (“Oasis”) (NYSE: OAS), two of the largest producers in the basin, operate substantially all of the Sanish Field Assets. The general partner of the Partnership is Energy 11 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership. The Partnership’s fiscal year ends on December 31. Drilling Program, Oil Demand, Current Pricing, Liquidity and Going Concern Considerations During 2019 and the first quarter of 2020, the Partnership elected to participate in the drilling and completion of 43 new wells in the Sanish field. The Partnership estimates the total investment for these 43 new wells to be approximately $63 million. In conjunction with this drilling program performed primarily by Whiting, the Partnership had incurred approximately $42 million in capital expenditures through September 30, 2020, which was primarily funded by availability under the Partnership’s $40 million revolving credit facility (“Credit Facility”, described in Note 4. Debt). However, the Partnership used all availability under its Credit Facility by March 31, 2020, and as of June 30, 2020, the Partnership had approximately $20 million in accrued operating and capital expenditures due to Whiting. New production from completed wells was expected to enhance the Partnership’s operating performance throughout 2020, providing incremental cash flow from operations to fund the Partnership’s investment in its undrilled acreage. Subsequent to the Partnership’s election to participate in Whiting’s drilling program, the outbreak of a novel coronavirus (“COVID-19”) in China spread worldwide, forcing governments around the world to take drastic measures to halt the outbreak. These measures included significant restrictions on travel, forced quarantines, stay-at-home requirements and the closure of businesses in many industries for an undetermined period of time, creating extreme volatility in capital markets and the global economy. Because of COVID-19’s impact to the global economy, demand for oil, natural gas and other hydrocarbons substantially declined in March 2020 and has remained depressed through the third quarter of 2020. Demand for oil and natural gas is not anticipated to return to pre-COVID-19 levels during 2020, and the outlook for demand for oil and natural gas in 2021 is uncertain. This reduction in demand compounded an existing excess in supply of oil and natural gas, as the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia could not agree on daily production output of crude oil in March 2020. As a result, Russia announced its intention to increase production, and Saudi Arabia immediately countered with announced reductions to export prices. All of these factors led to oil prices falling in March 2020 and to 20-year lows in April 2020. Although NYMEX oil prices have stabilized around $40 per barrel since June 2020, prices throughout the third quarter of 2020 remained below pre-COVID-19 levels. In response to lower commodity prices and reduced demand, operators within the United States altered drilling programs and the related forecasted capital expenditures for those programs, and implemented other cost-saving measures, such as curtailing production or shutting in producing wells, during the second quarter of 2020. While operators have since returned significant inventory of existing wells to production, the nature and timing of drilling new wells remains uncertain. These factors have had and are anticipated to continue to have an adverse impact on the Partnership’s business and its financial condition. Due to the impacts to the global oil and gas industry described above, the General Partner approved the suspension of distributions to limited partners of the Partnership in March 2020. Further, Whiting and certain of its subsidiaries declared bankruptcy under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas on April 1, 2020. Subsequent to filing for Chapter 11 protection, Whiting suspended its Sanish field drilling program during the second quarter of 2020, but operated its business in the normal course without material disruption to its vendors, partners or employees, including the Partnership, during the bankruptcy process. Whiting completed its financial restructuring and emerged from bankruptcy protection in September 2020, but has yet to resume its drilling program. In July 2020, the Partnership entered into a loan agreement for a one year, $15 million term loan (“Affiliate Loan”) that matures on July 21, 2021 (see Note 4. Debt for additional information). The Partnership used proceeds from the Affiliate Loan plus cash on hand to pay the Partnership’s accrued operating and capital expenditures due to Whiting, which totaled approximately $19 million at the time of payment. In addition to the Affiliate Loan, the Partnership entered into a letter agreement (“Letter Agreement”) with its lending group for its Credit Facility. The Letter Agreement, among other items, waived the non-compliance of certain covenants under the Credit Facility; however, the Letter Agreement changed the maturity date of the Credit Facility from September 30, 2022 to July 31, 2021. In October 2020, the Partnership made a principal payment on the Affiliate Loan of $5 million; therefore, the Partnership’s outstanding debt obligations at the date of filing of this Form 10-Q total $50 million and mature within one year of the filing of this Form 10-Q. The Partnership’s ability to continue as a going concern is dependent on several factors including, but not limited to, (i) the Partnership’s ability to comply with its obligations under its loan agreements (see Note 4. Debt for further discussion); (ii) refinancing its existing debt and/or securing additional capital; (iii) an increase in demand for oil and natural gas as the global economy recovers from the effects of the COVID-19 pandemic and the existing oversupply of oil in the United States; and (iv) an increase in oil and natural gas market prices, which will improve the Partnership’s cash flow generated from operations. The Partnership can provide no assurance that it will be able to achieve any of these objectives. Refinancing its existing debt or securing additional capital may not be available on favorable terms to the Partnership, if it is available at all. There also can be no assurance that economic activity and oil and natural gas market conditions, including commodity prices, will return to pre-COVID-19 levels, or that the Partnership will be able to meet its operational obligations. If the Partnership is unable to refinance or repay its debt obligations or is unable to meet its operational obligations, the Partnership could be required to liquidate certain of its assets used for collateral to satisfy these obligations, which create the substantial doubt that exists about the ability of the Partnership to continue as a going concern for one year after the date these financial statements are issued. The accompanying financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classifications of liabilities that may result from the possible inability of the Partnership to continue as a going concern. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 9 Months Ended |
Sep. 30, 2020 | |
Accounting Policies [Abstract] | |
Significant Accounting Policies [Text Block] | Note 2. Summary of Significant Accounting Policies Basis of Presentation The accompanying unaudited financial statements have been prepared in accordance with the instructions for Article 10 of SEC Regulation S-X. Accordingly, they do not include all of the information required by generally accepted accounting principles (“GAAP”) in the United States. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. These unaudited financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements included in its 2019 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 2020 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2020. Use of Estimates The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Revenue Recognition The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Oil, natural gas and natural gas liquids revenue receivable in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers. Net Income (Loss) Per Common Unit Basic net income (loss) per common unit is computed as net income (loss) divided by the weighted average number of common units outstanding during the period. Diluted net income (loss) 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, 2020 and 2019. As a result, basic and diluted outstanding common units were the same. The Class B units and Incentive Distribution Rights, as defined below, are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 8) will occur. Recently Adopted Accounting Standards In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-04, Reference Rate Reform (Topic 848), which provides optional guidance through December 31, 2022 to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments in ASU No. 2020-04 apply to contract modifications that replace a reference rate affected by reference rate reform, providing optional expedients regarding the measurement of hedge effectiveness in hedging relationships that have been modified to replace a reference rate. While the guidance in ASU No. 2020-04 became effective upon issuance, the provisions of the ASU did not have a material impact on the Partnership’s consolidated financial statements and related disclosures as of September 30, 2020. |
Oil and Natural Gas Investments
Oil and Natural Gas Investments | 9 Months Ended |
Sep. 30, 2020 | |
Oil and Gas Property [Abstract] | |
Oil and Gas Properties [Text Block] | Note 3. Oil and Natural Gas Investments On December 18, 2015, the Partnership completed its first purchase 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 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 in the Sanish field, acquiring an additional approximate average 10.5% non-operated working interest in 82 of the Partnership’s then 216 existing producing wells and 150 of the Partnership’s then 253 future development locations in the Sanish Field Assets for approximately $52.4 million. During 2018, six wells were completed by the Partnership’s operators. Two wells were completed by and are being operated by Whiting; the Partnership has an approximate 29% non-operated working interest in these two wells. The other four wells were completed by and are operated by Oasis; the Partnership has an approximate 8% non-operated working interest in these four wells. In total, the Partnership’s capital expenditures for the drilling and completion of these six wells were approximately $7.8 million. During 2019 and the first quarter of 2020, the Partnership elected to participate in the drilling and completion of 43 new wells in the Sanish field. Twenty-two (22) of these 43 wells have been completed and were producing at September 30, 2020; the Partnership has an approximate non-operated working interest of 23% in these 22 wells. The Partnership has an estimated approximate non-operated working interest of 18% in the remaining 21 wells that are in-process as of September 30, 2020. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 43 wells is approximately $63 million, of which approximately $42 million was incurred as of September 30, 2020. Whiting suspended its Sanish field drilling program during the second quarter of 2020 in response to the significant reduction in demand for oil caused by COVID-19 and the oversupply of oil in the United States. The Partnership estimates it may incur approximately $1 to $2 million in additional capital expenditures during the fourth quarter of 2020; however, low commodity prices, market supply and demand imbalances and how Whiting’s emergence from bankruptcy protection in September 2020 impacts the resumption of its suspended drilling program make it difficult to predict the amount and timing of capital expenditures for the remainder of 2020. Estimated capital expenditures could be significantly different from amounts actually invested. Evaluation for Potential Impairment of Oil and Natural Gas Investments The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. The Partnership considered the declines in the current and forecasted operating cash flows resulting from COVID-19 and sustained lower commodity prices to be potential indicators of impairment and, as a result, performed a test of recoverability for the Sanish Field Assets. Estimated future net cash flows calculated in the recoverability test were based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. The underlying commodity prices used in the determination of the Partnership’s estimated future net cash flows were based on NYMEX forward strip prices as of October 1, 2020, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believed will impact realizable prices. Future operating cost estimates were based on actual historical costs of the Sanish Field Assets. The Partnership’s recoverability analyses did not identify any impairment losses as of September 30, 2020. If current macro-economic conditions continue or worsen, the carrying value of the Partnership’s oil and natural gas properties may not be recoverable and impairment losses could be recorded in future periods. |
Debt
Debt | 9 Months Ended |
Sep. 30, 2020 | |
Debt Disclosure [Abstract] | |
Debt Disclosure [Text Block] | Note 4. Debt Revolving Credit Facility On November 21, 2017, the Partnership, as the borrower, entered into a loan agreement (the “Loan Agreement”) between and among the Partnership and Simmons Bank, as administrative agent and the lenders party thereto (the “Lender”), 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”) with Lender, which provided for the Credit Facility with an approved initial commitment of $40 million (the “Revolver Commitment Amount”), subject to borrowing base restrictions. The terms of the Amended Loan Agreement were generally similar to the Partnership’s existing revolving credit facility and included the following: (i) a maturity date of September 30, 2022; (ii) subject to certain exceptions, an interest rate, which did not change from the existing revolving credit facility, equal to the London Inter-Bank Offered Rate (LIBOR) plus a margin ranging from 2.50% to 3.50%, depending upon the Partnership’s borrowing base utilization, as calculated under the terms of the Amended Loan Agreement; (iii) an increase to the borrowing base from $30 million to an initially stipulated $40 million; and (iv) an increase to the mortgage and lenders’ first lien position from 80% to 90% of the Partnership’s owned producing oil and natural gas properties. At closing of the Amended Loan Agreement in October 2019, the Partnership paid an origination fee of 0.45% on the change in Revolver Commitment Amount of the Credit Facility (increase from $20 million on previous credit facility to $40 million under revised Credit Facility, or $20 million), or $90,000. The Partnership is also required to pay an unused facility fee of 0.50% on the unused portion of the Revolver Commitment Amount, based on the amount of borrowings outstanding during a quarter. On July 21, 2020, the Partnership entered into a letter agreement (“Letter Agreement”) with Lender that amended and modified the Amended Loan Agreement. The modifications to the Amended Loan Agreement include, among other items, the following: - Maturity date was changed from September 30, 2022 to July 31, 2021; - Interest rate was changed to the prime rate plus 1.00%, with an interest rate floor of 4.00% (an increase of 50 basis points from the rate prior to the Letter Agreement); - Any future Partnership distributions to limited partners require Lender approval; - Calculation of the current ratio covenant was suspended until the reporting date of September 30, 2020; - The definition of current ratio excludes the Affiliate Loan (discussed below) from the definition of liabilities; and - As additional collateral for the loan, the Partnership established and funded a bank account with Lender in the amount of $1.6 million, to be used for interest payments under the Amended Loan Agreement until maturity (the balance of this collateral bank account at September 30, 2020 was approximately $1.3 million and is included in Restricted cash and cash equivalents on the Partnership’s September 30, 2020 consolidated balance sheet). Also, under the Letter Agreement, the Partnership is required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and natural gas sales. The risk management program must cover at least 80% of the Partnership’s projected total production of oil and natural gas for the period from August 31, 2020 until the next borrowing base redetermination date (first quarter of 2021). See more information on the Partnership’s hedging program in Note 7. Risk Management. In addition to the modification of certain terms under the Amended Loan Agreement, the Letter Agreement waived the defaults by the Partnership under the Amended Loan Agreement that existed prior to signing the Letter Agreement, including not meeting the current ratio covenant as of March 31, 2020, the Partnership not filing its first quarter financial statements within 60 days of March 31, 2020 and the non-payment by the Partnership of amounts due to Whiting. The Letter Agreement also waived the Partnership’s calculation of the current ratio covenant at June 30, 2020. The Letter Agreement also allows for the Affiliate Loan discussed below and payments under the Affiliate Loan. In consideration for the modifications, amendments and waivers described above to the Amended Loan Agreement, the Letter Agreement provides for an amendment fee to Lender of $40,000, of which $15,000 was paid on September 30, 2020 and $25,000 is due December 31, 2020. The Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants, each as defined in the Amended Loan Agreement, include: ● A maximum ratio of funded debt to trailing 12-month EBITDAX of 3.50 to 1.00 ● A minimum ratio of current assets to current liabilities of 1.00 to 1.00 (“Current Ratio”) ● A minimum ratio of EBITDAX to cash interest expense of 2.50 to 1.00 for trailing 12-month period The Partnership was in compliance with its applicable covenants at September 30, 2020. If the Partnership is not in compliance with its covenants in future periods, it may not be able to obtain waivers and the outstanding balance under the Credit Facility may become due on demand at that time. At September 30, 2020, the outstanding balance on the Credit Facility was $40 million, and the interest rate for the Credit Facility was 4.25%. As of September 30, 2020 and December 31, 2019, the outstanding balances on the Credit Facility were $40 million and $24 million, respectively, which approximate 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. Term Loan from Affiliate On July 21, 2020, the Partnership, as borrower, entered into a loan agreement with GKDML, LLC (“GKDML”), which provides for an unsecured, one-year To provide the proceeds for the Term Loan, GKDML entered into a loan agreement with Bank of America, N.A. on July 21, 2020 (“GKDML Loan”). The GKDML Loan has substantially the same terms as the Term Loan and is personally guaranteed by Messrs. Knight and McKenney. GKDML, Mr. Knight and Mr. McKenney have not and will not receive any consideration for providing the Term Loan or guaranty to the GKDML Loan; however, under the Term Loan, the Partnership is required to reimburse GKDML for all costs of the GKDML Loan. The Term Loan may be prepaid at any time with no penalty and in any amount, but any amounts repaid may not be reborrowed. |
Asset Retirement Obligations
Asset Retirement Obligations | 9 Months Ended |
Sep. 30, 2020 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset Retirement Obligation Disclosure [Text Block] | Note 5. Asset Retirement Obligations The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement costs in oil and natural gas properties in the period in which the asset retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance. The changes in the aggregate ARO are as follows: 2020 2019 Balance at January 1 $ 1,452,734 $ 1,294,067 Well additions 35,646 73,096 Accretion 61,547 52,482 Revisions - - Balance at September 30 $ 1,549,927 $ 1,419,645 |
Fair Value of Financial Instrum
Fair Value of Financial Instruments | 9 Months Ended |
Sep. 30, 2020 | |
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, 2020 and 2019, 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, 2020 and December 31, 2019. Fair Value Measurements at September 30, 2020 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current assets $ - $ 66,299 $ - Total $ - $ 66,299 $ - Fair Value Measurements at December 31, 2019 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current liabilities $ - $ (183,850 ) $ - Total $ - $ (183,850 ) $ - 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 Other current assets at September 30, 2020 and Accounts payable, accrued expenses and other current liabilities at December 31, 2019. See additional detail in Note 7. Risk Management. Fair Value of Other Financial Instruments The carrying value of the Partnership’s other financial instruments, including cash and cash equivalents, oil, natural gas and natural gas liquids revenue receivable, accounts payable and accrued expenses, reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments. |
Risk Management
Risk Management | 9 Months Ended |
Sep. 30, 2020 | |
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. Periodically, the Partnership utilizes derivative contracts to manage the commodity price risk on the Partnership’s future oil production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations. The Partnership settled three derivative contracts during the first quarter of 2020, and in accordance with the Letter Agreement discussed in Note 4. Debt, the Partnership is required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 31, 2020 until the next borrowing base redetermination date (first quarter of 2021). In August 2020, the Partnership established its risk management program by entering into costless collar derivative contracts for future oil and natural gas produced by the Sanish Field Assets during the period from August 2020 through February 2021. All derivative instruments are recorded on the Partnership’s balance sheet as assets or liabilities measured at fair value. As of September 30, 2020, the Partnership’s derivative instruments with its counterparty were in a gain position; therefore, a current asset of approximately $66,000, which approximates its fair value, has been recognized as a derivative asset in Other current assets on the Partnership’s consolidated balance sheet as of September 30, 2020. As of December 31, 2019, the Partnership’s derivative instruments were in a loss position; therefore, a current liability of approximately $0.2 million, which approximates fair value, was recognized in Accounts payable, accrued expenses and other current liabilities on the Partnership’s consolidated balance sheet. The Partnership determined 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 performed 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 considered that the counterparty is of substantial credit quality and had 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 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 following table presents settlements of matured derivative instruments and non-cash gains on open derivative instruments for the periods presented. Settlements on matured derivatives below reflect realized gains on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash) gains 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 $ 28,000 $ - $ 285,040 $ - Gain on mark-to-market of derivatives 66,299 498,790 250,149 498,790 Gain on derivatives $ 94,299 $ 498,790 $ 535,189 $ 498,790 The Partnership generally uses costless collar derivative contracts, which establish floor and ceiling prices on future anticipated production. The Partnership did not pay or receive a premium related to the costless collars, and the contracts are settled monthly. The following table reflects the open costless collar derivative instruments as of September 30, 2020. Settlement Period Basis Product Volume Floor / Ceiling Prices ($) Fair Value of Asset / (Liability) at 10/2020 - 02/2021 NYMEX Oil (bbls) 75,000 37.50 / 44.50 $ 24,000 10/2020 - 02/2021 NYMEX Oil (bbls) 75,000 38.00 / 44.25 $ 28,350 10/2020 - 02/2021 NYMEX Oil (bbls) 75,000 38.00 / 44.00 $ 22,500 10/2020 - 02/2021 NYMEX Oil (bbls) 48,000 38.00 / 44.50 $ 22,320 10/2020 - 02/2021 Henry Hub Gas (MMBtu) 320,000 2.50 / 3.05 $ (30,871 ) $ 66,299 The Partnership’s outstanding derivative instruments are covered by an International Swap Dealers Association Master Agreement (“ISDA”) entered into with the counterparty. The ISDA may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately. The Partnership has netting arrangements with the counterparty that provide for offsetting payables against receivables from separate derivative instruments. |
Capital Contribution and Partne
Capital Contribution and Partners' Equity | 9 Months Ended |
Sep. 30, 2020 | |
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%). In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to recent market volatility and the impact on the Partnership’s operating cash flows. The Partnership will accumulate unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are required to be paid before final Payout occurs, as defined above. As of September 30, 2020, the unpaid Payout Accrual totaled $0.828493 per common unit, or approximately $16 million. As discussed in Note 4. Debt and pursuant to the Letter Agreement, the Partnership is not permitted to pay distributions without lender approval. For the nine months ended September 30, 2020, the Partnership paid distributions of $0.241644, or $4.6 million. 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. |
Related Parties
Related Parties | 9 Months Ended |
Sep. 30, 2020 | |
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, including approving the loan discussed below. As described in Note 4. Debt, in July 2020, the Partnership entered into a loan agreement with GKDML, which provided for a $15 million unsecured, one-year For the three and nine months ended September 30, 2020, approximately $101,000 and $291,000 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, 2020, approximately $101,000 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, 2019, approximately $88,000 and $236,000 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 Mr. Knight, Mr. McKenney, Anthony F. Keating, III, Co-Chief Operating Officer and Michael J. Mallick, Co-Chief Operating Officer. Messrs. Knight and 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 six months ended June 30, 2020 and 2019, the Partnership paid $25,611 and $51,222 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, 2020, approximately $64,000 and $204,000, 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, 2020, the approximately $64,000 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, 2019, approximately $65,000 and $200,000, respectively, of expenses subject to the cost sharing agreement were paid by the Partnership and have been reimbursed by ER12. |
Subsequent Events
Subsequent Events | 9 Months Ended |
Sep. 30, 2020 | |
Subsequent Events [Abstract] | |
Subsequent Events [Text Block] | Note 10. Subsequent Events In October 2020, ER12 provided 60-day written notice to the Partnership of ER12’s intention to terminate the cost sharing agreement between the Partnership and ER12. The cost sharing agreement will terminate on December 31, 2020. |
Accounting Policies, by Policy
Accounting Policies, by Policy (Policies) | 9 Months Ended |
Sep. 30, 2020 | |
Accounting Policies [Abstract] | |
Basis of Accounting, Policy [Policy Text Block] | Basis of Presentation The accompanying unaudited financial statements have been prepared in accordance with the instructions for Article 10 of SEC Regulation S-X. Accordingly, they do not include all of the information required by generally accepted accounting principles (“GAAP”) in the United States. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. These unaudited financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements included in its 2019 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 2020 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2020. |
Use of Estimates, Policy [Policy Text Block] | Use of Estimates The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates. |
Revenue [Policy Text Block] | Revenue Recognition The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Oil, natural gas and natural gas liquids revenue receivable in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required. 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. |
Earnings Per Share, Policy [Policy Text Block] | Net Income (Loss) Per Common Unit Basic net income (loss) per common unit is computed as net income (loss) divided by the weighted average number of common units outstanding during the period. Diluted net income (loss) 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, 2020 and 2019. As a result, basic and diluted outstanding common units were the same. The Class B units and Incentive Distribution Rights, as defined below, are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 8) will occur. |
New Accounting Pronouncements, Policy [Policy Text Block] | Recently Adopted Accounting Standards In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-04, Reference Rate Reform (Topic 848), which provides optional guidance through December 31, 2022 to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments in ASU No. 2020-04 apply to contract modifications that replace a reference rate affected by reference rate reform, providing optional expedients regarding the measurement of hedge effectiveness in hedging relationships that have been modified to replace a reference rate. While the guidance in ASU No. 2020-04 became effective upon issuance, the provisions of the ASU did not have a material impact on the Partnership’s consolidated financial statements and related disclosures as of September 30, 2020. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 9 Months Ended |
Sep. 30, 2020 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule of Asset Retirement Obligations [Table Text Block] | The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement costs in oil and natural gas properties in the period in which the asset retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance. The changes in the aggregate ARO are as follows: 2020 2019 Balance at January 1 $ 1,452,734 $ 1,294,067 Well additions 35,646 73,096 Accretion 61,547 52,482 Revisions - - Balance at September 30 $ 1,549,927 $ 1,419,645 |
Fair Value of Financial Instr_2
Fair Value of Financial Instruments (Tables) | 6 Months Ended |
Jun. 30, 2020 | |
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, 2020 and December 31, 2019. Fair Value Measurements at September 30, 2020 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current assets $ - $ 66,299 $ - Total $ - $ 66,299 $ - Fair Value Measurements at December 31, 2019 Quoted Prices in Significant Other Observable Inputs Significant Unobservable Inputs Commodity derivatives - current liabilities $ - $ (183,850 ) $ - Total $ - $ (183,850 ) $ - |
Risk Management (Tables)
Risk Management (Tables) | 9 Months Ended |
Sep. 30, 2020 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | 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 following table presents settlements of matured derivative instruments and non-cash gains on open derivative instruments for the periods presented. Settlements on matured derivatives below reflect realized gains on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash) gains 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 $ 28,000 $ - $ 285,040 $ - Gain on mark-to-market of derivatives 66,299 498,790 250,149 498,790 Gain on derivatives $ 94,299 $ 498,790 $ 535,189 $ 498,790 |
Schedule of Derivative Instruments [Table Text Block] | The Partnership generally uses costless collar derivative contracts, which establish floor and ceiling prices on future anticipated production. The Partnership did not pay or receive a premium related to the costless collars, and the contracts are settled monthly. The following table reflects the open costless collar derivative instruments as of September 30, 2020. Settlement Period Basis Product Volume Floor / Ceiling Prices ($) Fair Value of Asset / (Liability) at 10/2020 - 02/2021 NYMEX Oil (bbls) 75,000 37.50 / 44.50 $ 24,000 10/2020 - 02/2021 NYMEX Oil (bbls) 75,000 38.00 / 44.25 $ 28,350 10/2020 - 02/2021 NYMEX Oil (bbls) 75,000 38.00 / 44.00 $ 22,500 10/2020 - 02/2021 NYMEX Oil (bbls) 48,000 38.00 / 44.50 $ 22,320 10/2020 - 02/2021 Henry Hub Gas (MMBtu) 320,000 2.50 / 3.05 $ (30,871 ) $ 66,299 |
Partnership Organization (Detai
Partnership Organization (Details) shares in Millions | Jul. 09, 2013USD ($) | Oct. 31, 2020USD ($) | Jul. 31, 2020USD ($) | Sep. 30, 2020USD ($) | Dec. 31, 2019 | Sep. 30, 2020USD ($) | Dec. 31, 2019USD ($) | Apr. 24, 2017USD ($)shares | Jun. 30, 2020USD ($) | Nov. 21, 2017USD ($) |
Partnership Organization (Details) [Line Items] | ||||||||||
Limited Liability Company or Limited Partnership, Business, Formation State | Delaware | |||||||||
Partners' Capital Account, Contributions | $ 1,000 | |||||||||
Sanish Field Located in Mountrail County, North Dakota [Member] | ||||||||||
Partnership Organization (Details) [Line Items] | ||||||||||
Capital Expenditures, Drilling and Completion of Wells | $ 63,000,000 | $ 7,800,000 | ||||||||
Costs Incurred, Development Costs | $ 42,000,000 | |||||||||
Non-operated Completed Wells [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | ||||||||||
Partnership Organization (Details) [Line Items] | ||||||||||
Gas and Oil Area Developed, Net | 25.00% | |||||||||
Oil, Productive Well, Number of Wells, Net | 243 | 243 | ||||||||
Non-operated Wells in the Process of Drilling [Member] | ||||||||||
Partnership Organization (Details) [Line Items] | ||||||||||
Oil and Gas, Present Activity, Well in Process of Drilling | 21 | 21 | ||||||||
Non-operated Wells in the Process of Drilling [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | ||||||||||
Partnership Organization (Details) [Line Items] | ||||||||||
Gas and Oil Area Developed, Net | 18.00% | |||||||||
Oil and Gas, Present Activity, Well in Process of Drilling | 21 | 21 | ||||||||
Whiting Petroleum [Member] | ||||||||||
Partnership Organization (Details) [Line Items] | ||||||||||
Amounts Outstanding to Operator | $ 19,000,000 | $ 20,000,000 | ||||||||
Debt Instrument, Term | 1 year | |||||||||
Subsequent Event [Member] | ||||||||||
Partnership Organization (Details) [Line Items] | ||||||||||
Repayments of Related Party Debt | $ 5,000,000 | |||||||||
Debt, Current | $ 50,000,000 | |||||||||
Revolving Credit Facility [Member] | ||||||||||
Partnership Organization (Details) [Line Items] | ||||||||||
Line of Credit Facility, Remaining Borrowing Capacity | $ 40,000,000 | $ 40,000,000 | ||||||||
Debt Instrument, Face Amount | $ 20,000,000 | |||||||||
Best-Efforts Offering [Member] | ||||||||||
Partnership Organization (Details) [Line Items] | ||||||||||
Partners' Capital Account, Units, Sale of Units (in Shares) | shares | 19 | |||||||||
Proceeds from Issuance of Common Limited Partners Units | $ 374,200,000 | |||||||||
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units | $ 349,600,000 | |||||||||
GKDML [Member] | ||||||||||
Partnership Organization (Details) [Line Items] | ||||||||||
Debt Instrument, Term | 1 year | |||||||||
Debt Instrument, Face Amount | $ 15,000,000 | |||||||||
Sanish Field Located in Mountrail County, North Dakota [Member] | ||||||||||
Partnership Organization (Details) [Line Items] | ||||||||||
Wells Elected to Participate in Drilling | 43 | 43 | ||||||||
Capital Expenditures, Drilling and Completion of Wells | $ 63,000,000 | |||||||||
Costs Incurred, Development Costs | $ 42,000,000 |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Details) - shares | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Accounting Policies [Abstract] | ||||
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount | 0 | 0 | 0 | 0 |
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 ($) | Sep. 30, 2020USD ($) | Dec. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2020USD ($) | Dec. 31, 2019USD ($) |
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 | ||||||||
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars) | $ 63 | $ 7.8 | |||||||
Costs Incurred, Development Costs (in Dollars) | 42 | ||||||||
Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars) | 1 | ||||||||
Sanish Field Located in Mountrail County, North Dakota [Member] | Maximum [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars) | $ 2 | ||||||||
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) | $ 159.6 | ||||||||
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) | $ 128.5 | ||||||||
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) | $ 52.4 | ||||||||
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] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars) | $ 63 | ||||||||
Wells Elected to Participate in Drilling | 43 | 43 | |||||||
Costs Incurred, Development Costs (in Dollars) | $ 42 | ||||||||
Whiting Petroleum [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Oil and Gas, Development Well Drilled, Net Productive, Number | 2 | ||||||||
Whiting Petroleum [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | |||||||||
Oil and 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% | ||||||||
Non-operated Completed Wells [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Oil and Gas, Development Well Drilled, Net Productive, Number | 22 | ||||||||
Working Interest | 23.00% | 23.00% | |||||||
Non-operated Completed Wells [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Gas and Oil Area Developed, Net | 25.00% | ||||||||
Oil, Productive Well, Number of Wells, Net | 243 | 243 | |||||||
Non-operated Wells in the Process of Drilling [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Working Interest | 18.00% | 18.00% | |||||||
Oil and Gas, Present Activity, Well in Process of Drilling | 21 | 21 | |||||||
Non-operated Wells in the Process of Drilling [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | |||||||||
Oil and Natural Gas Investments (Details) [Line Items] | |||||||||
Gas and Oil Area Developed, Net | 18.00% | ||||||||
Oil and Gas, Present Activity, Well in Process of Drilling | 21 | 21 |
Debt (Details)
Debt (Details) - USD ($) | Jul. 21, 2020 | Sep. 30, 2019 | Nov. 21, 2017 | Jul. 31, 2020 | Sep. 30, 2020 | Dec. 31, 2019 |
Debt (Details) [Line Items] | ||||||
Long-term Line of Credit | $ 0 | $ 24,000,000 | ||||
Line of Credit Facility, Fair Value of Amount Outstanding | 40,000,000 | 24,000,000 | ||||
Notes Payable, Related Parties, Current | $ 15,000,000 | $ 0 | ||||
Revolving Credit Facility [Member] | ||||||
Debt (Details) [Line Items] | ||||||
Debt Instrument, Face Amount | $ 20,000,000 | |||||
Debt Instrument, Maturity Date | Nov. 21, 2019 | |||||
Line of Credit Facility, Commitment Fee Description | the Partnership paid an origination fee of 0.45% on the change in Revolver Commitment Amount of the Credit Facility (increase from $20 million on previous credit facility to $40 million under revised Credit Facility, or $20 million), or $90,000 | |||||
Line of Credit Facility, Commitment Fee Percentage | 0.45% | |||||
Line of Credit Facility, Commitment Fee Amount | $ 90,000 | |||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.50% | |||||
Line of Credit Facility, Covenant Terms | The Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants, each as defined in the Amended Loan Agreement, include: ● A maximum ratio of funded debt to trailing 12-month EBITDAX of 3.50 to 1.00 ● A minimum ratio of current assets to current liabilities of 1.00 to 1.00 (“Current Ratio”) ● A minimum ratio of EBITDAX to cash interest expense of 2.50 to 1.00 for trailing 12-month period | |||||
Line of Credit Facility, Covenant Compliance | The Partnership was in compliance with its applicable covenants at September 30, 2020 | |||||
Long-term Line of Credit | $ 40,000,000 | |||||
Long-term Debt, Percentage Bearing Variable Interest, Percentage Rate | 4.25% | |||||
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 | 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 | |||||
Credit Facility, Letter Agreement | On July 21, 2020, the Partnership entered into a letter agreement (“Letter Agreement”) with Lender that amended and modified the Amended Loan Agreement. The modifications to the Amended Loan Agreement include, among other items, the following: - Maturity date was changed from September 30, 2022 to July 31, 2021; - Interest rate was changed to the prime rate plus 1.00%, with an interest rate floor of 4.00% (an increase of 50 basis points from the rate prior to the Letter Agreement); - Any future Partnership distributions to limited partners require Lender approval; - Calculation of the current ratio covenant was suspended until the reporting date of September 30, 2020; - The definition of current ratio excludes the Affiliate Loan (discussed below) from the definition of liabilities; and - As additional collateral for the loan, the Partnership established and funded a bank account with Lender in the amount of $1.6 million, to be used for interest payments under the Amended Loan Agreement until maturity (the balance of this collateral bank account at September 30, 2020 was approximately $1.3 million and is included in Restricted cash and cash equivalents on the Partnership’s September 30, 2020 consolidated balance sheet). | |||||
Debt Instrument, Collateral Amount | $ 1,600,000 | |||||
Restricted Cash, Current | $ 1,300,000 | |||||
Debt, Risk Management, Description | Also, under the Letter Agreement, the Partnership is required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and natural gas sales. The risk management program must cover at least 80% of the Partnership’s projected total production of oil and natural gas for the period from August 31, 2020 until the next borrowing base redetermination date (first quarter of 2021) | |||||
Debt Instrument, Fee Amount | $ 40,000 | |||||
Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Amended Loan Agreement [Member] | Minimum [Member] | ||||||
Debt (Details) [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 2.50% | |||||
Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member] | Amended Loan Agreement [Member] | Maximum [Member] | ||||||
Debt (Details) [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 3.50% | |||||
Revolving Credit Facility [Member] | Prime Rate [Member] | Amended Loan Agreement [Member] | ||||||
Debt (Details) [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | |||||
Revolving Credit Facility [Member] | Prime Rate [Member] | Amended Loan Agreement [Member] | Minimum [Member] | ||||||
Debt (Details) [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 4.00% | |||||
Revolving Credit Facility [Member] | Amendment Fee, Due September 30, 2020 [Member] | Amended Loan Agreement [Member] | ||||||
Debt (Details) [Line Items] | ||||||
Debt Instrument, Fee Amount | $ 15,000 | |||||
Revolving Credit Facility [Member] | Amendment Fee, Due December 31, 2020 [Member] | Amended Loan Agreement [Member] | ||||||
Debt (Details) [Line Items] | ||||||
Debt Instrument, Fee Amount | $ 25,000 | |||||
GKDML [Member] | ||||||
Debt (Details) [Line Items] | ||||||
Debt Instrument, Face Amount | $ 15,000,000 | |||||
Debt Instrument, Term | 1 year | |||||
Notes Payable, Related Parties, Current | $ 15,000,000 | |||||
Short-term Debt, Weighted Average Interest Rate, at Point in Time | 2.20% | |||||
GKDML [Member] | London Interbank Offered Rate (LIBOR) [Member] | ||||||
Debt (Details) [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 2.00% | |||||
GKDML [Member] | London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member] | ||||||
Debt (Details) [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 0.00% |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations - USD ($) | 9 Months Ended | |
Sep. 30, 2020 | Sep. 30, 2019 | |
Schedule of Asset Retirement Obligations [Abstract] | ||
Balance | $ 1,452,734 | $ 1,294,067 |
Well additions | 35,646 | 73,096 |
Accretion | 61,547 | 52,482 |
Revisions | 0 | 0 |
Balance | $ 1,549,927 | $ 1,419,645 |
Fair Value of Financial Instr_3
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis - USD ($) | Sep. 30, 2020 | Dec. 31, 2019 |
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 | |
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 | 66,299 | |
Total | 66,299 | |
Commodity derivatives - current liabilities | (183,850) | |
Total | (183,850) | |
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 | |
Commodity derivatives - current liabilities | 0 | |
Total | $ 0 |
Risk Management (Details)
Risk Management (Details) | 9 Months Ended | |
Sep. 30, 2020USD ($) | Dec. 31, 2019USD ($) | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||
Discussion of Price Risk Derivative Risk Management Policy | The Partnership settled three derivative contracts during the first quarter of 2020, and in accordance with the Letter Agreement discussed in Note 4. Debt, the Partnership is required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 31, 2020 until the next borrowing base redetermination date (first quarter of 2021). | |
Number of Price Risk Derivatives Held | 3 | |
Derivative Asset, Current | $ 66,000 | |
Derivative Liability, Current | $ 200,000 |
Risk Management (Details) - Sch
Risk Management (Details) - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value - Price Risk Derivative [Member] - USD ($) | 3 Months Ended | 9 Months Ended | ||
Sep. 30, 2020 | Sep. 30, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | |
Derivatives, Fair Value [Line Items] | ||||
Settlements on matured derivatives | $ 28,000 | $ 0 | $ 285,040 | $ 0 |
Gain on mark-to-market of derivatives | 66,299 | 498,790 | 250,149 | 498,790 |
Gain on derivatives | $ 94,299 | $ 498,790 | $ 535,189 | $ 498,790 |
Risk Management (Details) - S_2
Risk Management (Details) - Schedule of Derivative Instruments | 9 Months Ended |
Sep. 30, 2020USD ($)$ / itembbl | |
Derivative [Line Items] | |
Fair Value of Asset / (Liability) | $ | $ 66,299 |
Costless Collar Agreements #1 [Member] | Price Risk Derivative [Member] | |
Derivative [Line Items] | |
Basis | NYMEX |
Product | Oil (bbls) |
Volume | bbl | 75,000 |
Floor Prices | 37.50 |
Ceiling Prices | 44.50 |
Fair Value of Asset / (Liability) | $ | $ 24,000 |
Costless Collar Agreements #2 [Member] | Price Risk Derivative [Member] | |
Derivative [Line Items] | |
Basis | NYMEX |
Product | Oil (bbls) |
Volume | bbl | 75,000 |
Floor Prices | 38 |
Ceiling Prices | 44.25 |
Fair Value of Asset / (Liability) | $ | $ 28,350 |
Costless Collar Agreements #3 [Member] | Price Risk Derivative [Member] | |
Derivative [Line Items] | |
Basis | NYMEX |
Product | Oil (bbls) |
Volume | bbl | 75,000 |
Floor Prices | 38 |
Ceiling Prices | 44 |
Fair Value of Asset / (Liability) | $ | $ 22,500 |
Costless Collar Agreements #4 [Member] | Price Risk Derivative [Member] | |
Derivative [Line Items] | |
Basis | NYMEX |
Product | Oil (bbls) |
Volume | bbl | 48,000 |
Floor Prices | 38 |
Ceiling Prices | 44.50 |
Fair Value of Asset / (Liability) | $ | $ 22,320 |
Costless Collar Agreements #5 [Member] | Price Risk Derivative [Member] | |
Derivative [Line Items] | |
Basis | Henry Hub |
Product | Gas (MMBtu) |
Volume | bbl | 320,000 |
Floor Prices | 2.50 |
Ceiling Prices | 3.05 |
Fair Value of Asset / (Liability) | $ | $ (30,871) |
Capital Contribution and Part_2
Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions | Jul. 09, 2013 | Mar. 31, 2020 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Sep. 30, 2020 | Sep. 30, 2019 | Apr. 24, 2017 |
Capital Contribution and Partners' Equity (Details) [Line Items] | ||||||||
Partners' Capital Account, Contributions | $ 1,000 | |||||||
Distributions to organizational limited partner | $ 990 | |||||||
Partners' Capital Account, Description of Units Sold | Under the agreement with David Lerner Associates, Inc. (the “Dealer Manager”), the Dealer Manager received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager will also be paid a contingent incentive fee, which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold based on the performance of the Partnership. | |||||||
Managing Dealer, Selling Commissions, Percentage | 6.00% | |||||||
Managing Dealer, Maximum Contingent Incentive Fee on Gross Proceeds, Percentage | 4.00% | |||||||
Maximum Contingent Offering Costs, Selling Commissions and Marketing Expenses | $ 15,000,000 | |||||||
Key Provisions of Operating or Partnership Agreement, Description | The Partnership Agreement provides that Payout occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per unit, regardless of the amount paid for the unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount. All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows: ● First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement; ● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%). | |||||||
Annualized Rate of Retun | 7.00% | |||||||
Distribution at Payout to limited partner, per common unit (in Dollars per share) | $ 0.828493 | |||||||
Distribution at Payout to limited partner | $ 16,000,000 | |||||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share) | $ 0.349041 | $ 0.241644 | $ 1.047123 | |||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 4,584,826 | $ 6,622,520 | $ 6,622,521 | $ 6,622,520 | $ 4,584,826 | $ 19,867,561 | ||
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 ($) | 1 Months Ended | 3 Months Ended | 6 Months Ended | 9 Months Ended | |||
Jul. 31, 2020 | Sep. 30, 2020 | Jun. 30, 2020 | Sep. 30, 2019 | Jun. 30, 2020 | Sep. 30, 2020 | Sep. 30, 2019 | |
GKDML [Member] | |||||||
Related Parties (Details) [Line Items] | |||||||
Debt Instrument, Face Amount | $ 15,000,000 | ||||||
Debt Instrument, Term | 1 year | ||||||
General Partner [Member] | |||||||
Related Parties (Details) [Line Items] | |||||||
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party | $ 101,000 | $ 88,000 | $ 291,000 | $ 236,000 | |||
Due to Related Parties, Current | 101,000 | 101,000 | |||||
Affiliated Entity [Member] | |||||||
Related Parties (Details) [Line Items] | |||||||
Operating Leases, Rent Expense | $ 25,611 | $ 51,222 | |||||
Operating Leases, Rent Expense, Minimum Rentals | $ 8,537 | ||||||
Reimbursements From Related Party | 64,000 | $ 65,000 | 204,000 | $ 200,000 | |||
Due from Related Parties | $ 64,000 | $ 64,000 |