Document And Entity Information
Document And Entity Information - shares | 3 Months Ended | |
Mar. 31, 2021 | May 17, 2021 | |
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 | Mar. 31, 2021 | |
Document Fiscal Year Focus | 2021 | |
Document Fiscal Period Focus | Q1 | |
Entity Small Business | true | |
Entity Emerging Growth Company | false | |
Entity Shell Company | false | |
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 ($) | Mar. 31, 2021 | Dec. 31, 2020 |
Assets | ||
Cash and cash equivalents | $ 866,453 | $ 1,608,301 |
Restricted cash and cash equivalents | 431,087 | 855,518 |
Accounts receivable | 7,967,911 | 5,890,971 |
Other current assets | 166,691 | 257,524 |
Total Current Assets | 9,432,142 | 8,612,314 |
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $80,631,735 and $75,765,289, respectively | 320,658,701 | 323,200,183 |
Total Assets | 330,090,843 | 331,812,497 |
Liabilities | ||
Revolving credit facility | 40,000,000 | 40,000,000 |
Affiliate term loan | 0 | 6,000,000 |
Accounts payable and accrued expenses | 4,696,476 | 3,299,810 |
Derivative liability | 0 | 602,760 |
Total Current Liabilities | 44,696,476 | 49,902,570 |
Asset retirement obligations | 1,585,076 | 1,564,105 |
Total Liabilities | 46,281,552 | 51,466,675 |
Partners’ Equity | ||
Limited partners' interest (18,973,474 common units issued and outstanding, respectively) | 283,811,018 | 280,347,549 |
General partner's interest | (1,727) | (1,727) |
Class B Units (62,500 units issued and outstanding, respectively) | 0 | 0 |
Total Partners’ Equity | 283,809,291 | 280,345,822 |
Total Liabilities and Partners’ Equity | $ 330,090,843 | $ 331,812,497 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parentheticals) - USD ($) | Mar. 31, 2021 | Dec. 31, 2020 |
Statement of Financial Position [Abstract] | ||
Oil and natural gas properties, accumulated depreciation, depletion and amortization (in Dollars) | $ 80,631,735 | $ 75,765,289 |
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 | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Revenues | ||
Oil | $ 10,601,937 | $ 10,229,733 |
Natural gas | 1,478,760 | 354,574 |
Natural gas liquids | 1,523,379 | 519,227 |
Total revenue | 13,604,076 | 11,103,534 |
Operating costs and expenses | ||
Production expenses | 2,656,077 | 2,052,237 |
Production taxes | 1,001,952 | 992,341 |
General and administrative expenses | 531,298 | 565,297 |
Depreciation, depletion, amortization and accretion | 4,887,417 | 4,564,861 |
Total operating costs and expenses | 9,076,744 | 8,174,736 |
Operating income | 4,527,332 | 2,928,798 |
Gain (loss) on derivatives, net | (579,660) | 440,890 |
Interest expense, net | (484,203) | (436,261) |
Total other expense, net | (1,063,863) | 4,629 |
Net income | $ 3,463,469 | $ 2,933,427 |
Basic and diluted net income per common unit (in Dollars per share) | $ 0.18 | $ 0.15 |
Weighted average common units outstanding - basic and diluted (in Shares) | 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, 2019 | $ 287,735,971 | $ 287,737,698 | $ (1,727) | |
Balance (in Shares) at Dec. 31, 2019 | 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, 2020 | $ 280,345,822 | $ 280,347,549 | (1,727) | |
Balance (in Shares) at Dec. 31, 2020 | 18,973,474 | 18,973,474 | 62,500 | |
Distributions declared and paid to common units | $ 0 | |||
Net income (loss) | 3,463,469 | $ 3,463,469 | ||
Balance at Mar. 31, 2021 | $ 283,809,291 | $ 283,811,018 | $ (1,727) | |
Balance (in Shares) at Mar. 31, 2021 | 18,973,474 | 18,973,474 | 62,500 |
Consolidated Statements of Pa_2
Consolidated Statements of Partners' Equity (Parentheticals) | 3 Months Ended |
Mar. 31, 2020$ / shares | |
Capital Unit, Class B [Member] | Member Units [Member] | |
Distributions declared and paid to common units, per unit | $ 0.241644 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Cash flow from operating activities: | ||
Net income | $ 3,463,469 | $ 2,933,427 |
Adjustments to reconcile net income to cash from operating activities: | ||
Depreciation, depletion, amortization and accretion | 4,887,417 | 4,564,861 |
(Gain) / loss on mark-to-market of derivatives | (602,760) | (183,850) |
Non-cash expenses, net | 46,406 | 10,164 |
Changes in operating assets and liabilities: | ||
Oil, natural gas and natural gas liquids revenue receivable | (2,076,940) | (3,430,205) |
Other current assets | 44,427 | 52,762 |
Accounts payable and accrued expenses | (116,638) | 289,117 |
Net cash flow provided by operating activities | 5,645,381 | 4,236,276 |
Cash flow from investing activities: | ||
Additions to oil and natural gas properties | (811,660) | (13,290,884) |
Net cash flow used in investing activities | (811,660) | (13,290,884) |
Cash flow from financing activities: | ||
Proceeds from revolving credit facility | 0 | 16,000,000 |
Payments on affiliate term loan | (6,000,000) | 0 |
Distributions paid to limited partners | 0 | (4,584,826) |
Net cash flow (used in) provided by financing activities | (6,000,000) | 11,415,174 |
Decrease in cash and cash equivalents | (1,166,279) | 2,360,566 |
Cash and cash equivalents, beginning of period | 2,463,819 | 348,550 |
Cash and cash equivalents, end of period | 1,297,540 | 2,709,116 |
Interest paid | 447,886 | 441,591 |
Supplemental non-cash information: | ||
Accrued capital expenditures related to additions to oil and natural gas properties | $ 3,045,132 | $ 20,547,754 |
Partnership Organization
Partnership Organization | 3 Months Ended |
Mar. 31, 2021 | |
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 March 31, 2021, the Partnership owned an approximate 25% non-operated working interest in 243 producing wells, an estimated approximate 17% non-operated working interest in 24 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) operates substantially all of the Sanish Field Assets. The general partner of the Partnership is Energy 11 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership. The Partnership’s fiscal year ends on December 31. 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 (“Drilling Program”), primarily administered by Whiting, at an estimated cost of approximately $60 million to the Partnership. Production from additional wells to be completed under the Drilling Program 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 the Drilling Program, the outbreak of a novel coronavirus (“COVID-19”) in China in December 2019 significantly impacted the global economy throughout 2020, and the domestic oil and gas industry was especially impacted as demand for oil, natural gas and other hydrocarbons substantially declined in March and April 2020. In addition to the outbreak of COVID-19, Saudi Arabia and Russia, two of the largest worldwide producers of crude oil, engaged in a price war during March and April 2020 that ultimately led to excess crude oil and natural gas inventory and congested supply chain channels, which weighed negatively on commodity prices while demand was low. Demand for oil and natural gas began to return in the fourth quarter of 2020 and first quarter of 2021 as government-mandated COVID-19 restrictions have eased. In addition, oil prices increased to over $60 per barrel throughout March 2021, marking an over 50% increase over the average price per barrel in 2020. Increased demand and higher commodity prices have improved the outlook for the domestic oil and natural gas industry in 2021, but significant uncertainty remains as to when Whiting will fully resume the Drilling Program, which the Partnership anticipates will have a positive impact to its revenues and operating results. As of March 31, 2021, the Partnership has used all its availability under its $40 million revolving credit facility (“Credit Facility”), and the maturity date of the Credit Facility is July 31, 2021. If the lenders were to enforce the obligations outstanding under the Credit Facility when they become due, the Partnership would be required to pay approximately $40 million (as of March 31, 2021) to the lenders at maturity. The Partnership’s ability to continue as a going concern is primarily dependent on the refinancing the Partnership’s existing debt and/or securing additional capital as well as the Partnership’s ability to continue to comply with its obligations under its existing loan agreements. In May 2021, the Partnership entered into a loan agreement with a bank syndicate led by BancFirst, which provides for a $60 million revolving credit facility that matures on March 1, 2024. The Partnership used proceeds from the new revolving credit facility to repay the existing Credit Facility in full. Refer to Note 9. Subsequent Events for more information about the Partnership’s new credit facility. Therefore, based on the successful refinancing of the Partnership’s debt along with the Partnership’s performance during the first quarter of 2021, substantial doubt no longer exists for the Partnership to continue as a going concern for one year after the date these financial statements are issued. |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 3 Months Ended |
Mar. 31, 2021 | |
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 2020 Annual Report on Form 10-K. Operating results for the three months ended March 31, 2021 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2021. 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 Accounts 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. Fair Value of Other Financial Instruments The carrying value of the Partnership’s other financial instruments, including cash and cash equivalents, accounts 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. Net Income Per Common Unit Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three months ended March 31, 2021 and 2020. 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 7) will occur. |
Oil and Gas Investments
Oil and Gas Investments | 3 Months Ended |
Mar. 31, 2021 | |
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. 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 March 31, 2021; 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 March 31, 2021. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 43 wells is approximately $60 million, of which approximately $43 million was incurred as of March 31, 2021. Whiting suspended the 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 timing for completion of a portion or all of the in-process wells within the Drilling Program is dependent upon several factors, including available capital. The Partnership estimates it may incur approximately $10 to $15 million in capital expenditures, if Whiting is successfully able to fully resume its Drilling Program, in 2021. However, market conditions and the uncertainty of when Whiting will fully resume the Drilling Program make it difficult to predict the amount and timing of capital expenditures for the remainder of 2021, and estimated capital expenditures could be significantly different from amounts actually invested. During the first quarter of 2021, the Partnership elected to participate in the drilling and completion of three new wells proposed by Whiting. The Partnership has an estimated approximate 11% non-operated working interest in these three wells. The wells are anticipated to be completed during the second quarter of 2021. The Partnership’s proportionate share of capital expenditures to complete these wells is approximately $1.9 million, of which approximately $0.3 million was incurred as of March 31, 2021. |
Debt
Debt | 3 Months Ended |
Mar. 31, 2021 | |
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 “2017 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 (“Simmons 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 2017 Loan Agreement (the “Amended Loan Agreement”) with the Lender, which provided for the Simmons 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 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; (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 Simmons Credit Facility, 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 the Lender that amended and modified the Amended Loan Agreement. The modifications to the Amended Loan Agreement included, 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; - 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 March 31, 2021 was approximately $0.4 million and is included in Restricted cash and cash equivalents on the Partnership’s March 31, 2021 consolidated balance sheet). The Simmons Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants 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 The Partnership was in compliance with its applicable covenants at March 31, 2021. At March 31, 2021, the outstanding balance on the Simmons Credit Facility was $40 million, and the interest rate for the Simmons Credit Facility was 4.25%. As of March 31, 2021 and December 31, 2020, the outstanding balance on the Simmons Credit Facility was $40 million, which approximates fair market value. The Partnership estimated the fair value of its Simmons 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 provided 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 was also repaid in March 2021, had substantially the same terms as the Term Loan and was personally guaranteed by Messrs. Knight and McKenney. GKDML, Mr. Knight and Mr. McKenney did not receive any consideration for providing the Term Loan or guaranty to the GKDML Loan; however, under the Term Loan, the Partnership reimbursed GKDML for all costs of the GKDML Loan. |
Asset Retirement Obligations
Asset Retirement Obligations | 3 Months Ended |
Mar. 31, 2021 | |
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: 2021 2020 Balance at January 1 $ 1,564,105 $ 1,452,734 Well additions - 27,844 Accretion 20,971 19,979 Revisions - - Balance at March 31 $ 1,585,076 $ 1,500,557 |
Risk Management
Risk Management | 3 Months Ended |
Mar. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments and Hedging Activities Disclosure [Text Block] | Note 6. 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. In accordance with the Letter Agreement discussed in Note 4. Debt, the Partnership was 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 2020 through February 2021. As of December 31, 2020, the Partnership had two outstanding monthly costless collar derivative contracts, which hedged a total of 105,000 barrels of oil and 120,000 MMBtu of natural gas of January and February 2021 production. The Partnership settled these monthly derivative contracts during the first quarter of 2021 at a loss of approximately $1.2 million. The Partnership also recorded a non-cash gain during the first quarter of 2021, which represents the reversal of the $0.6 million Derivative liability recorded at December 31, 2020 on the Partnership’s consolidated balance sheet. The Partnership did not designate its derivative instruments as hedges for accounting purposes and did not enter 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 had no outstanding contracts at March 31, 2021. The following table presents the settlement gain (loss) of matured derivative instruments and non-cash mark-to-market gains for the periods presented. Three Months Ended Three Months Ended Settlement gains (losses) on matured derivatives $ (1,182,420 ) $ 257,040 Gain on mark-to-market of derivatives 602,760 183,850 Gain (loss) on derivatives, net $ (579,660 ) $ 440,890 Settlements on matured derivatives above reflect realized gains or losses 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 above represent the change in fair value of derivative instruments which were held at period-end. These unrealized gains do not represent actual settlements or payments made to or from the counterparty. |
Capital Contribution and Partne
Capital Contribution and Partners' Equity | 3 Months Ended |
Mar. 31, 2021 | |
Partners' Capital Notes [Abstract] | |
Partners' Capital Notes Disclosure [Text Block] | Note 7. 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 market volatility caused by the COVID-19 pandemic 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 March 31, 2021, the unpaid Payout Accrual totaled $1.526575 per common unit, or approximately $29 million. As discussed in Note 9. Subsequent Events, the Partnership must meet certain conditions under its new revolving credit facility before distributions to limited partners may resume. For the three months ended March 31, 2020, the Partnership paid distributions of $0.241644, or $4.6 million. |
Related Parties
Related Parties | 3 Months Ended |
Mar. 31, 2021 | |
Related Party Transactions [Abstract] | |
Related Party Transactions Disclosure [Text Block] | Note 8. Related Parties 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. Entities owned by Messrs. Keating and Mallick own non-voting, Class B units in the general partner of ER12. The Partnership has, and is expected to continue to engage in, significant transactions with related parties. These transactions cannot be construed to be at arm’s length and the results of the Partnership’s operations may be different than if conducted with non-related parties. The General Partner’s Board of Directors oversees and reviews the Partnership’s related party relationships and is required to approve any significant modifications to any existing related party transactions, as well as any new significant related party transactions. For the three months ended March 31, 2021 and 2020, approximately $32,000 and $92,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At March 31, 2021, approximately $32,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses on the consolidated balance sheets. On January 31, 2018, the Partnership entered into a cost sharing agreement with ER12 that gave ER12 access to the Partnership’s personnel and administrative resources, including accounting, asset management and other day-to-day management support. The cost sharing agreement reduced these accounting and asset management costs to the Partnership, as these shared day-to-day costs were split evenly between the two partnerships. The shared costs were based on actual costs incurred with no mark-up or profit to the Partnership. Any other direct third-party costs were paid by the party receiving the services. For the three months ended March 31, 2020, approximately $76,000 of expenses subject to the cost sharing agreement were incurred by ER12 and have been reimbursed to the Partnership. In October 2020, the cost sharing agreement was terminated by ER12, effective December 31, 2020. On December 1, 2020, the Partnership entered into an Administrative Services Agreement (the “ASA”) with Regional Energy Investors, L.P. d/b/a Regional Energy Management (the “Administrator”) and ER12, whereby the Administrator will provide administrative, operating and professional services necessary and useful to the Partnership. The Administrator will also assist the General Partner with the day-to-day operations of the Partnership. The ASA is effective January 1, 2021, and the Initial Term of the ASA will extend until the earlier of (a) five years or (b) when the Partnership and/or Energy 11 ceases to own its respective oil and natural gas assets. Provided the ASA is not terminated by any party via 60-day written notice at the conclusion of the Initial Term, the ASA will be automatically renewed for additional one-year periods. If a party to the ASA materially breaches the terms and conditions of the ASA and the breach has not been cured with 30 days of written notification of said breach, the ASA may be terminated with immediate effect. Costs and expenses attributable to the services performed by the Administrator under the ASA will be reimbursed by the Partnership. All Administrator costs and expenses will be accumulated (based on actual costs incurred with no mark-up or profit to the Administrator) and approved by the Partnership prior to reimbursement. Costs and expenses to be reimbursed under the ASA may include, but are not limited to, employee wages and benefits, rent for office space and network and information technology support. Other expenses, such as business travel costs and accounting, legal or banking services, may not be incurred by the Administrator on behalf of the Partnership without prior express written consent of the Partnership. For the three months ended March 31, 2021, approximately $141,000 of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator. Under the ASA, the Administrator will also assist Energy Resources 12 GP, LLC, the general partner of ER12 (“ER12’s General Partner”), with the day-to-day operations of ER12. ER12 currently pays ER12’s General Partner an annual management fee of 0.5% of the total gross equity proceeds raised by ER12 in its best-efforts offering. Under the ASA, ER12’s General Partner will pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. This fee is only applicable to ER12 and does not apply to the Partnership. The Administrator is owned by entities that are controlled by Messrs. Keating and Mallick. |
Subsequent Events
Subsequent Events | 3 Months Ended |
Mar. 31, 2021 | |
Subsequent Events [Abstract] | |
Subsequent Events [Text Block] | Note 9. Subsequent Events On May 13, 2021, the Partnership and its wholly-owned subsidiary, as borrowers, entered into a loan agreement (“2021 Loan Agreement”) with BancFirst, as administrative agent for the lenders (the “Lender”), which provides for a revolving credit facility (“Revolving Credit Facility”) with an approved maximum credit amount (“Maximum Credit Amount”) of $60 million, subject to borrowing base restrictions. The Partnership paid an origination fee of 0.50% of the Maximum Credit Amount, or $300,000, and is subject to an additional fee of 0.25% on any incremental increase to the borrowing base. The Partnership is also required to pay an annual fee to the Lender of $30,000, and an unused facility fee of 0.25% on the unused portion of the Revolving Credit Facility, based on borrowings outstanding during a quarter. The maturity date is March 1, 2024. Under the 2021 Loan Agreement, the initial borrowing base is $60 million. The Partnership also is required to make a monthly principal reduction payment (“Monthly Commitment Reduction”), which is initially stipulated to be $1 million. The borrowing base and Monthly Commitment Reduction are subject to redetermination semi-annually, on March 1 and September 1, based upon the Lender’s analysis of the Partnership’s proven oil and natural gas reserves. The Lender is also permitted to cause the borrowing base to be redetermined up to two times during a 12-month period. Outstanding borrowings under the Revolving Credit Facility cannot exceed the lesser of the borrowing base or the Maximum Credit Amount at any time. The interest rate is equal to the Wall Street Journal Prime Rate plus 0.50%, with a floor of 4.00%. At closing, the interest rate for the Revolving Credit Facility was 4.00%. At closing, the Partnership borrowed approximately $40 million. The proceeds were used to pay the $40 million outstanding balance and accrued interest on the Simmons Credit Facility described above. Any further advances under the Revolving Credit Facility are to be used to fund capital expenditures for the development of the Partnership’s undrilled acreage. Under the terms of the 2021 Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The Revolving Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells. The Revolving Credit Facility contains prepayment requirements, customary affirmative and negative covenants and events of default. The financial covenants include a minimum debt service coverage ratio and a minimum current ratio. The 2021 Loan Agreement restricts the Partnership’s ability to pay limited partner distributions until the outstanding balance of the Revolving Credit Facility is equal to or less than 50% of the Maximum Credit Amount, at which point the Partnership is permitted to make distributions so long as the Partnership is in compliance with its debt service coverage ratio and no other event of default has occurred. Also under the 2021 Loan Agreement, the Partnership is required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production. The Partnership must hedge at least 50% of its rolling 12-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is less than 50%, and at least 50% of its rolling 24-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is greater than 50%. The foregoing summary of the 2021 Loan Agreement does not purport to be a complete statement of the terms and conditions under the 2021 Loan Agreement, and is qualified in its entirety by the full terms and conditions of the 2021 Loan Agreement, which is filed as Exhibit 10.1 to this Form 10-Q. |
Accounting Policies, by Policy
Accounting Policies, by Policy (Policies) | 3 Months Ended |
Mar. 31, 2021 | |
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 2020 Annual Report on Form 10-K. Operating results for the three months ended March 31, 2021 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2021. |
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 Accounts 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. |
Fair Value of Financial Instruments, Policy [Policy Text Block] | Fair Value of Other Financial Instruments The carrying value of the Partnership’s other financial instruments, including cash and cash equivalents, accounts 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. |
Earnings Per Share, Policy [Policy Text Block] | Net Income Per Common Unit Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three months ended March 31, 2021 and 2020. 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 7) will occur. |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
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: 2021 2020 Balance at January 1 $ 1,564,105 $ 1,452,734 Well additions - 27,844 Accretion 20,971 19,979 Revisions - - Balance at March 31 $ 1,585,076 $ 1,500,557 |
Risk Management (Tables)
Risk Management (Tables) | 3 Months Ended |
Mar. 31, 2021 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block] | The Partnership did not designate its derivative instruments as hedges for accounting purposes and did not enter 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 had no outstanding contracts at March 31, 2021. The following table presents the settlement gain (loss) of matured derivative instruments and non-cash mark-to-market gains for the periods presented. Three Months Ended Three Months Ended Settlement gains (losses) on matured derivatives $ (1,182,420 ) $ 257,040 Gain on mark-to-market of derivatives 602,760 183,850 Gain (loss) on derivatives, net $ (579,660 ) $ 440,890 |
Partnership Organization (Detai
Partnership Organization (Details) shares in Millions | Jul. 21, 2020 | Sep. 30, 2019USD ($) | Nov. 21, 2017USD ($) | Dec. 18, 2015 | Jul. 09, 2013USD ($) | May 31, 2021USD ($) | Mar. 31, 2021USD ($) | Mar. 31, 2020USD ($) | Dec. 31, 2019USD ($) | Apr. 24, 2017USD ($)shares |
Partnership Organization (Details) [Line Items] | ||||||||||
Limited Liability Company or Limited Partnership, Business, Formation State | Delaware | |||||||||
Partners' Capital Account, Contributions | $ 1,000 | |||||||||
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 | |||||||||
Sanish Field Located in Mountrail County, North Dakota [Member] | ||||||||||
Partnership Organization (Details) [Line Items] | ||||||||||
Capital Expenditures, Drilling and Completion of Wells | $ 60,000,000 | $ 7,800,000 | ||||||||
Revolving Credit Facility [Member] | ||||||||||
Partnership Organization (Details) [Line Items] | ||||||||||
Debt Instrument, Face Amount | $ 20,000,000 | $ 60,000,000 | ||||||||
Long-term Line of Credit | 40,000,000 | |||||||||
Debt Instrument, Maturity Date | Nov. 21, 2019 | Mar. 1, 2024 | ||||||||
Revolving Credit Facility [Member] | Amended Loan Agreement [Member] | ||||||||||
Partnership Organization (Details) [Line Items] | ||||||||||
Debt Instrument, Face Amount | $ 40,000,000 | 40,000,000 | ||||||||
Long-term Line of Credit | $ 40,000,000 | |||||||||
Debt Instrument, Maturity Date | Jul. 31, 2021 | Sep. 30, 2022 | ||||||||
Sanish Field Located in Mountrail County, North Dakota [Member] | ||||||||||
Partnership Organization (Details) [Line Items] | ||||||||||
Wells Elected to Participate in Drilling | 43 | |||||||||
Capital Expenditures, Drilling and Completion of Wells | $ 60,000,000 | |||||||||
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 | 11.00% | 25.00% | ||||||||
Oil, Productive Well, Number of Wells, Net | 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 | |||||||||
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 | 17.00% | |||||||||
Oil and Gas, Present Activity, Well in Process of Drilling | 24 |
Oil and Gas Investments (Detail
Oil and Gas Investments (Details) $ in Millions | Mar. 31, 2017 | Jan. 11, 2017USD ($) | Dec. 18, 2015USD ($) | Mar. 31, 2017USD ($) | Mar. 31, 2021USD ($) | Dec. 31, 2018 | Mar. 31, 2020USD ($) | Dec. 31, 2020 | Dec. 31, 2019USD ($) |
Sanish Field Located in Mountrail County, North Dakota [Member] | |||||||||
Oil and 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) | $ 60 | $ 7.8 | |||||||
Costs Incurred, Development Costs (in Dollars) | 43 | ||||||||
Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member] | |||||||||
Oil and Gas Investments (Details) [Line Items] | |||||||||
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars) | 10 | ||||||||
Sanish Field Located in Mountrail County, North Dakota [Member] | Maximum [Member] | |||||||||
Oil and Gas Investments (Details) [Line Items] | |||||||||
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars) | $ 15 | ||||||||
Acquisition No. 1 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | |||||||||
Oil and Gas Investments (Details) [Line Items] | |||||||||
Business Combination, Consideration Transferred (in Dollars) | $ 159.6 | ||||||||
Acquisition No. 2 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | |||||||||
Oil and 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 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 Gas Investments (Details) [Line Items] | |||||||||
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars) | $ 60 | ||||||||
Wells Elected to Participate in Drilling | 43 | ||||||||
Non-operated Completed Wells [Member] | |||||||||
Oil and Gas Investments (Details) [Line Items] | |||||||||
Oil and Gas, Development Well Drilled, Net Productive, Number | 22 | ||||||||
Working Interest | 23.00% | ||||||||
Non-operated Completed Wells [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | |||||||||
Oil and Gas Investments (Details) [Line Items] | |||||||||
Gas and Oil Area Developed, Net | 11.00% | 25.00% | |||||||
Oil, Productive Well, Number of Wells, Net | 243 | ||||||||
Non-operated Wells in the Process of Drilling [Member] | |||||||||
Oil and Gas Investments (Details) [Line Items] | |||||||||
Working Interest | 18.00% | ||||||||
Oil and Gas, Present Activity, Well in Process of Drilling | 21 | ||||||||
Non-operated Wells in the Process of Drilling [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | |||||||||
Oil and Gas Investments (Details) [Line Items] | |||||||||
Gas and Oil Area Developed, Net | 17.00% | ||||||||
Oil and Gas, Present Activity, Well in Process of Drilling | 24 | ||||||||
Whiting Petroleum [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | |||||||||
Oil and Gas Investments (Details) [Line Items] | |||||||||
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars) | $ 1.9 | ||||||||
Costs Incurred, Development Costs (in Dollars) | $ 0.3 | ||||||||
Whiting Petroleum [Member] | Sanish Field Located in Mountrail County, North Dakota [Member] | |||||||||
Oil and Gas Investments (Details) [Line Items] | |||||||||
Wells Elected to Participate in Drilling | 3 | ||||||||
Working Interest | 11.00% |
Debt (Details)
Debt (Details) - USD ($) | Jul. 21, 2020 | Sep. 30, 2019 | Nov. 21, 2017 | May 31, 2021 | Jul. 31, 2020 | Mar. 31, 2021 |
Debt (Details) [Line Items] | ||||||
Line of Credit Facility, Fair Value of Amount Outstanding (in Dollars) | $ 40,000,000 | |||||
Revolving Credit Facility [Member] | ||||||
Debt (Details) [Line Items] | ||||||
Debt Instrument, Face Amount (in Dollars) | $ 20,000,000 | $ 60,000,000 | ||||
Debt Instrument, Maturity Date | Nov. 21, 2019 | Mar. 1, 2024 | ||||
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 Simmons Credit Facility, or $90,000 | |||||
Line of Credit Facility, Commitment Fee Percentage | 0.45% | |||||
Line of Credit Facility, Commitment Fee Amount (in Dollars) | $ 90,000 | |||||
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.50% | |||||
Line of Credit Facility, Covenant Compliance | The Partnership was in compliance with its applicable covenants at March 31, 2021 | |||||
Long-term Line of Credit (in Dollars) | $ 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 (in Dollars) | $ 40,000,000 | $ 40,000,000 | ||||
Debt Instrument, Maturity Date | Jul. 31, 2021 | 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 | |||||
Debt Instrument, Collateral Amount (in Dollars) | $ 1,600,000 | |||||
Restricted Cash, Current (in Dollars) | 400,000 | |||||
Long-term Line of Credit (in Dollars) | $ 40,000,000 | |||||
GKDML [Member] | ||||||
Debt (Details) [Line Items] | ||||||
Debt Instrument, Face Amount (in Dollars) | $ 15,000,000 | |||||
Debt Instrument, Term | 1 year | |||||
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% | |||||
London Interbank Offered Rate (LIBOR) [Member] | GKDML [Member] | ||||||
Debt (Details) [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 2.00% | |||||
London Interbank Offered Rate (LIBOR) [Member] | GKDML [Member] | Minimum [Member] | ||||||
Debt (Details) [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 0.00% | |||||
Prime Rate [Member] | Revolving Credit Facility [Member] | Amended Loan Agreement [Member] | ||||||
Debt (Details) [Line Items] | ||||||
Debt Instrument, Basis Spread on Variable Rate | 1.00% | |||||
Prime Rate [Member] | Revolving Credit Facility [Member] | Amended Loan Agreement [Member] | Minimum [Member] | ||||||
Debt (Details) [Line Items] | ||||||
Debt Instrument, Minimum Interest Rate | 4.00% |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations - USD ($) | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Schedule of Asset Retirement Obligations [Abstract] | ||
Balance | $ 1,564,105 | $ 1,452,734 |
Well additions | 0 | 27,844 |
Accretion | 20,971 | 19,979 |
Revisions | 0 | 0 |
Balance | $ 1,585,076 | $ 1,500,557 |
Risk Management (Details)
Risk Management (Details) | 2 Months Ended | 3 Months Ended | 12 Months Ended | ||
Feb. 28, 2021bbl | Feb. 28, 2021MMcf | Mar. 31, 2021USD ($) | Mar. 31, 2020USD ($) | Dec. 31, 2020USD ($) | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||
Discussion of Price Risk Derivative Risk Management Policy | Debt, the Partnership was 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 2020 through February 2021. | ||||
Number of Derivative Contracts | 2 | ||||
Derivative, Nonmonetary Notional Amount, Volume | 105,000 | 120,000 | |||
Gain (Loss) on Derivative Instruments, Net, Pretax | $ (1,182,420) | $ 257,040 | |||
Derivative Liability | $ 600,000 |
Risk Management (Details) - Sch
Risk Management (Details) - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value - USD ($) | 3 Months Ended | |
Mar. 31, 2021 | Mar. 31, 2020 | |
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Abstract] | ||
Settlement gains (losses) on matured derivatives | $ (1,182,420) | $ 257,040 |
Gain on mark-to-market of derivatives | 602,760 | 183,850 |
Gain (loss) on derivatives, net | $ (579,660) | $ 440,890 |
Capital Contribution and Part_2
Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions | Jul. 09, 2013 | Mar. 31, 2021 | Mar. 31, 2020 | Mar. 31, 2019 | 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 | ||||
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) | $ 1,526,575 | ||||
Distribution at Payout to limited partner | $ 29,000,000 | ||||
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share) | $ 0.241644 | ||||
Distribution Made to Limited Partner, Cash Distributions Paid | $ 0 | $ 4,584,826 | |||
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 ($) | Jan. 01, 2021 | Mar. 31, 2021 | Mar. 31, 2020 |
General Partner [Member] | |||
Related Parties (Details) [Line Items] | |||
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party | $ 32,000 | $ 92,000 | |
Due to Related Parties, Current | 32,000 | ||
Affiliated Entity [Member] | |||
Related Parties (Details) [Line Items] | |||
Reimbursements From Related Party | $ 76,000 | ||
Administrative Service Agreement [Member] | |||
Related Parties (Details) [Line Items] | |||
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party | $ 141,000 | ||
Related Party, Administrative Service Agreement | Under the ASA, the Administrator will also assist Energy Resources 12 GP, LLC, the general partner of ER12 (“ER12’s General Partner”), with the day-to-day operations of ER12. ER12 currently pays ER12’s General Partner an annual management fee of 0.5% of the total gross equity proceeds raised by ER12 in its best-efforts offering. Under the ASA, ER12’s General Partner will pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. This fee is only applicable to ER12 and does not apply to the Partnership. |
Subsequent Events (Details)
Subsequent Events (Details) - Revolving Credit Facility [Member] - Subsequent Event [Member] | May 13, 2021USD ($) |
Subsequent Events (Details) [Line Items] | |
Debt Instrument, Face Amount | $ 60,000,000 |
Debt Instrument, Fee | origination fee of 0.50% of the Maximum Credit Amount |
Debt Instrument, Fee Amount | $ 300,000 |
Line of Credit Facility, Commitment Fee Description | The Partnership is also required to pay an annual fee to the Lender of $30,000, and an unused facility fee of 0.25% on the unused portion of the Revolving Credit Facility, based on borrowings outstanding during a quarter. |
Line of Credit Facility, Unused Capacity, Commitment Fee Percentage | 0.25% |
Debt Instrument, Maturity Date | Mar. 1, 2024 |
Line of Credit Facility, Borrowing Capacity, Description | Under the 2021 Loan Agreement, the initial borrowing base is $60 million. The Partnership also is required to make a monthly principal reduction payment (“Monthly Commitment Reduction”), which is initially stipulated to be $1 million. The borrowing base and Monthly Commitment Reduction are subject to redetermination semi-annually, on March 1 and September 1, based upon the Lender’s analysis of the Partnership’s proven oil and natural gas reserves. The Lender is also permitted to cause the borrowing base to be redetermined up to two times during a 12-month period |
Line of Credit Facility, Interest Rate at Period End | 4.00% |
Proceeds from Lines of Credit | $ 40,000,000 |
Repayments of Lines of Credit | $ 40,000,000 |
Line of Credit Facility, Collateral | The Revolving Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells |
Line of Credit Facility, Dividend Restrictions | The Revolving Credit Facility contains prepayment requirements, customary affirmative and negative covenants and events of default. The financial covenants include a minimum debt service coverage ratio and a minimum current ratio. The 2021 Loan Agreement restricts the Partnership’s ability to pay limited partner distributions until the outstanding balance of the Revolving Credit Facility is equal to or less than 50% of the Maximum Credit Amount, at which point the Partnership is permitted to make distributions so long as the Partnership is in compliance with its debt service coverage ratio and no other event of default has occurred. |
Debt, Risk Management, Description | Also under the 2021 Loan Agreement, the Partnership is required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production. The Partnership must hedge at least 50% of its rolling 12-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is less than 50%, and at least 50% of its rolling 24-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is greater than 50%. |
Prime Rate [Member] | |
Subsequent Events (Details) [Line Items] | |
Derivative, Basis Spread on Variable Rate | 0.50% |
Prime Rate [Member] | Minimum [Member] | |
Subsequent Events (Details) [Line Items] | |
Debt Instrument, Minimum Interest Rate | 4.00% |