Energy Resources 12 10-Q2024 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q 

For the quarterly period ended March 31, 2024

Commission File Number 000-55916

Energy Resources 12, L.P.

(Exact name of registrant as specified in its charter)

(817) 882-9192

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

As of May 15, 2024, the Partnership had 11,031,579 common units outstanding.

Energy Resources 12, L.P.

Form 10-Q

Index

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Energy Resources 12, L.P.

Consolidated Balance Sheets

See notes to consolidated financial statements.

Energy Resources 12, L.P.

Consolidated Statements of Operations

(Unaudited)

See notes to consolidated financial statements.

Energy Resources 12, L.P.

Consolidated Statements of Partners’ Equity

(Unaudited)

See notes to consolidated financial statements.

Energy Resources 12, L.P.

Consolidated Statements of Cash Flows

(Unaudited)

See notes to consolidated financial statements.

Energy Resources 12, L.P.

Notes to Consolidated Financial Statements

March 31, 2024

(Unaudited)

Note 1. Partnership Organization

Energy Resources 12, L.P. (together with its wholly-owned subsidiary, 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 December 30, 2016. The Partnership completed its best-efforts offering in October 2019 with a total of approximately 11.0 million common units sold for gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.

As of March 31, 2024, the Partnership owned an approximate 5.5% non-operated working interest in 424 producing wells, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”). The Partnership also owns an estimated approximate 2.3% non-operated working interest in 24 wells in various stages of the drilling and completion process, and possible future development locations in the Bakken Assets. The Bakken Assets, which are a part of the Bakken shale formation in the Greater Williston Basin, are operated by 13 third-party operators on behalf of the Partnership and other working interest owners.

The general partner of the Partnership is Energy Resources 12 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.

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 for complete financial statements. 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 December 31, 2023 financial statements included in its 2023 Annual Report on Form 10-K. Operating results for the three months ended March 31, 2024 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2024.

Cash and Cash Equivalents

Cash and cash equivalents consist of highly liquid investments with original maturities of three months or less. The fair market value of cash and cash equivalents approximates their carrying value. Cash balances may at times exceed federal depository insurance limits.

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 and other current assets 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.

Accounts Receivable and Concentration of Credit Risk

Substantially all of the Partnership’s accounts receivable are due from the operators of the Partnership’s oil and natural gas properties in North Dakota (the operators have accounts receivable from purchasers of oil, natural gas and NGLs). Oil, natural gas and NGL sales receivables are generally unsecured. This industry and location concentration has the potential to impact the Partnership’s overall exposure to credit risk, in that the purchasers of the Partnership’s oil, natural gas and NGLs and the operators of the properties the Partnership has an interest in may be similarly affected by changes in economic, industry or other conditions. At March 31, 2024 and December 31, 2023, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible and the Partnership’s operators do not have a history of non-payment. For the quarter ended March 31, 2024, approximately 94% of the Partnership’s total revenue was generated through sales by five of its 13 operators, respectively. All oil and natural gas producing activities of the Partnership are in North Dakota and represent substantially all of the business activities of the Partnership.

Income Tax

The Partnership is taxed as a partnership for federal and state income tax purposes. Typically, the Partnership has not recorded a provision for income taxes since the liability for such taxes is that of each of the partners rather than the Partnership. In mid-2022, the Partnership was contacted by the state of North Dakota, which asserted that the Partnership has an obligation to make tax payments on behalf of certain non-resident partners. In accordance with its settlements with the state of North Dakota, the Partnership has made payments of (i) approximately $365,000 (approximately $0.033 per common unit) in May 2023 for tax year 2021; (ii) approximately $532,000 (approximately $0.048 per common unit) in April 2024 for tax year 2022; and (iii) approximately $142,000 (approximately $0.013 per common unit) in April 2024 for tax year 2023.

The Partnership’s income tax returns are subject to examination by the federal and state taxing authorities, and changes, if any, could adjust the individual income tax of the partners. The Partnership has evaluated whether any material tax position taken will more likely than not be sustained upon examination by the appropriate taxing authority and believes that all such material tax positions taken are supportable by existing laws and related interpretations.

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 (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 months ended March 31, 2024 and 2023. As a result, basic and diluted outstanding common units were the same. The Incentive Distribution Rights, as defined below, are not included in net income (loss) per common unit until such time that it is probable Payout (as discussed in Note 5) will occur.

Note 3. Oil and Gas Investments

On February 1, 2018, the Partnership completed its first purchase (“Acquisition No. 1”) in the Bakken Assets for approximately $90.5 million, including all closing costs and assumed liabilities. On August 31, 2018, the Partnership completed its second purchase of an additional non-operated working interest in the Bakken Assets for approximately $81.3 million, including all closing costs and assumed liabilities. As of March 31, 2023, the Partnership’s ownership of the Bakken Assets consisted of an approximate 5.7% non-operated working interest in 403 producing wells, and an estimated approximate 2.4% non-operated working interest in 21 wells in various stages of the drilling and completion process.

From September 1, 2017, the effective date of Acquisition No. 1, to March 31, 2024, the Partnership has participated in the drilling of 244 wells, of which 218 have been completed as of March 31, 2024. The Partnership incurred approximately $0.5 million and $1.3 million in capital drilling and completion costs for the three-month periods ended March 31, 2024 and 2023, respectively. The Partnership anticipates approximately $2 million of capital expenditures will be incurred to complete the 24 wells in process as of March 31, 2024. Estimated capital expenditures to complete these 24 wells could be significantly different from amounts actually invested, and the timing of these expenditures is difficult to estimate.

Note 4. 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:

Note 5. Capital Contribution and Partners’ Equity

At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990, the General Partner received Incentive Distribution Rights (defined below), and has been reimbursed for its documented third-party out-of-pocket expenses incurred in organizing the Partnership and offering the common units.

The Partnership completed its best-efforts offering of common units as of the close of business on October 24, 2019. As of the conclusion of the offering, the Partnership had completed the sale of approximately 11.0 million common units for total gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.

Under the agreement with David Lerner Associates, Inc. (the “Managing Dealer”), the Managing Dealer received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering as outlined in the prospectus based on the performance of the Partnership. Based on the common units sold in the best-efforts offering, the Dealer Manager Incentive Fees are approximately $8.7 million, subject to Payout (defined below).

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 the Dealer Manager Incentive Fees to the Managing Dealer until Payout occurs.

The Agreement of Limited Partnership of the Partnership (the “Partnership Agreement”) provides that “Payout”, which is defined below, 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 common unit, regardless of the amount paid for the common 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.

In June 2023, the General Partner declared and paid a special distribution to return $1.60 per common unit of capital to holders of Partnership common units. As described in Income Tax in Note 2. Summary of Significant Accounting Policies, in May 2023 and April 2024, the Partnership paid total withholding taxes of approximately $0.09 per common unit to the state of North Dakota on behalf of its limited partners related to tax years 2021, 2022 and 2023. These withholding tax payments, along with the $1.60 per common unit special distribution to holders of its common units in June 2023, have reduced the Net Investment Amount described above by an approximate total of $1.69 per common unit.

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:

All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.

For the three months ended March 31, 2024 and 2023, the Partnership paid distributions of $0.320541 and $0.349041 per common unit, or $3.5 million and $3.9 million, respectively.

Note 6. Related Parties

The Class A voting members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer and David S. McKenney, Chief Financial Officer. Messrs. Knight and McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy 11 GP, LLC, the general partner of Energy 11, L.P. (“Energy 11”), a limited partnership that also invests in producing and non-producing oil and gas properties on-shore in the United States.

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.

The Partnership will reimburse the General Partner for any costs incurred by the General Partner for certain expenses, which include costs for organizing the Partnership, costs incurred in the offering of the common units and general and administrative costs. The Partnership also agreed to pay the General Partner an advisory fee to manage the day-to-day affairs of the Partnership, including serving as an investment advisor and consultant in connection with the acquisition, development, operation and disposition of oil and gas properties and other assets of the Partnership. In accordance with the Partnership Agreement, subsequent to the Partnership’s first asset purchase, which occurred on February 1, 2018, the Partnership is required to pay quarterly an annual fee of 0.5% of the total gross equity proceeds raised by the Partnership in its best-efforts offering. The management fee that has been paid to the General Partner for the three months ended March 31, 2024 and 2023 was approximately $273,000 in both periods, and is included in General and administrative expenses on the consolidated statements of operations.

For the three months March 31, 2024 and 2023, approximately $78,000 and $42,000 of general and administrative costs, respectively, were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At March 31, 2024, approximately $78,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses in the consolidated balance sheets.

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 Energy 11, whereby the Administrator was to provide administrative, operating and professional services necessary and useful to the Partnership. The Administrator also was to assist the General Partner with the day-to-day operations of the Partnership. The Administrator is owned by entities that are controlled by Anthony F. Keating, III and Michael J. Mallick, former Class B members of the General Partner and the former Co-Chief Operating Officers of Energy 11’s general partner. The ASA became effective January 1, 2021.

On April 5, 2023, the Partnership and Energy 11 entered into an agreement (the “Agreement”) with Messrs. Knight, McKenney, Keating and Mallick and various affiliates of each, including the Administrator. Pursuant to the Agreement, the ASA was terminated effective immediately, subject to a 60-day transition period to transition the services being provided by the Administrator to Partnership and Energy 11 management. All Administrator costs and expenses were 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 reimbursed under the ASA included, but were not limited to, employee wages and benefits – including the former president of Energy 11’s general partner, who was paid as an employee of the Administrator, rent for office space and network and information technology support. Other expenses, such as business travel costs and accounting, legal or banking services, were not incurred by the Administrator on behalf of the Partnership without prior express written consent of the Partnership. Costs and expenses attributable to the services performed by the Administrator under the ASA have been reimbursed by the Partnership. For the three months ended March 31, 2023, approximately $130,000 of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator.

Also pursuant to the Agreement, the affiliates of Messrs. Keating and Mallick sold (i) their Class B Unit interests in the General Partner; (ii) all interests in the general partner of Energy 11; (iii) all common unit interests in Energy 11; and (iv) all Class B Unit interests in Energy 11 to an affiliate of Mr. Knight and withdrew as members of General Partner and the general partner of Energy 11. Prior to the execution of the Agreement, the General Partner had agreed to pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. Therefore, one-half of the management fee for the three months ended March 31, 2023 described above was paid by the General Partner to the Administrator.

Note 7. Subsequent Events

In April 2024, the Partnership declared and paid $1.1 million, or $0.098628 per outstanding common unit, in distributions to its holders of common units.

On May 2, 2024, the Partnership and its wholly-owned subsidiary, as borrowers, entered into a loan agreement (“Loan Agreement”) with BancFirst (the “Lender”), which provides for a revolving credit facility (“Credit Facility”) with an approved maximum credit amount (“Maximum Credit Amount”) of $20 million, subject to borrowing base restrictions. The Partnership paid one-time commitment and setup fees totaling $100,000 at closing. The Partnership is also subject to an additional fee of 0.50% on any incremental increase to the borrowing base. The Partnership is required to pay an unused facility fee of 0.25% on the unused portion of the Credit Facility, based on borrowings outstanding during a quarter. The maturity date is March 1, 2026.

Under the Loan Agreement, the initial borrowing base is $10 million. The borrowing base is 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 additional times during a 12-month period. Outstanding borrowings under the 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 4.50%. At closing, the interest rate for the Credit Facility was 9.00%.

At closing, the Partnership borrowed approximately $1.5 million. Any further advances under the Credit Facility are to be used to fund capital expenditures for the development of the Partnership’s undrilled acreage. Under the terms of the Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The Credit Facility is secured by a mortgage and first lien position on at least 80% of the Partnership’s producing wells.

The Credit Facility contains 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 Loan Agreement does not restrict the Partnership’s ability to pay limited partner distributions unless the Partnership is in default of its debt service coverage ratio or another event of default has occurred. In addition, the Partnership is not required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production. However, if the Partnership does elect to speculatively trade and hedge future oil and natural gas production, hedged volumes may not exceed 85% of the Partnership’s anticipated future production.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Certain statements within this report may constitute forward-looking statements. Forward-looking statements are those that do not relate solely to historical fact. They include, but are not limited to, any statement that may predict, forecast, indicate or imply future results, performance, achievements or events. You can identify these statements by the use of words such as “may,” “will,” “could,” “anticipate,” “believe,” “estimate,” “expect,” “intend,” “predict,” “continue,” “further,” “seek,” “plan” or “project” and variations of these words or comparable words or phrases of similar meaning.

These forward-looking statements include such things as:

These forward-looking statements reflect the Partnership’s current beliefs and expectations with respect to future events and are based on assumptions and are subject to risks and uncertainties and other factors outside the Partnership’s control that may cause actual results to differ materially from those projected. Such factors include, but are not limited to, those described under “Risk Factors” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2023 and the following:

Although the Partnership believes the expectations reflected in such forward-looking statements are based upon reasonable assumptions, the Partnership cannot assure investors that its expectations will be attained or that any deviations will not be material. Investors are cautioned that forward-looking statements speak only as of the date they are made and that, except as required by law, the Partnership undertakes no obligation to update these forward-looking statements to reflect any future events or circumstances. All subsequent written or oral forward-looking statements attributable to the Partnership or to individuals acting on its behalf are expressly qualified in their entirety by this section.

The following discussion and analysis should be read in conjunction with the Partnership’s Unaudited Consolidated Financial Statements and Notes thereto, appearing elsewhere in this Quarterly Report on Form 10-Q, as well as the information contained in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2023.

Overview

Energy Resources 12, L.P. (the “Partnership”) was formed as a Delaware limited partnership. The initial capitalization of the Partnership of $1,000 occurred on December 30, 2016. The Partnership began offering common units of limited partner interest (the “common units”) on a best-efforts basis on May 17, 2017, the date the Partnership’s initial Registration Statement on Form S-1 (File No. 333-216891) was declared effective by the Securities and Exchange Commission. The Partnership completed its best-efforts offering on October 24, 2019. Total common units sold were approximately 11.0 million for gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.

The general partner is Energy Resources 12 GP, LLC (the “General Partner”). The General Partner manages the day-to-day affairs of the Partnership. All decisions regarding the management of the Partnership made by the General Partner are made by the Board of Directors of the General Partner and its officers. The Partnership has no officers, directors or employees.

The Partnership was formed to acquire primarily oil and gas properties located onshore in the United States. On February 1, 2018, the Partnership completed its first asset purchase in the Williston Basin of North Dakota, acquiring, at closing, non-operated working interests in producing wells and in-process wells, along with additional future development locations, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the “Bakken Assets”), for approximately $90.5 million. On August 31, 2018, the Partnership closed on its second asset purchase, acquiring an additional non-operated working interest in the Bakken Assets for approximately $81.3 million. Prior to these acquisitions, the Partnership owned no oil and natural gas assets. The Partnership utilized proceeds from its best-efforts offering and available financing to close on the acquisitions.

As a result of these acquisitions and completed drilling during the period of ownership, as of March 31, 2024, the Partnership’s ownership of the Bakken Assets consisted of an approximate 5.5% non-operated working interest in 424 producing wells, an estimated 2.3% non-operated working interest in 24 wells in various stages of the drilling and completion process and additional possible future development locations.

The Bakken Assets are operated by 13 third-party operators, including Devon Energy Corporation, Marathon Oil, EOG Resources, Continental Resources and Chord Energy.

Current Price Environment

Oil, natural gas and natural gas liquids (“NGL”) prices are determined by many factors outside of the Partnership’s control. Historically, world-wide oil and natural gas prices and markets have been subject to significant change and may continue to be in the future. Global macroeconomic factors contributing to uncertainty within the industry include real or perceived geopolitical risks in oil-producing regions of the world, particularly Russia and the Middle East; forecasted levels of global economic growth combined with forecasted global supply; supply levels of oil and natural gas due to exploration and development activities in the United States; environmental and climate change regulation; actions taken by the Organization of the Petroleum Exporting Countries (“OPEC”); and the strength of the U.S. dollar in international currency markets.

The length and outcome of the military conflicts between Ukraine and Russia as well as Israel and Hamas are highly unpredictable, and further escalation of these conflicts could lead to significant market and other disruptions, such as volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, political and social instability and other material and adverse effects on macroeconomic conditions. The short- and long-term impact of these conflicts on the operations and financial condition of the Partnership and the global economy is uncertain.

The following table lists average NYMEX prices for oil and natural gas for the three months ended March 31, 2024 and 2023.

The Partnership’s oil and natural gas revenues are heavily weighted to oil, so any material change to market pricing for oil has a more significant impact to the Partnership’s operational performance. If commodity prices significantly drop, such as the decline in the second quarter of 2020, and remain low, the Partnership will see a reduction in available capital for the development of its undrilled wellsites. Future growth is dependent on the Partnership’s ability to add reserves in excess of production. In addition to commodity price fluctuations, the Partnership faces the challenge of natural production volume declines. As reservoirs are depleted, oil and natural gas production from Partnership wells will decrease.

Results of Operations

In evaluating financial condition and operating performance, the most important indicators on which the Partnership focuses are (1) total quarterly production in barrel of oil equivalent (“BOE”) units, (2) average sales price per unit for oil, natural gas and natural gas liquids (“NGL” or “NGLs”), (3) production costs per BOE and (4) capital expenditures.

The following table is a summary of the results from operations, including production, of the Partnership’s non-operated working interest in the Bakken Assets for the three months ended March 31, 2024 and 2023.

Oil, natural gas and NGL revenues

For the three months ended March 31, 2024, revenues for oil, natural gas and NGL sales were $8.7 million. Revenues for the sale of crude oil were $7.2 million, which resulted in a realized price of $73.66 per barrel. Revenues for the sale of natural gas were $0.6 million, which resulted in a realized price of $2.26 per Mcf. Revenues for the sale of NGLs were approximately $0.9 million, which resulted in a realized price of $26.00 per BOE of production. For the three months ended March 31, 2023, revenues for oil, natural gas and NGL sales were $15.6 million. Revenues for the sale of crude oil were $13.3 million, which resulted in a realized price of $75.79 per barrel. Revenues for the sale of natural gas were $1.2 million, which resulted in a realized price of $4.70 per Mcf. Revenues for the sale of NGLs were approximately $1.1 million, which resulted in a realized price of $27.39 per BOE of production.

The Partnership’s results for the three months ended March 31, 2024 were negatively impacted by adverse weather conditions in North Dakota; extremely cold temperatures for a multi-day stretch in mid-January led to suspended production throughout the Bakken. North Dakota’s Department of Mineral Resources reported a basin-wide drop in oil production of approximately 13.5% in January, and production did not return to levels realized during the fourth quarter of 2023. Sold production for the Sanish Field Assets was approximately 1,900 BOE per day for the three months ended March 31, 2024. Conversely, the Partnership’s results for the three months ended March 31, 2023 were positively impacted by the recent completion of eleven (11) new wells that were turned to sales during the fourth quarter of 2022, with sold production for the Bakken Assets approximating 2,900 BOE per day for the three months ended March 31, 2023.

The Partnership has recently elected to participate in the drilling of 24 new wells, of which the Partnership owns an average estimated non-operated working interest of approximately 2.3%. These wells are anticipated to be completed during the second and third quarters of 2024. Certain of these 24 wells are expected to significantly contribute to sold production volumes upon completion. Production volumes per day fluctuate due to the timing of well completions; new wells often have high levels of production immediately following completion, then decline to more consistent levels.

The Partnership’s results for the three months ended March 31, 2024 were also negatively impacted by lower realized sales prices for oil (see Differentials below) and natural gas. Continued high inventories and lower demand stemming from warmer winter weather conditions across the country kept natural gas prices low throughout the first quarter of 2024. However, high natural gas market spot prices in December 2022 carried over to early January 2023 natural gas sales, which fueled the Partnership’s realized natural gas sales prices in excess of the market average during the first quarter of 2023.

If the operators of the Bakken Assets are unable to produce, process and sell oil and natural gas at economical prices, the operators may curtail daily production, shut-in producing wells or seek other cost-cutting measures. Consequently, any of these measures could significantly impact the Partnership’s oil, natural gas and NGL production, and there can be no assurance regarding how they will produce if and when they are brought back on-line. Further, production is dependent on the investment in existing wells and the development of new wells. See further discussion on the Partnership’s investment in new wells in “Liquidity and Capital Resources” below.

Differentials

The realized prices per barrel of oil above are based upon the NYMEX benchmark price less a cost to distribute the oil, or the differential. Oil price differentials primarily represent the transportation costs in moving produced oil at the wellhead to a refinery and are based on the availability of pipeline, rail and other transportation methods out of the Bakken. Oil price differentials to the NYMEX benchmark price vary by operator based upon operator-specific contracts. On average, the Partnership’s realized oil price differentials increased during the first quarter of 2024, in comparison to the first and fourth quarters of 2023, which reduced the Partnership’s realized oil sales prices.

The Dakota Access Pipeline is a significant pipeline that transports oil and natural gas from North Dakota fields. Its use by operators in the region is currently in ongoing litigation in the United States. If use of the Dakota Access Pipeline or any other pipelines servicing the region are suspended at a future date, the disruption of transporting the Partnership’s production out of North Dakota could negatively impact the Partnership’s realized sales prices, results of operations and/or cash flows.

Operating costs and expenses

Production expenses

Production expenses are daily costs incurred by the Partnership to bring oil and natural gas out of the ground and to market, along with the daily costs incurred to maintain producing properties. Such costs include field personnel compensation, saltwater disposal, utilities, maintenance, repairs and servicing expenses related to the Partnership’s oil and natural gas properties, along with the gathering and processing contracts in effect for the extraction, transportation and treatment of oil and natural gas.

Production expenses for the three months ended March 31, 2024 and 2023 were $4.3 million and $5.5 million, and production expenses per BOE were $24.74 and $21.14, respectively. Production expenses per BOE increased in the three months ended March 31, 2024, in comparison to the same period of 2023, primarily due to an decrease in sold production volumes, which decreases the production base over which fixed costs are spread. The Partnership also experienced an increase in workover activity in the first quarter of 2024 to ensure production from wells is maximized.

Production taxes

Taxes on the production and extraction of oil and gas are regulated and set by North Dakota tax authorities. Taxes on the sale of gas and NGL products are less than taxes levied on the sale of oil. Therefore, production taxes as a percentage of revenue may fluctuate dependent upon the ratio of sales of natural gas and NGLs to total sales. Production taxes for the three months ended March 31, 2024 and 2023 were $0.7 million (8% of revenue) and $1.3 million (8% of revenue), respectively. Oil production comprised approximately 56% and 68% of the Partnership’s sold production volumes in the three months ended March 31, 2024 and 2023, respectively.

General and administrative expenses

The principal components of general and administrative expense are accounting, legal, advisory and consulting fees. General and administrative costs for the three months ended March 31, 2024 and 2023 were $0.7 million in both periods.

Depreciation, depletion, amortization and accretion (“DD&A”)

DD&A of capitalized drilling and development costs of producing oil, natural gas and NGL properties are computed using the unit-of-production method on a field basis based on total estimated proved developed oil, natural gas and NGL reserves. Costs of acquiring proved properties are depleted using the unit-of-production method on a field basis based on total estimated proved developed and undeveloped reserves. The Partnership’s DD&A for the three months ended March 31, 2024 and 2023 was $4.1 million and $5.0 million, respectively, and DD&A per BOE of production was $23.58 and $19.46, respectively.

The increase in DD&A expense per BOE of production for the three months ended March 31, 2024, compared to same period of 2023, is primarily due to a reduction of the Partnership’s estimated proved developed and undeveloped reserves resulting from well performance during 2022 and 2023 as well as changes in the future drill schedule during the Partnership’s December 31, 2023 reserve analysis.

Interest income, net

Interest income, net for the three months ended March 31, 2024 was approximately $5,000 and $104,000.

Supplemental Non-GAAP Measure

The Partnership uses “Adjusted EBITDAX”, defined as earnings (loss) before (i) interest income, net; (ii) income taxes; (iii) depreciation, depletion, amortization and accretion; and (iv) exploration expenses, as a key supplemental measure of its operating performance. This non-GAAP financial measure should be considered along with, but not as an alternative to, net income, operating income, cash flow from operating activities or other measures of financial performance presented in accordance with GAAP. Adjusted EBITDAX is not necessarily indicative of funds available to fund the Partnership’s cash needs, including its ability to make cash distributions. Although Adjusted EBITDAX, as calculated by the Partnership, may not be comparable to Adjusted EBITDAX as reported by other companies that do not define such term exactly as the Partnership defines such term, the Partnership believes this supplemental measure is useful to investors when comparing the Partnership’s results between periods and with other energy companies.

The Partnership believes that the presentation of Adjusted EBITDAX is important to provide investors with additional information (i) to provide an important supplemental indicator of the operational performance of the Partnership’s business without regard to financing methods and capital structure, and (ii) to measure the operational performance of the Partnership’s operators.

The following table reconciles the Partnership’s GAAP net income to Adjusted EBITDAX for the three months ended March 31, 2024 and 2023.

Transactions with 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 existing related party transactions, as well as any new significant related party transactions.

See further discussion in “Note 6. Related Parties” in Part I, Item 1 of this Form 10-Q.

Liquidity and Capital Resources

Historically, the Partnership’s principal sources of liquidity have been cash on-hand and the cash flow generated from the properties the Partnership owns. The Partnership generated approximately $3.3 million and $27.2 million in cash flow from operating activities for the quarter ended March 31, 2024 and the year ended December 31, 2023, respectively. In May 2024, the Partnership entered into a loan agreement with BancFirst that provides for a revolving credit facility for the Partnership to use for future development of oil and natural gas wells on its undrilled acreage in North Dakota. The initial borrowing base is $10 million (see more information in “Subsequent Events” below), and the Partnership has an outstanding balance of approximately $1.5 million at the time of filing of this Form 10-Q.

The Partnership anticipates that cash on-hand, cash flow from operations and availability under its revolving credit facility will be adequate to meet its liquidity requirements for at least the next 12 months, including completing the outstanding capital expenditures discussed below.

Although the Partnership anticipates its sources of liquidity to be adequate to fund its cash requirements, if market prices for oil and natural gas decline and/or production from Partnership wells is not replenished through the completion of new well investments, the Partnership’s cash flow from operations may decline. This could have a significant impact on the Partnership’s available cash on-hand, the Partnership’s ability to fund distributions to its limited partners and/or participate in future drilling programs as proposed by the operators of the Bakken Assets.

Partners’ Equity

The Partnership completed its best-efforts offering of common units on October 24, 2019. As of the conclusion of the offering, the Partnership had completed the sale of approximately 11.0 million common units for total gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.

Under the agreement with the Managing Dealer, the Managing Dealer received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership’s best-efforts offering as outlined in the prospectus based on the performance of the Partnership. Based on the common units sold through the conclusion of the offering, the Dealer Manager Incentive Fees are approximately $8.7 million, subject to Payout (as defined in “Note 5. Capital Contribution and Partners’ Equity” in Part 1, Item 1 of this Form 10-Q).

Distributions

For the three months ended March 31, 2024 and 2023, the Partnership paid distributions of $0.320541 and $0.349041 per common unit, or $3.5 million and $3.9 million, respectively.

While the Partnership’s goal is to maintain a relatively stable distribution rate over the life of its program, the General Partner monitors monthly Partnership distributions in conjunction with the Partnership’s projected cash requirements for operations and capital expenditures for new wells. There can be no assurance as to the classification or duration of distributions at the current distribution rate. If distributions are not paid or are reduced, the difference to the current distribution rate per common unit will be deferred and is required to be paid before final Payout occurs.

Oil and Natural Gas Properties

The Partnership incurred approximately $0.5 million and $1.3 million in capital expenditures during the three months ended March 31, 2024 and 2023, respectively. The Partnership has 24 wells in various stages of the drilling and completion process, and the Partnership estimates its share of capital expenditures to finish these wells is approximately $2 million. The Partnership anticipates the 24 wells in process will be substantially completed during the second and third quarters of 2024. In addition to the estimated capital expenditures of approximately $2 million to fully fund the 24 wells into which the Partnership most recently elected, the Partnership anticipates that it may be obligated to invest up to an additional $20 to $30 million in drilling capital expenditures from 2024 through 2028 to participate in new well development in the Bakken Assets without becoming subject to non-consent penalties under the joint operating agreements or North Dakota statutes governing the Bakken Assets.

Since the Partnership is not the operator of any of its oil and natural gas properties, it is difficult to predict levels of future participation in the drilling and completion of new wells, the timing of such activities and their associated capital expenditures. This makes capital expenditures for drilling and completion projects difficult to forecast for the remainder of 2024. Current estimated capital expenditures could be significantly different from amounts actually invested.

The Partnership expects to fund overhead costs and capital additions related to the drilling and completion of wells primarily from cash on hand, cash generated by its producing wells and/or availability under its revolving credit facility. If an operator elects to complete drilling or other significant capital expenditure activity and the Partnership is unable to fund the capital expenditures, the General Partner may decide to farmout the well. Also, if a well is proposed under the operating agreement for one of the properties the Partnership owns, the General Partner may elect to “non-consent” the well. Non-consenting a well will generally cause the Partnership not to be obligated to pay the costs of the well, but the Partnership will not be entitled to the proceeds of production from the well and would be subject to a non-consent penalty.

Subsequent Events

In April 2024, the Partnership declared and paid $1.1 million, or $0.098628 per outstanding common unit, in distributions to its holders of common units.

On May 2, 2024, the Partnership and its wholly-owned subsidiary, as borrowers, entered into a loan agreement (“Loan Agreement”) with BancFirst (the “Lender”), which provides for a revolving credit facility (“Credit Facility”) with an approved maximum credit amount (“Maximum Credit Amount”) of $20 million, subject to borrowing base restrictions. The Partnership paid one-time commitment and setup fees totaling $100,000 at closing. The Partnership is also subject to an additional fee of 0.50% on any incremental increase to the borrowing base. The Partnership is required to pay an unused facility fee of 0.25% on the unused portion of the Credit Facility, based on borrowings outstanding during a quarter. The maturity date is March 1, 2026.

Under the Loan Agreement, the initial borrowing base is $10 million. The borrowing base is 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 additional times during a 12-month period. Outstanding borrowings under the 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 4.50%. At closing, the interest rate for the Credit Facility was 9.00%.

At closing, the Partnership borrowed approximately $1.5 million. Any further advances under the Credit Facility are to be used to fund capital expenditures for the development of the Partnership’s undrilled acreage. Under the terms of the Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The Credit Facility is secured by a mortgage and first lien position on at least 80% of the Partnership’s producing wells.

The Credit Facility contains 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 Loan Agreement does not restrict the Partnership’s ability to pay limited partner distributions unless the Partnership is in default of its debt service coverage ratio or another event of default has occurred. In addition, the Partnership is not required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production. However, if the Partnership does elect to speculatively trade and hedge future oil and natural gas production, hedged volumes may not exceed 85% of the Partnership’s anticipated future production.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not applicable.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rule 13a–15 and 15d–15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Partnership carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer of the General Partner, of the effectiveness of the Partnership’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were effective as of March 31, 2024 to provide reasonable assurance that information required to be disclosed in the Partnership’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Partnership’s disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer of the General Partner, as appropriate, to allow timely decisions regarding required disclosure.

Change in Internal Controls Over Financial Reporting

There have not been any changes in the Partnership’s internal controls over financial reporting that occurred during the quarterly period ended March 31, 2024 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

At the end of the period covered by this Quarterly Report on Form 10-Q, the Partnership was not a party to any material, pending legal proceedings.

Item 1A. Risk Factors

For a discussion of the Partnership’s potential risks and uncertainties, see the section titled “Risk Factors” in the Partnership’s 2023 Annual Report on Form 10-K. There have been no material changes to the risk factors previously disclosed in the 2023 Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Not applicable.

Item 3. Defaults upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

*Filed herewith.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.