UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549  

FORM 10-Q

Commission File Number 000-55615

Energy 11, 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 November 14, 2022,May 15, 2023, the Partnership had 18,973,474 common units outstanding. 

Energy 11, L.P.

Form 10-Q

Index

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Energy 11, L.P.

Consolidated Balance Sheets

See notes to consolidated financial statements.

Energy 11, L.P.

Consolidated Statements of Operations

(Unaudited)

See notes to consolidated financial statements.

Energy 11, L.P.

Consolidated Statements of Partners’ Equity

(Unaudited)

See notes to consolidated financial statements.

Energy 11, L.P.

Consolidated Statements of Cash Flows

(Unaudited)

See notes to consolidated financial statements.

Energy 11, L.P.

Notes to Consolidated Financial Statements

September 30, 2022March 31, 2023

(Unaudited)

Note 1. Partnership Organization

Energy 11, L.P. (the “Partnership”) is a Delaware limited partnership formed to acquire producing and non-producing oil and natural gas properties onshore in the United States and to develop those properties. The initial capitalization of the Partnership of $1,000 occurred on July 9, 2013. The Partnership completed its best-efforts offering on April 24, 2017 with a total of approximately 19.0 million common units sold for gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million.

As of September 30, 2022,March 31, 2023, the Partnership owned an approximate 25%24% non-operated working interest in 281295 producing wells, an estimated approximate 17%14% non-operated working interest in 18four 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”).

Chord Energy Corporation (“Chord”, NASDAQ: CHRD), the product of a merger between Whiting Petroleum Corporation (“Whiting”) and Oasis Petroleum Inc. (“Oasis”), twois one of the largest producers in the Williston basin of North Dakota, operatedand operates substantially all of the Sanish Field Assets through June 30, 2022. On July 1, 2022, Chord Energy Corporation (“Chord”, NASDAQ: CHRD) announced the successful completion of the combination of Whiting and Oasis. The Partnership has not experienced any disruption to its normal course business as a result of this transaction, and Chord continues to administer the ongoing drilling program described below in Note 3. Oil and Natural Gas Investments.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.

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 20212022 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 2022March 31, 2023 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2022.2023.

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 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.

ReclassificationsAccounts Receivable and Concentration of Credit Risk

Certain prior periodFor the quarter ended March 31, 2023, the Partnership’s oil, natural gas and NGL sales were through two operators. Substantially all the Partnership’s accounts receivable is due from Chord, the largest operator of the Sanish Field Assets (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, 2023 and December 31, 2022, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible. Chord is the current operator of 99% of the Partnership’s producing properties. All oil and natural gas producing activities of the Partnership are in North Dakota and represent substantially all of the consolidated financial statements have been reclassifiedbusiness 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 conformmake tax payments on behalf of certain non-resident partners. The Partnership has reached a resolution with the state of North Dakota that entails the Partnership making a payment of taxes on behalf of certain non-resident limited partners to the current period presentationstate for the tax years 2021 and 2022. The estimate recorded by the Partnership at December 31, 2022 for this matter of approximately $0.6 million is consistent with no effect on previously reported netthe settlement reached. The Partnership will remit the settlement payment to the state of North Dakota during the second quarter of 2023. The Partnership’s income partners’ equity or cash flows.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.

Net Income Per Common Unit

Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three and nine months ended September 30, 2022.March 31, 2023. As a result, basic and diluted outstanding common units were the same. The Class B units and Incentive Distribution Rights, as defined below, are not included in net income per common unit until such time that it is probable Payout (as discussed in Note 8) will occur.

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.

Since the beginning of 2018, the Partnership has elected to participate in the drilling and completion of 86 new wells in the Sanish field, of which 68 of these 86 wells82 have been completed and were producing at September 30, 2022. The Partnership also has 18 wells that are in-process as of September 30, 2022.March 31, 2023. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 86 wells is approximately $115$119 million, of which approximately $109$117 million was incurred as of September 30, 2022.March 31, 2023.

The Partnership estimates the approximate $5$2 to $8$3 million in capital expenditures to fully pay for its recently-completed wells along with the remaining 18four (4) wells in various stages of drilling and completion will be incurred through the remainderthird quarter of 20222023 based on the best available information regarding current capital investment plans from its operators. However, many factors outside the Partnership’s control make it difficult to predict the amount and timing of capital expenditures, and estimated capital expenditures could be significantly different from amounts actually invested.

Note 4. Debt

Revolving Credit FacilitiesFacility

In November 2017, the Partnership, as the borrower, entered into a loan agreement (the “Simmons Loan Agreement”) between and among the Partnership and Simmons Bank, as administrative agent and the lenders party thereto. Through various amendments, the Simmons Loan Agreement provided for a revolving credit facility (“Simmons Credit Facility”) with a commitment amount of $40 million, subject to borrowing base restrictions, that was to mature on July 31, 2021. The Simmons Credit Facility had an interest rate of 4.25% and outstanding borrowings of $40 million as of May 13, 2021.

On May 13, 2021, the Partnership and its wholly-owned subsidiary, as borrowers, entered into a loan agreement (“BF Loan Agreement”) with BancFirst, as administrative agent for the lenders (the “Lender”), which provides for a revolving credit facility (“BF 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. Total capitalized loan costs were approximately $0.4 million and are being amortized over the life of the BF Credit Facility. Approximately $0.2 million$130,000 of the deferred loan costs remain unamortized as of September 30, 2022; approximately $0.1 millionMarch 31, 2023; these costs are included in Other current assets, net and the other approximate $0.1 million is recorded as Other assets on the Partnership’s consolidated balance sheet. The Partnership also is 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.

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.Partnership’s previous credit facility. Any further advances under the BF Credit Facility are to be used to fund capital expenditures for the development of the Partnership’s undrilled acreage. Under the terms of the BF Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The BF Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells.

Under the BF Loan Agreement, the initial borrowing base was $60 million. The Partnership’s borrowing base is reduced by a Monthly Commitment Reduction, which is currently stipulated to be $1 million. Therefore, as of September 30, 2022, the borrowing base was $44 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. TheIn conjunction with the Lender’s March 1, 2023 redetermination analysis, the Partnership and Lender did not make adjustmentsagreed to amend the Partnership’sBF Loan Agreement, which included establishing a fixed borrowing base orof $30 million and eliminating the Monthly Commitment Reduction provision based on its September 1, 2022 redetermination analysis.Reduction. 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 BF 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%.

Also, the BF Loan Agreement requires the Partnership to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production under certain conditions. As amended in August 2022, the Partnership is not required to enter into future hedging transactions as long as the Partnership maintains a BF Credit Facility utilization rate of less than or equal to 20% of the Partnership’s PV-9 (defined as the net present value, discounted at 9% per annum), as calculated by the Lender during the Lender’s scheduled semi-annual redeterminations described above. However, the Partnership must hedge at least 50% of its rolling 12-month projected future production if the Partnership’s utilization of the BF Credit Facility is greater than 20% but less than or equal to 30% of PV-9, 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 30% of PV-9. Based on the Partnership’s utilization of the BF Credit Facility and Lender’s current calculation of PV-9, the Partnership was not subject to any additional hedging requirements under the amended BF Loan Agreement as of September 30, 2022.March 31, 2023.

See Note 7. Risk Management for more information on the Partnership’s risk management program as required under the BF Loan Agreement.

The BF Credit Facility contains prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants include:

The BF Loan Agreement does restrict the Partnership’s ability to pay limited partner distributions if the outstanding balance of the BF Credit Facility is greater than 50% of the lesser of (i) the Maximum Credit Amount or (ii) the current borrowing base (“Restricted Payment Clause”). If the Partnership maintains a credit facility utilization of equal to or less than 50%,As amended in March 2023, the Partnership is permitted to make distributions to its limited partners so long as the Partnership is in compliance with its debt service coverage ratio and no other event of default has occurred. AsThe March 2023 amendment to the BF Loan Agreement eliminated the restriction on the Partnership’s ability to pay limited partner distributions if the outstanding balance of September 30, 2022, the Partnership was in compliance with its debt service coverage ratio; however, its outstanding balanceBF Credit Facility was greater than 50% of the current borrowing base. In September 2022,lesser of (i) the Lender agreed to waive the Restricted Payment Clause for the months of September 2022, October 2022 and November 2022; therefore, the Partnership will be permitted to make distributions to its limited partners for those months even if the Partnership’s utilization of its credit facility exceeds 50% ofMaximum Credit Amount or (ii) the current borrowing base.

At September 30, 2022,March 31, 2023, the outstanding balance on the BF Credit Facility was approximately $29.1$18.5 million, and the interest rate was 6.75%8.50%. Due to the maturity date being within one year from March 31, 2023, the BF Credit Facility is now classified as a current liability on the Partnership’s consolidated balance sheet. This reclassification resulted in the Partnership not meeting the minimum ratio of current assets to current liabilities financial covenant. The Lender has waived the covenant violation, and the Partnership was in compliance with its applicableremaining covenants at September 30, 2022.March 31, 2023.

At September 30, 2022March 31, 2023 and December 31, 2021,2022, the outstanding balances on the BF Credit Facility of approximately $29.1$18.5 million and $23.0$22.6 million, respectively, approximated the fair market value of the BF Credit Facility. The Partnership estimated the fair value of its credit facility by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity.

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:

Note 6. Fair Value of Financial Instruments

The Partnership follows authoritative guidance related to fair value measurement and disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement using market participant assumptions at the measurement date. Categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The three levels are defined as follows:

The Partnership’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and the consideration of factors specific to the asset or liability. The Partnership’s policy is to recognize transfers in or out of a fair value hierarchy as of the end of the reporting period for which the event or change in circumstances caused the transfer. The Partnership has consistently applied the valuation techniques discussed above for all periods presented. During the ninethree months ended September 30,March 31, 2023 and 2022, and 2021, there were no transfers in or out of Level 1, Level 2, or Level 3 assets and liabilities measured on a recurring basis.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2022March 31, 2023 and December 31, 2021.2022.

The Level 2 instruments presented in the table above consist of Partnership’s costless collar commodity derivative instruments. The fair value of the Partnership’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroboratedthings, using various methodologies and significant observable inputs. The fair value of the commodity derivatives noted above are included in the Partnership’s consolidated balance sheet at September 30, 2022March 31, 2023 and December 31, 2021.2022. See additional detail in Note 7. Risk Management.

Fair Value of Other Financial Instruments

The carrying value of the Partnership’s other financial instruments, including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments.

Note 7. Risk Management

Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. Therefore, the Partnership periodically 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 amended Simmons Loan 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. In July 2021, the Partnership began its risk management program required under the BF Loan Agreement (see Note 4. Debt) by entering into costless collar derivative contracts for the period from July 2021 to September 2023. The Partnership generally uses costless collar derivative contracts, which establish floor and ceiling prices on future anticipated production. The Partnership did not pay or receive a premium related to the costless collars into which it entered to remain compliant with each loan agreement, and the contracts will be settled monthly.

As of September 30,March 31, 2023 and December 31, 2022, the Partnership’s derivative instruments were in a loss position. The Partnership recognized a current Derivative liability of approximately $3.9$1.3 million and $3.2 million on the Partnership’s consolidated balance sheet. As of December 31, 2021, the Partnership’s derivative instruments were also in a loss position; therefore, the Partnership recognized total liabilities of approximately $2.4 million, of which $1.3 million was recorded as current in Derivative liability and $1.1 million was recorded as Derivative liability – noncurrent on the Partnership’s consolidated balance sheet.sheets.

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 following table presents the settlement losses of matured derivative instruments and non-cash mark-to-market gains (losses) for the periods presented.

Settlements on matured derivatives above reflect realized 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, unrealized) gains or losses above represent the change in fair value of derivative instruments which were held at period-end. Unrealized gains or losses do not represent actual settlements or payments made to or from the counterparty.

The table below summarizes the Partnership’s outstanding derivative contracts (costless collars – purchased put options and written call options) on the Partnership’s future oil and natural gas production.

The Partnership’s outstanding derivative instruments are covered by International Swap Dealers Association Master Agreements (“ISDA”) entered into with the counterparty. The ISDA may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately. The Partnership has netting arrangements with its counterparties that provide for offsetting payables against receivables from separate derivative instruments. The use of derivative instruments involves the risk that the Partnership’s counterparty will be unable to meet the financial terms of such instruments.

Note 8. Capital Contribution and Partners’ Equity

At inception, the General Partner and organizational limited partner made initial capital contributions totaling $1,000 to the Partnership. Upon closing of the minimum offering, the organizational limited partner withdrew its initial capital contribution of $990, and the General Partner received Incentive Distribution Rights (defined below).

The Partnership completed its best-efforts offering of common units on April 24, 2017. As of the conclusion of the offering on April 24, 2017, the Partnership had completed the sale of approximately 19.0 million common units for total gross proceeds of $374.2 million and proceeds net of offering 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:

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.

InFor the three months ended March 2020, the General Partner approved the suspension of distributions to limited partners of31, 2023, the Partnership paid distributions of $0.375753 per common unit, or $7.1 million. In addition, the Partnership declared a monthly cash distribution to its holders of common units of $0.12 per common unit for the month of March 2023. The declared distribution of approximately $2.3 million, which is included in response to market volatility caused by the onset of the COVID-19 pandemicAccounts payable and the impactaccrued expenses on the Partnership’s operating cash flows. Further,balance sheet as of March 31, 2023, was paid on April 5, 2023 to the Partnership was restricted in making distributions to limited partners under the Simmons Loan Agreement and BF Loan Agreement (both described above) until certain conditions within those credit agreements had been met. In November 2021, the Partnership successfully met the required conditions under the BF Loan Agreement to resume distributions to limited partners. Subsequently, the General Partner approved a partial distribution in November 2021 and has paid full monthly distributions in December 2021 through September 2022. common unit holders on record as of March 31, 2023.

For the three and nine months ended September 30,March 31, 2022, the Partnership paid distributions of $0.375891 and $1.047123,$0.322191 per common unit, or $7.1 million and $19.9 million, respectively.

As described in Note 4. Debt, the Partnership was in compliance with its debt service coverage ratio at September 30, 2022, but the outstanding balance on the BF Credit Facility was greater than 50% of the current borrowing base. In September 2022, the Lender waived the restriction on Partnership distributions to its limited partners for the months of September 2022, October 2022 and November 2022, even if the Partnership’s utilization of its credit facility exceeds 50% of the current borrowing base. If the Partnership is not able to reduce its utilization of the BF Credit Facility by the end of the waiver period (and maintain compliance with its debt service coverage ratio), it may not be able to obtain similar waivers from the Lender and future distributions to limited partners may be restricted.$6.1 million.

The Partnership accumulates unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are required to be paid before final Payout occurs, as defined above. As of September 30, 2022,March 31, 2023, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.387671 per common unit, or approximately $45 million.

Note 9. Related Parties

The members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer and 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 and nine months ended September 30,March 31, 2023 and 2022, approximately $32,000$41,000 and $108,000$37,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At September 30, 2022,March 31, 2023, approximately $32,000$41,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses on the consolidated balance sheet. For the three and nine months ended September 30, 2021, approximately $29,000 and $91,000 of general and administrative costs were incurred by a member of the General Partner and have been reimbursed by the Partnership.

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 provideswas to provide administrative, operating and professional services necessary and useful to the Partnership. The Administrator also assistswas to assist the General Partner with the day-to-day operations of the Partnership. The ASA became 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 ER12 ceases to own its respective oil and natural gas assets. Provided the ASA is notwas 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.

on April 5, 2023 (see more details below in Note 10. Subsequent Events). Costs and expenses attributable to the services performed by the Administrator under the ASA will behave been reimbursed by the Partnership. All Administrator costs and expenses will bewere 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,included, but arewere 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, maywere not be incurred by the Administrator on behalf of the Partnership without prior express written consent of the Partnership. For the three and nine months ended September 30,March 31, 2023 and 2022, approximately $149,000$132,000 and $423,000, respectively, of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator. For the three and nine months ended September 30, 2021, approximately $129,000 and $420,000,$140,000, respectively, of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator.

UnderAlso under the ASA, the Administrator will also assistassisted 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 paypaid 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.Anthony F. Keating, III and Mallick.Michael J. Mallick, the former Co-Chief Operating Officers of the General Partner.

Note 10. Subsequent Events

In October 2022,On April 5, 2023, the Partnership declared and ER12 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 affiliates of Messrs. Keating and Mallick sold (i) all interests in the General Partner; (ii) all common unit interests in the Partnership; (iii) all Class B Unit interests in the Partnership; and (iv) their Class B Unit interests in ER12’s General Partner to an affiliate of Mr. Knight and withdrew as members of General Partner and ER12’s General Partner. Pursuant to the Agreement, each of Messrs. Keating and Mallick resigned their positions as director and as Co-Chief Operating Officer of the General Partner. Additionally, Clifford J. Merritt resigned as President of the General Partner. Also 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 ER12 management. During the transition period, the Administrator has been reimbursed by the Partnership for approximately $32,000 in costs and expenses subject to the ASA, and any remaining costs and expenses that may be reimbursed are anticipated to be immaterial.

In April 2023, the Partnership paid $2.0approximately $2.3 million, or $0.107397$0.12 per outstanding common unit, in distributions to its holders of common units.

In April 2023, the Partnership declared a monthly cash distribution to its holders of common units of $0.11 per outstanding common unit for the month of April 2023. The distribution of approximately $2.1 million was paid on May 3, 2023 to common unit holders on record as of April 30, 2023.

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, 20212022 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, 2021.2022.

Overview

The Partnership was formed as a Delaware limited partnership. The general partner is Energy 11 GP, LLC (the “General Partner”). The initial capitalization of the Partnership of $1,000 occurred on July 9, 2013. The Partnership began offering common units of limited partner interest (the “common units”) on a best-efforts basis on January 22, 2015, the date the Partnership’s initial Registration Statement on Form S-1 (File No. 333-197476) was declared effective by the SEC. The Partnership completed its best-efforts offering on April 24, 2017. Total common units sold were approximately 19.0 million for gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million.

The Partnership has no officers, directors or employees. Instead, 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 was formed to acquire and develop oil and gas properties located onshore in the United States. 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.

Since the beginning of 2018, the Partnership has elected to participate in the drilling and completion of 86 new wells in the Sanish field, under a drilling program administered primarily by Whiting Petroleum Corporation (“Whiting”). As of September 30, 2022, approximately 68 of these 86 wellswhich 82 have been completed and were producing.producing as of March 31, 2023. The Partnership also has 18four (4) wells that are in-process as of September 30, 2022.March 31, 2023 that are anticipated to be completed during the second quarter of 2023. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 86 wells is approximately $115$119 million, of which approximately $109$117 million had been incurred as of September 30, 2022.March 31, 2023. See additional detail in “Oil and Natural Gas Properties” below.

As a result of its acquisitions and completed drilling during the period of ownership, as of September 30, 2022,March 31, 2023, the Partnership owned an approximate 25%24% non-operated working interest in 281295 producing wells, an estimated approximate 17%14% non-operated working interest in 18four 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”).

Chord Energy Corporation (“Chord”, NASDAQ: CHRD), the product of a merger between Whiting Petroleum Corporation and Oasis Petroleum Inc. (“Oasis”), twois one of the largest producers in the Williston basin of North Dakota, operatedand operates substantially all of the Sanish Field Assets through June 30, 2022. On July 1, 2022, Chord Energy Corporation (“Chord”, NASDAQ: CHRD) announced the successful completion of the combination of Whiting and Oasis. The Partnership has not experienced any disruption to its normal course business as a result of this transaction, and Chord continues to administer the ongoing drilling program described above.Assets.

Current Price Environment

Oil, natural gas and natural gas liquids 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 in 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.

Commodity prices strengthened throughout 2021, primarily driven by increased demand resulting from the initial recovery from the COVID-19 pandemic and production restraint by domestic and foreign operators. The ongoing military conflict between Russia and Ukraine and related economic sanctions imposed on Russia along with additional production growth by OPEC have further exacerbated supply shortages, causing oil prices to increase even morepeak at over $120 per barrel during the second quarter of 2022. Commodity prices fell through the second half of 2022, with oil prices predominantly ranging between $70 and $80 per barrel during 2023. A mild winter and ample supply have driven natural gas prices down during the first nine monthsquarter of 2022.2023.

The following table lists average NYMEX prices for oil and natural gas for the three and nine months ended September 30, 2022March 31, 2023 and 2021.2022.

The Partnership’s revenues and cash flow from operations are highly sensitive to changes in oil and natural gas prices and to levels of production. 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 sold 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 summarizes the results from operations, including production, of the Partnership’s non-operated working interest for the three and nine months ended September 30, 2022March 31, 2023 and 2021.2022.

Oil, natural gas and NGL revenues

For the three months ended September 30,March 31, 2023, revenues from oil, natural gas and NGL sales were $28.4 million. Revenues for the sale of crude oil were $25.0 million, which resulted in a realized price of $76.48 per barrel. Revenues for the sale of natural gas were $1.5 million, which resulted in a realized price of $3.91 per Mcf. Revenues for the sale of NGLs were $1.9 million, which resulted in a realized price of $33.10 per BOE of sold production. For the three months ended March 31, 2022, revenues from oil, natural gas and NGL sales were $33.0$25.5 million. Revenues for the sale of crude oil were $27.8$21.4 million, which resulted in a realized price of $89.79$89.92 per barrel. Revenues for the sale of natural gas were $2.9$1.9 million, which resulted in a realized price of $7.82$5.83 per Mcf. Revenues for the sale of NGLs were $2.3$2.2 million, which resulted in a realized price of $43.26 per BOE of sold production. For the three months ended September 30, 2021, revenues from oil, natural gas and NGL sales were $21.0 million. Revenues for the sale of crude oil were $17.9 million, which resulted in a realized price of $64.74 per barrel. Revenues for the sale of natural gas were $1.3 million, which resulted in a realized price of $4.56 per Mcf. Revenues for the sale of NGLs were $1.8 million, which resulted in a realized price of $46.44 per BOE of sold production.

For the nine months ended September 30, 2022, revenues from oil, natural gas and NGL sales were $82.9 million. Revenues for the sale of crude oil were $69.3 million, which resulted in a realized price of $93.86 per barrel. Revenues for the sale of natural gas were $6.9 million, which resulted in a realized price of $7.04 per Mcf. Revenues for the sale of NGLs were $6.7 million, which resulted in a realized price of $50.41 per BOE of sold production. For the nine months ended September 30, 2021, revenues from oil, natural gas and NGL sales were $48.5 million. Revenues for the sale of crude oil were $40.4 million, which resulted in a realized price of $59.54 per barrel. Revenues for the sale of natural gas were $3.6 million, which resulted in a realized price of $4.40 per Mcf. Revenues for the sale of NGLs were $4.5 million, which resulted in a realized price of $39.06$52.39 per BOE of sold production.

The Partnership’s results for the three and nine months ended September 30, 2022March 31, 2023 were positively impacted by the significantrecent completion of thirteen (13) new wells that were turned to sales during the fourth quarter of 2022. The Partnership owns an approximate 17% in these 13 wells. The completion of these new wells provided an increase to first quarter 2023 production, with sold production for the Sanish Field Assets approximating 4,900 BOE per day for the three months ended March 31, 2023. Sold production was approximately 3,700 BOE per day for three months ended March 31, 2022.

The increase in sold production volumes were offset by decreases in market prices of oil and natural gas when compared to the same periodsperiod of 2021. In addition, the Partnership continues to benefit from the easing of market imbalances and supply chain constraints that developed during the spring and summer of 2020 due to COVID-19, realized through reduced differentials (see below).2022. The Partnership’s realized sales prices for NGLs are influenced by the components extracted, including ethane, propane and butane and natural gasoline, among others, and the respective market pricing for each component.

The Partnership has completed 62 new wells since the fourth quarter of 2019, of which 40 were completed and turned to sales during the second quarter of 2021 through the third quarter of 2022. Sold production volumes increased when comparing the three- and nine-month periods ended September 30, 2022 and 2021, as production from newly-completed wells has exceeded the natural production declines as wells age. The Partnership has already seen an immediate boost in production during the third quarter of 2022 in conjunction with the recent completion of 16 wells, and the Partnership anticipates its sold production volumes will continue to improve as the remaining 18 wells in process are completed. Sold production for the Sanish Field Assets was approximately 4,600 BOE and 3,800 BOE per day for the three and nine months ended September 30, 2022, respectively, while sold production for the Sanish Field Assets was approximately 3,900 BOE and 3,400 BOE per day for the three and nine months ended September 30, 2021.

If the operators of the Sanish Field Assets are unable to produce, process and sell oil and natural gas at economical prices, these operators may curtail daily production, shut-in producing wells or seek other cost-cutting measures, and could continue so long as producing is uneconomical. Consequently, any of these measures could significantly impact the Partnership’s oil, natural gas and NGL production. Further, production is dependent on the investment in existing wells and the development of new wells. See further discussion of the Partnership’s investment in new wells in “Liquidity and Capital Resources” below.

Oil 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 Sanish field. Oil price differentials to the NYMEX benchmark price vary by operator based upon operator-specific contracts. Due to improvement in commodity prices and market-specific conditions in the Bakken along with the adjusted transportation contracts at Chord, oil price differentials were approximately 60-80%over 100% less during the three and nine months ended September 30, 2022March 31, 2023 than those of the same periodsfirst quarter ended March 31, 2022 and the year ended December 31, 2022, respectively. The Partnership anticipates differentials will remain favorable to benchmark pricing under the new transportation contracts of 2021, respectively.its primary operator during 2023.

In July 2020, the U.S. District Court for D.C. (“D.C. District Court”) ruled that the Dakota Access Pipeline, a significant pipeline that transports oil and natural gas from North Dakota fields, must suspend operations due to inadequate environmental review previously performed by the U.S. Army Corps of Engineers. In August 2020, the ruling was stayed on appeal by the U.S. Court of Appeals for the D.C. Circuit (“D.C. Appellate Court”), allowing the pipeline to operate until a further ruling was made. In January 2021, the D.C. Appellate Court affirmed the D.C. District Court’s decision. Further, in May 2021, the D.C. District Court denied an injunction that would have required a shutdown of the Dakota Access Pipeline while the U.S. Army Corps of Engineers completes its comprehensive environmental review. In June 2021, the D.C. District Court dismissed the existing claims against the Dakota Access Pipeline and its operators, but stated the plaintiffs could renew challenges against the pipeline after the U.S. Army Corps of Engineers releases its environmental review report. In February 2022, the United States Supreme Court declined to take a case brought by the Dakota Access Pipeline operators that challenged the requirement of an updated environmental review as upheld by lower courts. The U.S. Army Corps of Engineers report has yet to be issued, but is anticipated to be completed byduring the endspring of 2022.2023. If use of the Dakota Access Pipeline or any other region pipelines is 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 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 contract in effect for the extraction, transportation, treatment and marketing of oil and natural gas.

For the three months ended September 30,March 31, 2023 and 2022, and 2021, production expenses were $4.4$6.7 million and $2.7$4.7 million, respectively, and production expenses per BOE of sold production were $10.38$15.04 and $7.59,$13.97, respectively. ForIn conjunction with the nine months ended September 30, 2022,improved differentials discussed above, the result of Chord’s adjusted contracts led to higher gathering and processing expenses tied to oil production expensesin the first quarter of 2023 that previously were $12.8 millionincorporated into the Partnership’s realized oil differential. The increase in oil gathering and $8.3 million, respectively, andprocessing costs contributed to higher production expenses per BOE for the three months of sold production were $12.40March 31, 2023. The increase in gathering and $8.89, respectively. Productionprocessing expenses per BOE increased in the three and nine months ended September 30, 2022, in comparison to the same periods of 2021, as a result of (i) a rise in lease operating costs due to inflation; (ii) an increase in workover expenses as certain of the Partnership’s existing wells have required additional maintenance and/or rework to either maintain production efficiency or return to full production, and (iii) an increase in total gathering, processing and selling costs associated with the increased sale of the Partnership’s natural gas and NGL production. The production costs specific to the processing, treating and marketing of natural gas and NGLs are higher than those associated with oil, sowas offset by an increase in sold natural gas and NGLs (in proportion to total sold volumes) results in a greater increase in these production expenses per BOE thanvolumes, which increases the corresponding increase in production expenses for new oil production.base over which fixed lease operating costs are spread.

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 September 30,March 31, 2023 and 2022 and 2021 were $2.6$2.2 million (8% of revenue) and $1.7 million (8% of revenue), respectively. Production taxes for the nine months ended September 30, 2022 and 2021 were $6.4 million (8% of revenue) and $3.7$1.9 million (8% of revenue), respectively.

General and administrative expenses

The principal components of general and administrative expense are accounting, legal and consulting fees. General and administrative expenses for the three months ended September 30,March 31, 2023 and 2022 and 2021 were $0.5$0.8 million and $0.3$0.6 million, respectively. General and administrative expenses for the nine months ended September 30, 2022 and 2021 were $1.6 million and $1.2 million, respectively.

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. DD&A for the three months ended September 30,March 31, 2023 and 2022 and 2021 was $5.8$6.6 million and $6.5$5.4 million, and DD&A per BOE of sold production was $13.63$14.80 and $18.08, respectively. DD&A for the nine months ended September 30, 2022 and 2021 was $14.9 million and $16.4 million, and DD&A per BOE of sold production was $14.35 and $17.62,$16.28, respectively. The decrease in DD&A expense per BOE of production in the first nine monthsquarter of 20222023 is primarily due to the increase of the Partnership’s estimated proved undeveloped reserves during the most recent reserves analyses (as of December 31, 2021 and June 30, 2022) resulting from changes in the future drill schedule.

Gain (loss) on derivatives, net

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 Partnership’s previous credit facility, 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. In July 2021, the Partnership began its risk management program required under the BancFirst Loan Agreement by entering into costless collar derivative contracts for the period from July 2021 to September 2023.

The Partnership did not designate its 20212022 or 20222023 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 following table presents settlements of its matured derivative instruments and the non-cash, mark-to-market gains or losses recorded during the periods presented.

The Partnership’s oil production contracts that expired during the three months ended September 30, 2022March 31, 2023 represented approximately 81,00075,000 barrels of oil. The Partnership realized a loss of approximately $1.6 million, equating to an approximate loss of $19.56 per barrel, on its hedged oil production, and an approximate loss of $5.11 per barrel of total sold oil production for the third quarter of 2022. The Partnership’s natural gas production contracts that expired during the three months ended September 30, 2022 represented 90,000 MMBtu of produced natural gas. The Partnership realized a loss of approximately $0.3 million, equating to an approximate loss of $3.81 per MMBtu, on its hedged natural gas production, and an approximate loss $0.93 per MMBtu of total sold natural gas production for the third quarter of 2022.

The Partnership’s oil production contracts that expired during the nine months ended September 30, 2022 represented approximately 254,000 barrels of oil. The Partnership realized a loss of approximately $5.2 million, equating to an approximate loss of $20.62$4.13 per barrel, on its hedged oil production, and an approximate loss of $7.10$0.95 per barrel of total sold oil production throughfor the first three quartersquarter of 2022.2023. The Partnership’s natural gas production contracts that expired during the ninethree months ended September 30, 2022March 31, 2023 represented 290,00090,000 MMBtu of produced natural gas. The Partnership realized a loss of approximately $0.4 million, equating to an approximate loss of $1.39 per MMBtu, on its hedgedgas; however, these natural gas production contracts were settled at no cost or benefit to the Partnership, as contract prices on settlement dates were within the established floor and an approximate loss $0.41 per MMBtu of total sold natural gas production through the first three quarters of 2022.ceiling prices.

The Partnership’s oil production contracts that expired during the three months ended September 30, 2021March 31, 2022 represented approximately 99,000 barrels of oil. These oil production contracts were settled at no cost or benefit to the Partnership, as the contract prices on the dates of settlement were within the established floor and ceiling prices. The Partnership’s oil production contracts that expired during the nine months ended September 30, 2021 represented approximately 204,00088,000 barrels of oil. The Partnership’s realized loss of approximately $1.2 million equated to an approximate loss of $5.80$14.16 per barrel of hedged oil production, and an approximate loss of $1.74$5.23 per barrel of total sold oil production for the nine months ended September 30, 2021.first quarter of 2022. The Partnership’s natural gas production contracts that expired during the three and nine months ended September 30, 2021first quarter of 2022 represented 120,000 MMBtu and 240,000110,000 MMBtu of produced natural gas, respectively;gas; however, these natural gas production contracts were settled at no cost or benefit to the Partnership, as the contract priceprices on the date of settlement wasdates were within the established floor and ceiling prices.

The mark-to-market (non-cash, unrealized) gains or losses recorded for the three and nine months ended September 30,March 31, 2023 and 2022 and 2021 represent the change in fair value of the Partnership’s derivative instruments held at period-end. Unrealized gains and losses do not represent actual settlements or payments made to or from the counterparty.

The table below summarizes the Partnership’s outstanding derivative contracts (costless collars – purchased put options and written call options) on the Partnership’s future oil and natural gas production.

Interest expense, net

Interest expense, net, for the three months ended September 30,March 31, 2023 and 2022 was $0.5 million and 2021 was $0.4$0.3 million, in both periods.respectively. The Partnership’s interest expense forincreased in the thirdfirst quarter of 2023, compared to the first quarter of 2022, did increase from the first half of 2022primarily due to an increase in borrowings on its BF Credit Facility as well as an increase in interest rates. Interest expense, net, for the nine months ended September 30, 2022 and 2021 was $0.9 million and $1.5 million, respectively.

The primary component of Interest expense, net, during the three- and nine-month periods ended September 30, 2022 wasis interest expense on the BF Credit Facility. The primary component of Interest expense, net, during the three- and nine-month periods ended September 30, 2021 was interest expense on the BF Credit Facility, the Simmons Credit Facility (paid in full in May 2021) and a related-party term loan (paid in full in March 2021).

Supplemental Non-GAAP Measure

The Partnership uses “Adjusted EBITDAX”, defined as earnings before (i) interest expense, net; (ii) income taxes; (iii) depreciation, depletion, amortization and accretion; (iv) exploration expenses; and (v) (gain)/loss on the mark-to-market of derivative instruments, as a key supplemental measure of its operating performance. This non-GAAP financial measure should be considered along with, but not as alternatives 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 terms exactly as the Partnership defines such terms, 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 and nine months ended September 30, 2022March 31, 2023 and 2021.2022.

Liquidity and Capital Resources

Historically, the Partnership’s principal sources of liquidity have been cash on hand, the cash flow generated from the Sanish Field Assets, and availability under the Partnership’s revolving credit facility, if any. As of April 30, 2023, the Partnership had approximately $1.2 million in cash-on-hand. The Partnership generated approximately $43.5$74.7 million in cash flow from operating activities for the year ended December 31, 20212022 and approximately $49.5$16.2 million in cash flow from operating activities for the ninethree months ended September 30, 2022.March 31, 2023. In May 2021,conjunction with BancFirst’s semi-annual borrowing base redetermination process completed in March 2023, the BF Loan Agreement was amended, of which changes included a reduction in the Partnership’s borrowing base to a fixed $30 million. The Partnership successfully refinancedhas approximately $18 million in availability under its existing Simmons Bank credit facility and usedat the initial closing proceedstime of approximately $40 million from the refinancing with BancFirst to fully repay the outstanding balance on the Simmons credit facility. From May 2021 through June 2022, the Partnership made principal payments on the BF Credit Facilityfiling of approximately $24 million using excess cash flow from operations.this Form 10-Q.

The Partnership has incurred approximately $41.2 million in year-to-date capital expenditures through September 30, 2022 on new well investment. As of September 30, 2022, approximately 62 ofa result, the 80 wells in the Partnership’s current and ongoing drilling program have been completed and were producing, but the Partnership was only receiving revenue proceeds from 46 of the 62 completed wells. For non-operator, working-interest owners in oil and natural gas wells like the Partnership, there is a delay between when capital is invested to drill new wells and when the cash is actually received, as operators are permitted a grace period under the joint operating agreements that govern the operator and working interest owner relationship. Specific to the Partnership, to bridge the time gap from investment to incremental operational cash flow from the 16 wells not yet being paid out by its operator, the Partnership borrowed approximately $13 million on its credit facility during the third quarter of 2022 to pay its capital obligations as they became due under the drilling program. The Partnership made a principal payment on the BF Credit Facility of approximately $4 million in November 2022 and anticipates the receipt of incremental cash flow generated by newly-completed wells will allow the Partnership to make additional principal payments to reduce the utilization of the effective borrowing base below 50%. At the time of filing this Form 10-Q, the Partnership’s outstanding balance of its BF Credit Facility was approximately $26 million.

The Partnership anticipates its cash on-hand, cash flow from operations and availability under the BF 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. In addition, the Partnership’s ability to make distributions to its limited partners is contingent on remaining compliant with all applicable covenants under theMarch 2023 BF Credit Facility as well as ensuring the outstanding balance of the BF Credit Facility is at or below 50% of the Partnership’s current borrowing base (“Restricted Payment Clause”). The borrowings made in the third quarter of 2022 on the credit facility increased the Partnership’s utilization of its credit facility to a level that exceeds 50% of the Partnership’s current borrowing base. In September 2022, the lender group for the BF Credit Facility waivedLoan Agreement amendment eliminated the Restricted Payment Clause on Partnership distributions to its limited partners forwithin the months of September 2022, October 2022 and November 2022, even if the Partnership’s utilization of its credit facility exceeds 50% of the current borrowing base. Ifloan agreement, whereby the Partnership is not able to reduce its utilization of the BF Credit Facility by the end of the waiver period (and maintain compliance with its other required covenants), it may not be able to obtain similar waivers from the Lender and futurenow make distributions to limited partners may be restricted.regardless of BF Credit Facility utilization so long as the Partnership is in compliance with the applicable covenants and no other event of default has occurred. Therefore, the General Partner will monitor payment of future monthly Partnership distributions in conjunction with the Partnership’s projected cash requirements for operations, payments on the BancFirst credit facility and capital expenditures for new wells.

The Partnership’s revenues and cash flow from operations are highly sensitive to changes in oil and natural gas prices and to levels of production. If commodity prices significantly drop, such as the decline in the second quarter of 2020, and remain low, 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 participate in future drilling programs as proposed by the operators of the Sanish Field Assets and/or to fund any future distributions to its limited partners. 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.

Financing

See further discussion of the Partnership’s BF Credit Facility in “Note 4. Debt” in Part I, Item 1 of this Form 10-Q.

Partners’ Equity

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 sold approximately 19.0 million common units for total gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million.

Under the agreement with 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 in the offering, the total contingent fee is a maximum of approximately $15.0 million, which will only be paid if Payout occurs, as defined in “Note 8. Capital Contribution and Partners’ Equity” in Part I, Item 1 of this Form 10-Q.