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 NovemberAugust 12, 2021,2022, 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

SeptemberJune 30, 20212022

(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 SeptemberJune 30, 2021,2022, the Partnership owned an approximate 25% non-operated working interest in 264269 producing wells, an estimated approximate 20%21% non-operated working interest in 1427 wells in various stages of the drilling and completion process and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”).

Whiting Petroleum Corporation (“Whiting”) (NYSE: WLL) operatesand Oasis Petroleum Inc. (“Oasis”), two of the largest producers in the Williston basin of North Dakota, operated substantially all of the Sanish Field Assets.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 anticipates minimal disruption to its normal course business as a result of this transaction, and Chord will continue to administer the ongoing drilling program described below in Note 3. Oil and Natural Gas Investments.

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 20202021 Annual Report on Form 10-K. Operating results for the three and ninesix months ended SeptemberJune 30, 20212022 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2021.2022.

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.

Net Income (Loss) Per Common Unit

Basic net income (loss) per common unit is computed as net income (loss) divided by the weighted average number of common units outstanding during the period. Diluted net income (loss) per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three and ninesix months ended SeptemberJune 30, 2021 and 2020.2022. 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 (loss) 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.

During 2018, 6 wells were completed by the Partnership’s operators. In total, the Partnership’s capital expenditures for the drilling and completion of these six wells were approximately $7.8 million.

Since the beginning of 2019,2018, the Partnership has elected to participate in the drilling and completion of 5784 new wells in the Sanish field. NaN (43)(56) of these 5784 wells have been completed and were producing at SeptemberJune 30, 2021; the Partnership has an approximate non-operated working interest of 21% in these 43 wells.2022. The Partnership has an estimated approximate non-operated working interest of 20% in 827 wells that are in-process as of SeptemberJune 30, 2021. The Partnership has an estimated approximate non-operated working interest2022 and expects 1 additional well to commence drilling during the third quarter of 20% in 6 wells that had not commenced drilling as of September 30, 2021.2022. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 5784 wells is approximately $75$108 million, of which approximately $56$95 million was incurred as of SeptemberJune 30, 2021. 2022.

The Partnership estimates the approximate $15$10 to 20$20 million in capital expenditures to completefully pay for its recently-completed wells along with the remaining 1428 wells in various stages of drilling and completion will be incurred overthrough the fourth quarter of 2021 and the first halfremainder of 2022 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 Facilities

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 $0.1 million of the deferred loan costs are recorded as Other current assets, net and the other approximate $0.2$0.1 million in deferred loan costs are recorded as Other assets on the Partnership’s consolidated balance sheet as of SeptemberJune 30, 2021.2022. 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. 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 was initiallyis currently stipulated to be $1 million. Therefore, as of SeptemberJune 30, 2021,2022, the borrowing base was $56$47 million. The borrowing base and Monthly Commitment Reduction are subject to redetermination semi-annually, on March 1 and September 1, based upon the Lender’s analysis of the Partnership’s proven oil and natural gas reserves. The Lender did not make adjustments to the Partnership’s borrowing base or the Monthly Commitment Reduction provision based on its SeptemberMarch 1, 20212022 redetermination analysis. 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, under the BF Loan Agreement requires the Partnership is required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production. Theproduction under certain conditions. As amended in March 2022, the BF Loan Agreement no longer requires the Partnership to enter into future hedging transactions as long as the Partnership maintains a utilization rate of less than or equal to 35% of the current borrowing base on the BF Credit Facility. As of June 30, 2022, the Partnership was not subject to any additional hedging requirements as its utilization rate was less than or equal to 35% of the current borrowing base. However, the Partnership must hedge at least 50% of its rolling 12-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is greater than 35% but less than 50% of the lesser of the (i) Maximum Credit Amount or (ii) current borrowing base, and at least 50% of its rolling 24-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is greater than 50% of the lesser of the (i) Maximum Credit Amount or (ii) current borrowing base.

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 restrictsdoes restrict the Partnership’s ability to pay limited partner distributions untilif the outstanding balance of the BF Credit Facility is equal to or lessgreater than 50% of the lesser of (i) the Maximum Credit Amount or (ii) the current borrowing base, at which pointbase. If the Partnership maintains a credit facility utilization of equal to or less than 50%, the Partnership is permitted to make distributions so long as the Partnership is in compliance with its debt service coverage ratio and no other event of default has occurred. As of June 30, 2022, the Partnership was not subject to this restriction, as (i) the outstanding balance was less than 50% of the current borrowing base and (ii) the Partnership was in compliance with its debt service coverage ratio.

At June 30, 2022, the outstanding balance on the BF Credit Facility was approximately $16.0 million, and the interest rate was 5.25%. The Partnership was in compliance with its applicable covenants at SeptemberJune 30, 2021.2022.

At SeptemberJune 30, 2022 and December 31, 2021, the outstanding balance on the BF Credit Facility was approximately $34$16.0 million and the interest rate was 4.00%. As of September 30, 2021 and December 31, 2020, the outstanding balances on the BF Credit Facility and the Simmons Credit Facility were approximately $34 million and $40$23.0 million, respectively, which approximated the fair market value of each credit facility.the BF Credit Facility. The Partnership estimated the fair value of its credit facilitiesfacility by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity.

Term Loan from Affiliate

On July 21, 2020, the Partnership, as borrower, entered into a loan agreement with GKDML, LLC (“GKDML”), which provided for an unsecured, one-year term loan (“Term Loan” or “Affiliate Loan”) in the amount of $15 million. GKDML is owned and managed by Glade M. Knight and David S. McKenney, the Chief Executive Officer and the Chief Financial Officer, respectively, of the General Partner. The Term Loan was repaid in full during March 2021, and the Partnership did not incur a penalty for prepayment. The Term Loan bore interest at a variable rate based on LIBOR plus a margin of 2.00%, with a LIBOR floor of 0%. Interest was payable monthly.

To provide the proceeds for the Term Loan, GKDML entered into a loan agreement with Bank of America, N.A. on July 21, 2020 (“GKDML Loan”). The GKDML Loan was also repaid in March 2021, had substantially the same terms as the Term Loan and was personally guaranteed by Messrs. Knight and McKenney. GKDML, Mr. Knight and Mr. McKenney did not receive any consideration for providing the Term Loan or guaranty to the GKDML Loan; however, under the Term Loan, the Partnership reimbursed GKDML for all costs of the GKDML Loan.

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 three and ninesix months ended SeptemberJune 30, 20212022 and 2020,2021, 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 SeptemberJune 30, 20212022 and December 31, 2020.2021.

The Level 2 instruments presented in the table above consist of Partnership’s costless collar commodity derivative instruments. The fair value of the Partnership’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The fair value of the commodity derivatives noted above are included in the Partnership’s consolidated balance sheet at SeptemberJune 30, 20212022 and December 31, 2020.2021. See additional detail in Note 7. Risk Management.

Fair Value of Other Financial Instruments

The carrying value of the Partnership’s other financial instruments, including cash and cash equivalents, oil, natural gas and natural gas liquids revenueaccounts receivable, accounts payable and accrued expenses,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 SeptemberJune 30, 2022 and December 31, 2021, the Partnership’s derivative instruments were in a loss position. The Partnership has recognized a total liabilityliabilities of approximately $2.3$10.7 million and $2.4 million, respectively, of which $1.1$8.9 million and $1.3 million, respectively, has been recorded as current in Derivative liability and $1.2$1.9 million and $1.1 million, respectively, has been recorded as Derivative liability – noncurrent on the Partnership’s consolidated balance sheet as of September 30, 2021. The Partnership’s derivative instruments were in a loss position as of December 31, 2020; a current liability of approximately $0.6 million was recognized as Derivative Liability on the Partnership’s consolidated balance sheet as of December 31, 2020. These current and noncurrent derivative liabilities as of September 31, 2021 and December 31, 2020 approximate fair value.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 Partnership’s contracts that expired during the third quarter of 2021 were settled at no cost or benefit to the Partnership, as the contract price on the date of settlement was within the established floor and ceiling prices. The following table presents the settlement gain (loss)losses of matured derivative instruments and non-cash mark-to-market gains (losses) for the periods presented.

Settlements on matured derivatives above reflect realized gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash, 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.

In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to market volatility caused by the onset of the COVID-19 pandemic and the impact on the Partnership’s operating cash flows. Further, 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 June 2022. For the three and six months ended June 30, 2022, the Partnership paid distributions of $0.349041 and $0.671232, or $6.6 million and $12.7 million, respectively.

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 SeptemberJune 30, 2021,2022, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.228493$2.387671 per common unit, or approximately $42 million. As discussed in Note 4. Debt, the Partnership must meet certain conditions under the BF Loan Agreement before distributions to limited partners may resume.

For the nine months ended September 30, 2020, the Partnership paid distributions of $0.241644, or $4.6$45 million.

Note 9. Related Parties

The members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer, David S. McKenney, Chief Financial Officer, Anthony F. Keating, III, Co-Chief Operating Officer and Michael J. Mallick, Co-Chief Operating Officer. Mr. Knight and Mr. McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy Resources 12 GP, LLC, the general partner of Energy Resources 12, L.P. (“ER12”), a limited partnership that also invests in producing and non-producing oil and gas properties on-shore in the United States. Entities owned by Messrs. Keating and Mallick own non-voting, Class B units in the general partner of ER12.

The Partnership has, and is expected to continue to engage in, significant transactions with related parties. These transactions cannot be construed to be at arm’s length and the results of the Partnership’s operations may be different than if conducted with non-related parties. The General Partner’s Board of Directors oversees and reviews the Partnership’s related party relationships and is required to approve any significant modifications to any existing related party transactions, as well as any new significant related party transactions.

For the three and ninesix months ended SeptemberJune 30, 2021,2022, approximately $29,000$39,000 and $91,000$76,000 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 SeptemberJune 30, 2021,2022, approximately $29,000$39,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses on the consolidated balance sheets.sheet. For the three and ninesix months ended SeptemberJune 30, 2020,2021, approximately $101,000$30,000 and $291,000$62,000 of general and administrative costs were incurred by a member of the General Partner and have been reimbursed by the Partnership.

On January 31, 2018, the Partnership entered into a cost sharing agreement with ER12 that gave ER12 access to the Partnership’s personnel and administrative resources, including accounting, asset management and other day-to-day management support. The cost sharing agreement reduced these accounting and asset management costs to the Partnership, as these shared day-to-day costs were split evenly between the two partnerships. The shared costs were based on actual costs incurred with no mark-up or profit to the Partnership. Any other direct third-party costs were paid by the party receiving the services. For the three and nine months ended September 30, 2020, approximately $64,000 and $204,000, respectively, of expenses subject to the cost sharing agreement were incurred by ER12 and have been reimbursed to the Partnership. In October 2020, the cost sharing agreement was terminated by ER12, effective December 31, 2020.

On December 1, 2020, the Partnership entered into an Administrative Services Agreement (the “ASA”) with Regional Energy Investors, L.P. d/b/a Regional Energy Management (the “Administrator”) and ER12, whereby the Administrator will provide administrative, operating and professional services necessary and useful to the Partnership. The Administrator will also assist the General Partner with the day-to-day operations of the Partnership. The ASA isbecame 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 not terminated by any party via 60-day written notice at the conclusion of the Initial Term, the ASA will be automatically renewed for additional one-year periods. If a party to the ASA materially breaches the terms and conditions of the ASA and the breach has not been cured with 30 days of written notification of said breach, the ASA may be terminated with immediate effect.

Costs and expenses attributable to the services performed by the Administrator under the ASA will be reimbursed by the Partnership. All Administrator costs and expenses will be accumulated (based on actual costs incurred with no mark-up or profit to the Administrator) and approved by the Partnership prior to reimbursement. Costs and expenses to be reimbursed under the ASA may include, but are not limited to, employee wages and benefits, rent for office space and network and information technology support. Other expenses, such as business travel costs and accounting, legal or banking services, may not be incurred by the Administrator on behalf of the Partnership without prior express written consent of the Partnership. For the three and ninesix months ended SeptemberJune 30, 2022, approximately $134,000 and $274,000, respectively, of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator. For the three and six months ended June 30, 2021, approximately $129,000$151,000 and $420,000,$291,000, respectively, of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator.

Under the ASA, the Administrator will also assist Energy Resources 12 GP, LLC, the general partner of ER12 (“ER12’s General Partner”), with the day-to-day operations of ER12. ER12 currently pays ER12’s General Partner an annual management fee of 0.5% of the total gross equity proceeds raised by ER12 in its best-efforts offering. Under the ASA, ER12’s General Partner will pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. This fee is only applicable to ER12 and does not apply to the Partnership. The Administrator is owned by entities that are controlled by Messrs. Keating and Mallick.

Note 10. Subsequent Events

During October and November 2021,In July 2022, the Partnership utilized cash available from operations to make principal payments on the BF Credit Facility of $7 million. The effect of these principal payments reduced the outstanding balance on the BF Credit Facility to $27 million. Because the Partnership’s outstanding balance is now at or below 50% of its current borrowing basedeclared and the Partnership is in compliance with its debt covenants under the BF Loan Agreement, the Partnership has met the conditions required by the Lender to resume payment of distributions to its limited partners.

Subsequent to the Partnership meeting the required conditions set forth by the Lender in the BF Loan Agreement, the General Partner approved the resumption of distributions to limited partners for the month of November 2021. On November 24, 2021, the Partnership will pay approximately $1paid $2.5 million, or $0.051781$0.134247 per outstanding common unit, in distributions to its holders of common units.

As of June 30, 2022, the Partnership had approximately $20 million in accrued capital expenditures to its operators related to the drilling program. In addition to using cash flow from operations, the Partnership borrowed approximately $7 million on the BF Credit Facility in July and August to pay its capital obligations under the drilling program as they have become due.

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, 20202021 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, 2020.2021.

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.

As of September 30, 2021, the Partnership owned an approximate 25% non-operated working interest in 264 producing wells, an estimated approximate 20% non-operated working interest in 14 wells in various stages of the drilling and completion process and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). Whiting Petroleum Corporation (“Whiting”) (NYSE: WLL), one of the largest producers in the basin, operates substantially all of the Sanish Field Assets.

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.

During 2018, six wells were completed by the Partnership’s operators. In total, the Partnership’s capital expenditures for the drilling and completion of these six wells were approximately $7.8 million.

Since the beginning of 2019,2018, the Partnership has elected to participate in the drilling and completion of 5784 new wells in the Sanish field. Forty-three (43)field under a drilling program administered primarily by Whiting Petroleum Corporation (“Whiting”). Fifty-six (56) of these 5784 wells have been completed and were producing at SeptemberJune 30, 2021; the Partnership has an approximate non-operated working interest of 21% in these 43 wells.2022. The Partnership has an estimated approximate non-operated working interest of 20% in 827 wells that are in-process as of SeptemberJune 30, 2021. The Partnership has an estimated approximate non-operated working interest2022 and expects one additional well to commence drilling in the third quarter of 20% in six wells that had not commenced drilling as of September 30, 2021.2022. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 5784 wells is approximately $75$108 million, of which approximately $56$95 million washad been incurred as of SeptemberJune 30, 2021.2022. 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 June 30, 2022, the Partnership owned an approximate 25% non-operated working interest in 269 producing wells, an estimated approximate 21% non-operated working interest in 27 wells in various stages of the drilling and completion process and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”).

Whiting and Oasis Petroleum Inc. (“Oasis”), two of the largest producers in the Williston basin of North Dakota, operated 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 anticipates minimal disruption to its normal course business as a result of this transaction, and Chord will continue to administer the ongoing drilling program described above.

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 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.

The outbreak of a novel coronavirus (“COVID-19”) in China in December 2019 significantly impacted the global economy throughout 2020, and the domestic oil and gas industry was especially impacted as demand for oil, natural gas and other hydrocarbons substantially declined, beginning in March and April 2020. In addition toAs government-mandated COVID-19 restrictions eased during the outbreakfourth quarter of COVID-19, Saudi Arabia2020 and Russia, two of the largest worldwide producers of crude oil, engaged in a price war during March and April 2020 that ultimately led to excess crude oil and natural gas inventory and congested supply chain channels, which weighed negatively on commodity prices whileinto 2021, demand was low. Demand for oil and natural gas began to return in the fourth quarter of 2020 as government-mandated COVID-19 restrictions eased. The increased demand and productionreturned. Production restraint by domestic and foreign operators in 2021, havein conjunction with higher worldwide demand during the prolonged recovery from COVID-19, contributed to higher commodity prices withthroughout 2021. The ongoing military conflict between Russia and Ukraine and related economic sanctions imposed on Russia has further exacerbated supply shortages, causing oil prices averaging over $70 per barrelto increase even more during the first half of 2022.

The following table lists average NYMEX prices for oil and natural gas for the third quarter of 2021three and topping $80 per barrel in Octobersix months ended June 30, 2022 and 2021.

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.

The following table lists average NYMEX prices for oil and natural gas for the three and nine months ended September 30, 2021 and 2020. 

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 ninesix months ended SeptemberJune 30, 20212022 and 2020. The effect of the outbreak of COVID-19 during the first and second quarters of 2020 had a significant negative impact to the Partnership’s results from operations; as a result, the periods presented in the table below may not be directly comparable.2021.