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, 20202021

(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, 2020,2021, the Partnership owned an approximate 25% non-operated working interest in 243264 producing wells, an estimated approximate 18%20% non-operated working interest in 2114 wells in various stages of the drilling and completion process and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). Whiting Petroleum Corporation (“Whiting”) (NYSE: WLL) and Oasis Petroleum North America, LLC (“Oasis”) (NYSE: OAS), two of the largest producers in the basin, operateoperates substantially all of the Sanish Field Assets.

The general partner of the Partnership is Energy 11 GP, LLC (the “General Partner”). The General Partner manages and controls the business affairs of the Partnership.

The Partnership’s fiscal year ends on December 31.

Drilling Program, Oil Demand, Current Pricing, Liquidity and Going Concern Considerations

During 2019 and the first quarter of 2020, the Partnership elected to participate in the drilling and completion of 43 new wells in the Sanish field. The Partnership estimates the total investment for these 43 new wells to be approximately $63 million. In conjunction with this drilling program performed primarily by Whiting, the Partnership had incurred approximately $42 million in capital expenditures through September 30, 2020, which was primarily funded by availability under the Partnership’s $40 million revolving credit facility (“Credit Facility”, described in Note 4. Debt). However, the Partnership used all availability under its Credit Facility by March 31, 2020, and as of June 30, 2020, the Partnership had approximately $20 million in accrued operating and capital expenditures due to Whiting. New production from completed wells was expected to enhance the Partnership’s operating performance throughout 2020, providing incremental cash flow from operations to fund the Partnership’s investment in its undrilled acreage.

Subsequent to the Partnership’s election to participate in Whiting’s drilling program, the outbreak of a novel coronavirus (“COVID-19”) in China spread worldwide, forcing governments around the world to take drastic measures to halt the outbreak. These measures included significant restrictions on travel, forced quarantines, stay-at-home requirements and the closure of businesses in many industries for an undetermined period of time, creating extreme volatility in capital markets and the global economy. Because of COVID-19’s impact to the global economy, demand for oil, natural gas and other hydrocarbons substantially declined in March 2020 and has remained depressed through the third quarter of 2020. Demand for oil and natural gas is not anticipated to return to pre-COVID-19 levels during 2020, and the outlook for demand for oil and natural gas in 2021 is uncertain. This reduction in demand compounded an existing excess in supply of oil and natural gas, as the members of the Organization of the Petroleum Exporting Countries (“OPEC”) and Russia could not agree on daily production output of crude oil in March 2020. As a result, Russia announced its intention to increase production, and Saudi Arabia immediately countered with announced reductions to export prices. All of these factors led to oil prices falling in March 2020 and to 20-year lows in April 2020. Although NYMEX oil prices have stabilized around $40 per barrel since June 2020, prices throughout the third quarter of 2020 remained below pre-COVID-19 levels.

In response to lower commodity prices and reduced demand, operators within the United States altered drilling programs and the related forecasted capital expenditures for those programs, and implemented other cost-saving measures, such as curtailing production or shutting in producing wells, during the second quarter of 2020. While operators have since returned significant inventory of existing wells to production, the nature and timing of drilling new wells remains uncertain. These factors have had and are anticipated to continue to have an adverse impact on the Partnership’s business and its financial condition. Due to the impacts to the global oil and gas industry described above, the General Partner approved the suspension of distributions to limited partners of the Partnership in March 2020. Further, Whiting and certain of its subsidiaries declared bankruptcy under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas on April 1, 2020. Subsequent to filing for Chapter 11 protection, Whiting suspended its Sanish field drilling program during the second quarter of 2020, but operated its business in the normal course without material disruption to its vendors, partners or employees, including the Partnership, during the bankruptcy process. Whiting completed its financial restructuring and emerged from bankruptcy protection in September 2020, but has yet to resume its drilling program.

In July 2020, the Partnership entered into a loan agreement for a one year, $15 million term loan (“Affiliate Loan”) that matures on July 21, 2021 (see Note 4. Debt for additional information). The Partnership used proceeds from the Affiliate Loan plus cash on hand to pay the Partnership’s accrued operating and capital expenditures due to Whiting, which totaled approximately $19 million at the time of payment. In addition to the Affiliate Loan, the Partnership entered into a letter agreement (“Letter Agreement”) with its lending group for its Credit Facility. The Letter Agreement, among other items, waived the non-compliance of certain covenants under the Credit Facility; however, the Letter Agreement changed the maturity date of the Credit Facility from September 30, 2022 to July 31, 2021. In October 2020, the Partnership made a principal payment on the Affiliate Loan of $5 million; therefore, the Partnership’s outstanding debt obligations at the date of filing of this Form 10-Q total $50 million and mature within one year of the filing of this Form 10-Q.

The Partnership’s ability to continue as a going concern is dependent on several factors including, but not limited to, (i) the Partnership’s ability to comply with its obligations under its loan agreements (see Note 4. Debt for further discussion); (ii) refinancing its existing debt and/or securing additional capital; (iii) an increase in demand for oil and natural gas as the global economy recovers from the effects of the COVID-19 pandemic and the existing oversupply of oil in the United States; and (iv) an increase in oil and natural gas market prices, which will improve the Partnership’s cash flow generated from operations. The Partnership can provide no assurance that it will be able to achieve any of these objectives. Refinancing its existing debt or securing additional capital may not be available on favorable terms to the Partnership, if it is available at all. There also can be no assurance that economic activity and oil and natural gas market conditions, including commodity prices, will return to pre-COVID-19 levels, or that the Partnership will be able to meet its operational obligations. If the Partnership is unable to refinance or repay its debt obligations or is unable to meet its operational obligations, the Partnership could be required to liquidate certain of its assets used for collateral to satisfy these obligations, which create the substantial doubt that exists about the ability of the Partnership to continue as a going concern for one year after the date these financial statements are issued.

The accompanying financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amounts and classifications of liabilities that may result from the possible inability of the Partnership to continue as a going concern.

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 20192020 Annual Report on Form 10-K. Operating results for the three and nine months ended September 30, 20202021 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2020.2021.

Use of Estimates

The preparation of financial statements in conformity with United States GAAP requires management to make estimates and assumptions that affect the reported amounts in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.

Revenue Recognition

The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Oil, natural gas and natural gas liquids revenueAccounts 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 0no common units with a dilutive effect for the three and nine months ended September 30, 20202021 and 2019.2020. As a result, basic and diluted outstanding common units were the same. The Class B units and Incentive Distribution Rights, as defined below, are not included in net income (loss) per common unit until such time that it is probable Payout (as discussed in Note 8) will occur.

Recently Adopted Accounting Standards

In March 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2020-04, Reference Rate Reform (Topic 848), which provides optional guidance through December 31, 2022 to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments in ASU No. 2020-04 apply to contract modifications that replace a reference rate affected by reference rate reform, providing optional expedients regarding the measurement of hedge effectiveness in hedging relationships that have been modified to replace a reference rate. While the guidance in ASU No. 2020-04 became effective upon issuance, the provisions of the ASU did not have a material impact on the Partnership’s consolidated financial statements and related disclosures as of September 30, 2020.

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. NaN wells were completed by and are being operated by Whiting; the Partnership has an approximate 29% non-operated working interest in these 2 wells. The other 4 wells were completed by and are operated by Oasis; the Partnership has an approximate 8% non-operated working interest in these four wells. In total, the Partnership’s capital expenditures for the drilling and completion of these six wells were approximately $7.8 million.

DuringSince the beginning of 2019, and the first quarter of 2020, the Partnership has elected to participate in the drilling and completion of 4357 new wells in the Sanish field. NaN (22)(43) of these 4357 wells have been completed and were producing at September 30, 2020;2021; the Partnership has an approximate non-operated working interest of 23%21% in these 2243 wells. The Partnership has an estimated approximate non-operated working interest of 18%20% in the remaining 218 wells that are in-process as of September 30, 2020.2021. The Partnership has an estimated approximate non-operated working interest of 20% in 6 wells that had not commenced drilling as of September 30, 2021. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 4357 wells is approximately $63$75 million, of which approximately $42$56 million was incurred as of September 30, 2020. Whiting suspended its Sanish field drilling program during the second quarter of 2020 in response to the significant reduction in demand for oil caused by COVID-19 and the oversupply of oil in the United States.2021. The Partnership estimates it may incur approximately $1the approximate $15 to $220 million in additional capital expenditures duringto complete the remaining 14 wells will be incurred over the fourth quarter of 2020; however, low commodity prices, market supply2021 and demand imbalances and how Whiting’s emergencethe first half of 2022 based on the best available information regarding current capital investment plans from bankruptcy protection in September 2020 impactsits operators. However, many factors outside the resumption of its suspended drilling programPartnership’s control make it difficult to predict the amount and timing of capital expenditures, for the remainder of 2020. Estimatedand estimated capital expenditures could be significantly different from amounts actually invested.

Evaluation for Potential Impairment of Oil and Natural Gas Investments

The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of its oil and gas properties may not be recoverable. The Partnership considered the declines in the current and forecasted operating cash flows resulting from COVID-19 and sustained lower commodity prices to be potential indicators of impairment and, as a result, performed a test of recoverability for the Sanish Field Assets. Estimated future net cash flows calculated in the recoverability test were based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. The underlying commodity prices used in the determination of the Partnership’s estimated future net cash flows were based on NYMEX forward strip prices as of October 1, 2020, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believed will impact realizable prices. Future operating cost estimates were based on actual historical costs of the Sanish Field Assets. The Partnership’s recoverability analyses did not identify any impairment losses as of September 30, 2020.

If current macro-economic conditions continue or worsen, the carrying value of the Partnership’s oil and natural gas properties may not be recoverable and impairment losses could be recorded in future periods.

Note 4. Debt

Revolving Credit FacilityFacilities

OnIn November 21, 2017, the Partnership, as the borrower, entered into a loan agreement (the “Loan“Simmons Loan Agreement”) between and among the Partnership and Simmons Bank, as administrative agent and the lenders party thereto (the “Lender”), whichthereto. 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 initial commitmentmaximum credit amount (“Maximum Credit Amount”) of $20$60 million, subject to borrowing base restrictions. The maturity date was November 21, 2019. Effective September 30, 2019, the Partnership entered into an amendment and restatement of the Loan Agreement (the “Amended Loan Agreement”) with Lender, which provided for the Credit Facility with an approved initial commitment of $40 million (the “Revolver Commitment Amount”), subject to borrowing base restrictions. The terms of the Amended Loan Agreement were generally similar to the Partnership’s existing revolving credit facility and included the following: (i) a maturity date of September 30, 2022; (ii) subject to certain exceptions, an interest rate, which did not change from the existing revolving credit facility, equal to the London Inter-Bank Offered Rate (LIBOR) plus a margin ranging from 2.50% to 3.50%, depending upon the Partnership’s borrowing base utilization, as calculated under the terms of the Amended Loan Agreement; (iii) an increase to the borrowing base from $30 million to an initially stipulated $40 million; and (iv) an increase to the mortgage and lenders’ first lien position from 80% to 90% of the Partnership’s owned producing oil and natural gas properties.

At closing of the Amended Loan Agreement in October 2019, the Partnership paid an origination fee of 0.45%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 million in deferred loan costs are recorded as Other assets on the change in Revolver Commitment AmountPartnership’s consolidated balance sheet as of the Credit Facility (increase from $20 million on previous credit facility to $40 million under revised Credit Facility, or $20 million), or $90,000.September 30, 2021. The Partnership also is also required to pay an annual fee to the Lender of $30,000, and an unused facility fee of 0.50%0.25% on the unused portion of the Revolver Commitment Amount,Revolving Credit Facility, based on the amount of borrowings outstanding during a quarter.

On July 21, 2020, the Partnership entered into a letter agreement (“Letter Agreement”) with Lender that amended and modified the Amended Loan Agreement. The modifications to the Amended Loan Agreement include, among other items, the following:maturity date 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 initially stipulated to be $1 million. Therefore, as of September 30, 2021, the borrowing base was $56 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 September 1, 2021 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 LetterBF Loan Agreement, the Partnership is required to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and natural gas sales.production. The risk management programPartnership must coverhedge at least 80%50% of its rolling 12-month projected future production if the Partnership’s utilization of the Partnership’s projected total productionRevolving Credit Facility is less than 50% of oil and natural gas for the period from August 31, 2020 untillesser of the next(i) Maximum Credit Amount or (ii) current borrowing base, redetermination date (first quarterand at least 50% of 2021).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 hedgingrisk management program in Note 7. Risk Management.

In addition to the modification of certain termsas required under the AmendedBF Loan Agreement, the Letter Agreement waived the defaults by the Partnership under the Amended Loan Agreement that existed prior to signing the Letter Agreement, including not meeting the current ratio covenant as of March 31, 2020, the Partnership not filing its first quarter financial statements within 60 days of March 31, 2020 and the non-payment by the Partnership of amounts due to Whiting. The Letter Agreement also waived the Partnership’s calculation of the current ratio covenant at June 30, 2020. The Letter Agreement also allows for the Affiliate Loan discussed below and payments under the Affiliate Loan.

In consideration for the modifications, amendments and waivers described above to the Amended Loan Agreement, the Letter Agreement provides for an amendment fee to Lender of $40,000, of which $15,000 was paid on September 30, 2020 and $25,000 is due December 31, 2020.Agreement.

The BF Credit Facility contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. Certain of the financial covenants each as defined in the Amended Loan Agreement, include:

The BF Loan Agreement restricts the Partnership’s ability to pay limited partner distributions until the outstanding balance of the BF Credit Facility is equal to or less than 50% of the lesser of (i) the Maximum Credit Amount or (ii) the current borrowing base, at which point the Partnership is permitted to make distributions so long as the Partnership is in compliance with its debt service coverage ratio and no other event of default has occurred.

The Partnership was in compliance with its applicable covenants at September 30, 2020. If the Partnership is not in compliance with its covenants in future periods, it may not be able to obtain waivers and the outstanding balance under the Credit Facility may become due on demand at that time.2021.

At September 30, 2020,2021, the outstanding balance on the BF Credit Facility was $40approximately $34 million, and the interest rate for the Credit Facility was 4.25%4.00%. As of September 30, 20202021 and December 31, 2019,2020, the outstanding balances on the BF Credit Facility and the Simmons Credit Facility were $40approximately $34 million and $24$40 million, respectively, which approximateapproximated the fair market value.value of each credit facility. The Partnership estimated the fair value of its Credit Facilitycredit facilities 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 providesprovided 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 bearswas 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 iswas payable monthly. The Term Loan contains mandatory prepayment requirements, customary affirmative and negative covenants and events of default. At September 30, 2020, the outstanding balance on the Term Loan was $15 million, the interest rate for the Term Loan was approximately 2.2% and the Partnership was in compliance of all applicable covenants.

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 haswas also repaid in March 2021, had substantially the same terms as the Term Loan and iswas personally guaranteed by Messrs. Knight and McKenney. GKDML, Mr. Knight and Mr. McKenney have not and willdid not receive any consideration for providing the Term Loan or guaranty to the GKDML Loan; however, under the Term Loan, the Partnership is required to reimbursereimbursed GKDML for all costs of the GKDML Loan. The Term Loan may be prepaid at any time with no penalty and in any amount, but any amounts repaid may not be reborrowed. 

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 nine months ended September 30, 20202021 and 2019,2020, 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, 20202021 and December 31, 2019.2020.

The Level 2 instruments presented in the table above consist of Partnership’s costless collar commodity derivative instruments. The fair value of the Partnership’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The fair value of the commodity derivatives noted above are included in the Partnership’s consolidated balance sheet in Other current assets at September 30, 20202021 and Accounts payable, accrued expenses and other current liabilities at December 31, 2019.2020. See additional detail in Note 7. Risk Management.

Fair Value of Other Financial Instruments

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

Note 7. Risk Management

Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. Periodically,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. The Partnership settled 3 derivative contracts during the first quarter of 2020, and in

In accordance with the Letteramended Simmons Loan Agreement discussed in Note 4. Debt, the Partnership iswas required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 31, 2020 until the next borrowing base redetermination date (first quarter of 2021).through February 2021. In August 2020,July 2021, the Partnership establishedbegan its risk management program required under the BF Loan Agreement (see Note 4. Debt) by entering into costless collar derivative contracts for future oil and natural gas produced by the Sanish Field Assets during the period from August 2020 through February 2021. All derivative instruments are recorded onJuly 2021 to September 2023. The Partnership did not pay or receive a premium related to the Partnership’s balance sheet as assets or liabilities measured at fair value.costless collars into which it entered to remain compliant with each loan agreement, and the contracts will be settled monthly.

As of September 30, 2020,2021, the Partnership’s derivative instruments with its counterparty were in a gain position; therefore,loss position. The Partnership has recognized a current assettotal liability of approximately $66,000,$2.3 million, of which approximates its fair value,$1.1 million has been recognizedrecorded as a derivative assetcurrent in Other current assetsDerivative liability and $1.2 million has been recorded as Derivative liability – noncurrent on the Partnership’s consolidated balance sheet as of September 30, 2020. As of December 31, 2019, the2021. The Partnership’s derivative instruments were in a loss position; therefore,position as of December 31, 2020; a current liability of approximately $0.2$0.6 million which approximates fair value, was recognized in Accounts payable, accrued expenses and other current liabilitiesas Derivative Liability on the Partnership’s consolidated balance sheet.sheet as of December 31, 2020. These current and noncurrent derivative liabilities as of September 31, 2021 and December 31, 2020 approximate fair value.

The Partnership determined the estimated fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets and quotes from third parties, among other things. The Partnership also performed an internal valuation to ensure the reasonableness of third-party quotes. In consideration of counterparty credit risk, the Partnership assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually-required payments. Additionally, the Partnership considered that the counterparty is of substantial credit quality and had the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions. See additional discussion above in Note 6. Fair Value of Financial Instruments.

The Partnership hasdid not designateddesignate its derivative instruments as hedges for accounting purposes and hasdid not enteredenter 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 settlementsthe settlement gain (loss) of matured derivative instruments and non-cash mark-to-market gains on open derivative instruments(losses) for the periods presented.

Settlements on matured derivatives belowabove 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)(non-cash, unrealized) gains belowor 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 Partnership generally uses costless collartable below summarizes the Partnership’s outstanding derivative contracts which establish floor(costless collars – purchased put options and ceiling priceswritten call options) on the Partnership’s future anticipatedoil and natural gas production. The Partnership did not pay or receive a premium related to the costless collars, and the contracts are settled monthly. The following table reflects the open costless collar derivative instruments as of September 30, 2020.

The Partnership’s outstanding derivative instruments are covered by an International Swap Dealers Association Master AgreementAgreements (“ISDA”) entered into with the counterparty. The ISDA may provide that as a result of certain circumstances, such as cross-defaults, a counterparty may require all outstanding derivative instruments under an ISDA to be settled immediately. The Partnership has netting arrangements with the counterpartyits 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’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 offeringsoffering 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:

In March 2020, the General Partner approved the suspension of distributions to limited partners of the Partnership in response to recent market volatility caused by the COVID-19 pandemic and the impact on the Partnership’s operating cash flows. The Partnership will accumulateaccumulates unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are required to be paid before final Payout occurs, as defined above. As of September 30, 2020,2021, the unpaid Payout Accrual totaled $0.828493$2.228493 per common unit, or approximately $16$42 million. As discussed in Note 4. Debt, and pursuant to the Letter Agreement, the Partnership is not permittedmust meet certain conditions under the BF Loan Agreement before distributions to pay distributions without lender approval.limited partners may resume.

For the nine months ended September 30, 2020, the Partnership paid distributions of $0.241644, or $4.6 million. For the three and nine months ended September 30, 2019, the Partnership paid distributions of $0.349041 and $1.047123 per common unit, or $6.6 million and $19.9 million, respectively.

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, including approving the loan discussed below.

As described in Note 4. Debt, in July 2020, the Partnership entered into a loan agreement with GKDML, which provided for a $15 million unsecured, one-year Term Loan. GKDML is owned and managed by Messrs. Knight and McKenney, the Chief Executive Officer and the Chief Financial Officer, respectively, of the General Partner. To provide the proceeds for the Term Loan, GKDML entered into a loan agreement with Bank of America, N.A., which has substantially the same terms as the Term Loan and is personally guaranteed by Messrs. Knight and McKenney. GKDML, Mr. Knight and Mr. McKenney have not and will not receive any consideration for providing the Term Loan or the guaranty to the GKDML Loan; however, under the Term Loan, the Partnership is required to reimburse GKDML for all costs of its loan with Bank of America.transactions.

For the three and nine months ended September 30, 2020,2021, approximately $101,000$29,000 and $291,000$91,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At September 30, 2020,2021, approximately $101,000$29,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses on the consolidated balance sheets. For the three and nine months ended September 30, 2019,2020, approximately $88,000$101,000 and $236,000$291,000 of general and administrative costs were incurred by a member of the General Partner and have been reimbursed by the Partnership.

The members of the General Partner are affiliates of Mr. Knight, Mr. McKenney, Anthony F. Keating, III, Co-Chief Operating Officer and Michael J. Mallick, Co-Chief Operating Officer. Messrs. Knight and McKenney are also the Chief Executive Officer and Chief Financial Officer of Energy Resources 12 GP, LLC, the general partner of Energy Resources 12, L.P. (“ER12”), a limited partnership that also invests in producing and non-producing oil and gas properties on-shore in the United States. On January 31, 2018, the Partnership entered into a cost sharing agreement with ER12 that givesgave 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 arewere split evenly between the two partnerships and any direct third-party costs are paid by the party receiving the services.partnerships. The shared costs arewere based on actual costs incurred with no mark-up or profit to the Partnership. The agreement may be terminated at any timeAny other direct third-party costs were paid by eitherthe party upon 60 days written notice.

The Partnership leases office space in Oklahoma City, Oklahoma on a month-to-month basis from an affiliate ofreceiving the General Partner. For the three and six months ended June 30, 2020 and 2019, the Partnership paid $25,611 and $51,222 in each period, respectively, to the affiliate of the General Partner. The office space is shared between the Partnership and ER12; therefore, under the cost-sharing agreement, the monthly payment of $8,537 is split between the two partnerships. In addition to the office space, the cost-sharing agreement reduces the costs to the Partnership for accounting and asset management services provided through a member of the General Partner noted above. The compensation due to Clifford J. Merritt, President of the General Partner, is also a shared cost between the Partnership and ER12.services. For the three and nine months ended September 30, 2020, approximately $64,000 and $204,000, respectively, of expenses subject to the cost-sharingcost sharing agreement were paidincurred by the PartnershipER12 and have been reimbursed to the Partnership. In October 2020, the cost sharing agreement was terminated by ER12, effective December 31, 2020.

On December 1, 2020, the Partnership entered into an Administrative Services Agreement (the “ASA”) with Regional Energy Investors, L.P. d/b/a Regional Energy Management (the “Administrator”) and ER12, whereby the Administrator will provide administrative, operating and professional services necessary and useful to the Partnership. The Administrator will also assist the General Partner with the day-to-day operations of the Partnership. The ASA is effective January 1, 2021, and the Initial Term of the ASA will extend until the earlier of (a) five years or (b) when the Partnership and/or 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 ER12. At September 30, 2020, the approximately $64,000 duePartnership. 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 from ER12 is included inprior 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 current assets inexpenses, such as business travel costs and accounting, legal or banking services, may not be incurred by the consolidated balance sheets.Administrator on behalf of the Partnership without prior express written consent of the Partnership. For the three and nine months ended September 30, 2019,2021, approximately $65,000$129,000 and $200,000,$420,000, respectively, of costs and expenses subject to the cost sharing agreementASA were paidreimbursed 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 have been reimburseddoes not apply to the Partnership. The Administrator is owned by ER12.entities that are controlled by Messrs. Keating and Mallick.

Note 10. Subsequent Events

InDuring October 2020, ER12 provided 60-day written noticeand November 2021, 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 base 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 ER12’s intentiondistributions to terminatelimited partners for the cost sharing agreement betweenmonth of November 2021. On November 24, 2021, the Partnership and ER12. The cost sharing agreement will terminate on December 31, 2020.pay approximately $1 million, or $0.051781 per outstanding common unit, in distributions to its holders of common units.

Item 2. Management’sManagement’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, 2019, those described under Part II. Item 1A. Risk Factors included herein this Form 10-Q2020 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, 2019.2020.

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, 2020,2021, the Partnership owned an approximate 25% non-operated working interest in 243264 producing wells, an estimated approximate 18%20% non-operated working interest in 2114 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”). Substantially all of the Sanish Field Assets are operated by Whiting Petroleum Corporation (“Whiting”) (NYSE: WLL) and Oasis Petroleum North America, LLC (“Oasis”) (NYSE: OAS), two publicly-traded oil and gas companies and twoone of the largest producers in the basin.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. Two wells were completed by and are being operated by Whiting; the Partnership has an approximate 29% non-operated working interest in these two wells. The other four wells were completed by and are operated by Oasis; the Partnership has an approximate 8% non-operated working interest in these four wells. In total, the Partnership’s capital expenditures for the drilling and completion of these six wells were approximately $7.8 million.

DuringSince the beginning of 2019, and the first quarter of 2020, the Partnership has elected to participate in the drilling and completion of 4357 new wells in the Sanish field. Twenty-two (22)Forty-three (43) of these 4357 wells have been completed and were producing at September 30, 2020;2021; the Partnership has an approximate non-operated working interest of 23%21% in these 2243 wells. The Partnership has an estimated approximate non-operated working interest of 18%20% in the remaining 218 wells that are in-process as of September 30, 2020.2021. The Partnership has an estimated approximate non-operated working interest of 20% in six wells that had not commenced drilling as of September 30, 2021. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 4357 wells is approximately $63$75 million, of which approximately $42$56 million was incurred as of September 30, 2020. Due to the factors described below in “Current Price Environment,” Whiting suspended its Sanish field drilling program during the second quarter of 2020.2021. See additional detail in “Oil and Natural Gas Properties” below.

Drilling Program, Oil Demand, Liquidity and Going Concern Considerations

In conjunction with the Whiting drilling program described above, the Partnership had incurred approximately $42 million in capital expenditures through September 30, 2020, which was primarily funded by availability under the Partnership’s $40 million revolving credit facility (“Credit Facility”, described in “Financing” below). However, the Partnership used all availability under its Credit Facility by March 31, 2020, and as of June 30, 2020, the Partnership had approximately $20 million in accrued operating and capital expenditures due to Whiting. New production from completed wells was expected to enhance the Partnership’s operating performance throughout 2020, providing incremental cash flow from operations to fund the Partnership’s investment in its undrilled acreage. Subsequent to the Partnership’s election to participate in Whiting’s drilling program, several factors, described in “Current Price Environment” below, have had and are anticipated to have an adverse impact on the Partnership’s business and its financial condition. Due to these severe negative impacts to the global oil and gas industry, Whiting declared bankruptcy under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of Texas on April 1, 2020, then subsequently suspended its Sanish field drilling program during the second quarter of 2020.

In July 2020, the Partnership entered into a loan agreement for a one year, $15 million term loan (“Affiliate Loan”) that matures on July 21, 2021 (see “Financing” below). The Partnership used proceeds from the Affiliate Loan plus cash on hand to pay the Partnership’s accrued operating and capital expenditures due to Whiting, which totaled approximately $19 million at the time of payment. In addition to the Affiliate Loan, the Partnership entered into a letter agreement (“Letter Agreement”) with its lender group for its Credit Facility. The Letter Agreement, among other items, waived the non-compliance of certain covenants under the Credit Facility; however, the Letter Agreement changed the maturity date of the Credit Facility from September 30, 2022 to July 31, 2021. In October 2020, the Partnership made a principal payment on the Affiliate Loan of $5 million; therefore, the Partnership’s outstanding debt obligations at the date of filing of this Form 10-Q total $50 million and mature within one year of the filing of this Form 10-Q.

The Partnership’s ability to continue as a going concern is dependent on several factors including, but not limited to, (i) the Partnership’s ability to comply with its obligations under its loan agreements; (ii) refinancing its existing debt and/or securing additional capital; (iii) an increase in demand for oil and natural gas as the global economy recovers from the effects of the COVID-19 pandemic and the existing oversupply of oil in the United States; and (iv) an increase in oil and natural gas market prices, which will improve the Partnership’s cash flow generated from operations. The Partnership can provide no assurance that it will be able to achieve any of these objectives. Refinancing its existing debt or securing additional capital may not be available on favorable terms to the Partnership, if it is available at all. There also can be no assurance that economic activity and oil and natural gas market conditions, including commodity prices, will return to pre-COVID-19 levels, or that the Partnership will be able to meet its operational obligations. If the Partnership is unable to refinance or repay its debt obligations or is unable to meet its operational obligations, the Partnership could be required to liquidate certain of its assets used for collateral to satisfy these obligations, which create the substantial doubt that exists about the ability of the Partnership to continue as a going concern for one year after the date these financial statements are issued.

Current Price Environment

Oil, natural gas and natural gas liquids (“NGL”) prices are determined by many factors outside of the Partnership’s control. Historically, worldwideworld-wide oil and natural gas prices and markets have been subject to significant change and volatility and willmay continue to be in the future. Since first being reportedGlobal macroeconomic factors contributing to uncertainty within the industry include real or perceived geopolitical risks in December 2019, COVID-19 spread worldwide, forcing governments aroundoil-producing regions of the world, to take drastic measures to haltparticularly the outbreak. These measures included significant restrictions on travel, forced quarantines, stay-at-home requirements and the closureMiddle East; forecasted levels of businesses in many industries, creating extreme volatility in capital markets and the global economy. Becauseeconomic growth combined with forecasted global supply; supply levels of COVID-19’s impact to the global economy, demand for fossil fuels substantially declined during the first quarter of 2020, and demand remained depressed during the second quarter of 2020. Although prices for oil and natural gas stabilizeddue to exploration and development activities in June 2020the United States; environmental and throughoutclimate change regulation; actions taken by the third quarterOrganization of 2020, prices remain below pre-COVID-19 levelsthe Petroleum Exporting Countries (“OPEC”); and are not anticipated to return to pre-COVID-19 levels during 2020.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 to the outbreak of COVID-19, during the first quarter of 2020, Saudi Arabia and Russia, two of the largest worldwide producers of crude oil, engaged in a price war during March and April 2020. Russia did not participate in production cuts coordinated by the Organization of the Petroleum Exporting Countries (“OPEC”), which2020 that ultimately led to Saudi Arabia lowering crude oil prices and both countries substantially increasing daily output of crude oil. The increase in Saudi and Russian oil output along with sustained production by other global producers, including the United States, has stressed the oil and gas industry’s capacity to store excess oil and gas. Despite Saudi Arabia, Russia, the United States and other OPEC members reaching an agreement in April 2020 to cut daily production, congested supply chain channels and excess crude oil and natural gas inventory are expected to weighand congested supply chain channels, which weighed negatively on commodity prices while demand remains low during COVID-19.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 production restraint by domestic and foreign operators in 2021 have contributed to higher commodity prices, with oil prices averaging over $70 per barrel for the third quarter of 2021 and topping $80 per barrel in October 2021.

These factors led to oil prices falling to 20-year lows in April 2020, when the average daily NYMEX futures closing prices for the month was $16.70. In response to lower commodity prices and reduced demand, operators within the United States altered drilling programs and the related forecasted capital expenditures for those programs, and implemented other cost-saving measures, such as curtailing production or shutting in producing wells, during the second quarter of 2020. While operators have since returned significant inventory of existing wells to production, the nature and timing of drilling new wells remains uncertain. 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. As a result, sustained lowerIf commodity prices havesignificantly drop, such as the decline in the second quarter of 2020, and will continue to impact the amount of capitalremain low, the Partnership haswill 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, despite the addition of new wells discussed above, 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, 20202021 and 2019.2020. 

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 is a summary oftable summarizes the results from operations, including production, of the Partnership’s non-operated working interest for the three and nine months ended September 30, 2021 and 2020. The effect of the outbreak of COVID-19 during the first and second quarters of 2020 and 2019.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.