10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2022

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM                                   TO                                   

Commission File Number 000-55615

Energy 11, L.P.

(Exact name of registrant as specified in its charter)

Delaware	46-3070515
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)
120 W 3rd Street, Suite 220 Fort Worth, Texas	76102
(Address of principal executive offices)	(Zip Code)

(817) 882-9192

(Registrant’s telephone number, including area code)

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

Title of each class	Trading Symbol	Name of each exchange on which registered
None

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.

Large accelerated filer ☐	Accelerated filer ☐
Non-accelerated filer ☑	Smaller reporting company ☑
Emerging growth company ☐

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 August 12, 2022, the Partnership had 18,973,474 common units outstanding. 

Energy 11, L.P.

Form 10-Q

Index

			Page Number
PART I. FINANCIAL INFORMATION
	Item 1.	Financial Statements (Unaudited)
		Consolidated Balance Sheets – June 30, 2022 and December 31, 2021	3
		Consolidated Statements of Operations – Three and six months ended June 30, 2022 and 2021	4
		Consolidated Statements of Partners’ Equity – Three and six months ended June 30, 2022 and 2021	5
		Consolidated Statements of Cash Flows – Six months ended June 30, 2022 and 2021	6
		Notes to Consolidated Financial Statements	7
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	24
	Item 4.	Controls and Procedures	24
PART II. OTHER INFORMATION
	Item 1.	Legal Proceedings	25
	Item 1A.	Risk Factors	25
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	25
	Item 3.	Defaults upon Senior Securities	25
	Item 4.	Mine Safety Disclosures	25
	Item 5.	Other Information	25
	Item 6.	Exhibits	25
Signatures			26

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Energy 11, L.P.

Consolidated Balance Sheets

	June 30,			December 31,
	2022			2021
	(unaudited)
Assets
Cash and cash equivalents	$	990,979		$	912,828
Accounts receivable		15,608,650			15,118,535
Other current assets, net		222,312			317,497
Total Current Assets		16,821,941			16,348,860
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $107,071,733 and $98,150,833, respectively		342,629,381			325,032,321
Other assets		94,616			165,578
Total Assets	$	359,545,938		$	341,546,759
Liabilities
Accounts payable and accrued expenses	$	23,077,290		$	9,847,984
Derivative liability		8,865,685			1,264,935
Total Current Liabilities		31,942,975			11,112,919
Revolving credit facility		16,000,000			23,000,000
Asset retirement obligations		1,980,211			1,791,341
Derivative liability - noncurrent		1,854,934			1,099,388
Total Liabilities		51,778,120			37,003,648
Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)		307,769,545			304,544,838
General partner's interest		(1,727	)		(1,727	)
Class B Units (62,500 units issued and outstanding, respectively)		-			-
Total Partners’ Equity		307,767,818			304,543,111
Total Liabilities and Partners’ Equity	$	359,545,938		$	341,546,759

See notes to consolidated financial statements.

3

Energy 11, L.P.

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended			Three Months Ended			Six Months Ended			Six Months Ended
	June 30, 2022			June 30, 2021			June 30, 2022			June 30, 2021
Revenues
Oil	$	20,043,443		$	11,868,210		$	41,442,296		$	22,470,147
Natural gas		2,182,702			865,226			4,045,315			2,343,986
Natural gas liquids		2,207,792			1,146,037			4,438,249			2,669,416
Total revenue		24,433,937			13,879,473			49,925,860			27,483,549
Operating costs and expenses
Production expenses		3,773,564			2,867,144			8,435,650			5,523,221
Production taxes		1,841,483			1,093,447			3,761,440			2,095,399
General and administrative expenses		492,839			315,832			1,076,091			847,130
Depreciation, depletion, amortization and accretion		3,646,669			4,952,799			9,079,655			9,840,216
Total operating costs and expenses		9,754,555			9,229,222			22,352,836			18,305,966
Operating income		14,679,382			4,650,251			27,573,024			9,177,583
Loss on derivatives, net		(2,417,520	)		-			(11,108,504	)		(579,660	)
Interest expense, net		(246,347	)		(523,341	)		(504,210	)		(1,007,544	)
Total other expense, net		(2,663,867	)		(523,341	)		(11,612,714	)		(1,587,204	)
Net income	$	12,015,515		$	4,126,910		$	15,960,310		$	7,590,379
Basic and diluted net income per common unit	$	0.63		$	0.22		$	0.84		$	0.40
Weighted average common units outstanding - basic and diluted		18,973,474			18,973,474			18,973,474			18,973,474

See notes to consolidated financial statements.

4

Energy 11, L.P.

Consolidated Statements of Partners’ Equity

(Unaudited)

	Limited Partner					Class B				General Partner			Total Partners'
	Common Units		Amount			Units		Amount		Amount			Equity
Balances - December 31, 2020		18,973,474	$	280,347,549			62,500	$	-	$	(1,727	)	$	280,345,822
Net income - three months ended March 31, 2021		-		3,463,469			-		-		-			3,463,469
Balances - March 31, 2021		18,973,474		283,811,018			62,500		-		(1,727	)		283,809,291
Net income - three months ended June 30, 2021		-		4,126,910			-		-		-			4,126,910
Balances - June 30, 2021		18,973,474	$	287,937,928			62,500	$	-	$	(1,727	)	$	287,936,201
Balances - December 31, 2021		18,973,474	$	304,544,838			62,500	$	-	$	(1,727	)	$	304,543,111
Distributions declared and paid to common units ($0.322191 per unit)		-		(6,113,083	)		-		-		-			(6,113,083	)
Net income - three months ended March 31, 2022		-		3,944,795			-		-		-			3,944,795
Balances - March 31, 2022		18,973,474		302,376,550			62,500		-		(1,727	)		302,374,823
Distributions declared and paid to common units ($0.349041 per unit)		-		(6,622,520	)		-		-		-			(6,622,520	)
Net income - three months ended June 30, 2022		-		12,015,515			-		-		-			12,015,515
Balances - June 30, 2022		18,973,474	$	307,769,545			62,500	$	-	$	(1,727	)	$	307,767,818

See notes to consolidated financial statements.

5

Energy 11, L.P.

Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended			Six Months Ended
	June 30, 2022			June 30, 2021
Cash flow from operating activities:
Net income	$	15,960,310		$	7,590,379
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion		9,079,655			9,840,216
(Gain) loss on mark-to-market of derivatives, net		7,394,804			(602,760	)
Non-cash expenses, net		70,962			99,650
Changes in operating assets and liabilities:
Accounts receivable		(490,115	)		(2,623,270	)
Other assets		95,185			96,140
Accounts payable and accrued expenses		2,106,786			158,668
Net cash flow provided by operating activities		34,217,587			14,559,023
Cash flow from investing activities:
Additions to oil and natural gas properties		(14,403,833	)		(5,043,870	)
Net cash flow used in investing activities		(14,403,833	)		(5,043,870	)
Cash flow from financing activities:
Cash paid for loan costs		-			(394,928	)
Proceeds from (payments on) BancFirst revolving credit facility		(7,000,000	)		40,063,389
Payments on Simmons revolving credit facility		-			(40,000,000	)
Payments on affiliate term loan		-			(6,000,000	)
Distributions paid to limited partners		(12,735,603	)		-
Net cash flow used in financing activities		(19,735,603	)		(6,331,539	)
Decrease in cash and cash equivalents		78,151			3,183,614
Cash and cash equivalents, beginning of period		912,828			2,463,819
Cash and cash equivalents, end of period	$	990,979		$	5,647,433
Interest paid	$	345,644		$	731,069
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$	19,673,422		$	9,812,130

See notes to consolidated financial statements.

6

Energy 11, L.P.

Notes to Consolidated Financial Statements

June 30, 2022

(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 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 Petroleum Corporation (“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 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 2021 Annual Report on Form 10-K. Operating results for the three and six months ended June 30, 2022 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 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.

7

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 Per Common Unit

Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three and six months ended June 30, 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 per common unit until such time that it is probable Payout (as discussed in Note 8) will occur.

Note 3. Oil and Natural Gas Investments

On December 18, 2015, the Partnership completed its first purchase in the Sanish field, acquiring an approximate 11% non-operated working interest in the Sanish Field Assets for approximately $159.6 million. On January 11, 2017, the Partnership closed on its second purchase in the Sanish field, acquiring an additional approximate 11% non-operated working interest in the Sanish Field Assets for approximately $128.5 million. On March 31, 2017, the Partnership closed on its third purchase in the Sanish field, acquiring an additional approximate average 10.5% non-operated working interest in 82 of the Partnership’s then 216 existing producing wells and 150 of the Partnership’s then 253 future development locations in the Sanish Field Assets for approximately $52.4 million.

Since the beginning of 2018, the Partnership has elected to participate in the drilling and completion of 84 new wells in the Sanish field. Fifty-six (56) of these 84 wells have been completed and were producing at June 30, 2022. The Partnership has 27 wells that are in-process as of June 30, 2022 and expects one additional well to commence drilling during the third quarter of 2022. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 84 wells is approximately $108 million, of which approximately $95 million was incurred as of June 30, 2022.

The Partnership estimates the approximate $10 to $20 million in capital expenditures to fully pay for its recently-completed wells along with the remaining 28 wells in various stages of drilling and completion will be incurred through the remainder 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.

8

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 $0.1 million in deferred loan costs are recorded as Other assets on the Partnership’s consolidated balance sheet as of June 30, 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 is currently stipulated to be $1 million. Therefore, as of June 30, 2022, the borrowing base was $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 March 1, 2022 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, the BF Loan Agreement requires the Partnership to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production under certain conditions. As amended in 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 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 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:

● A minimum ratio of trailing 12-month EBITDAX to debt service coverage of 1.20 to 1.00

● A minimum ratio of current assets to current liabilities of 1.00 to 1.00

9

The BF Loan Agreement does restrict the Partnership’s ability to pay limited partner distributions if the outstanding balance of the BF Credit Facility is greater than 50% of the lesser of (i) the Maximum Credit Amount or (ii) the current borrowing base. 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 June 30, 2022.

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

Note 5. Asset Retirement Obligations

The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement costs in oil and natural gas properties in the period in which the asset retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance. The changes in the aggregate ARO are as follows:

	2022		2021
Balance at January 1	$	1,791,341	$	1,564,105
Well additions		30,115		78,511
Accretion		47,491		42,253
Revisions		111,264		-
Balance at June 30	$	1,980,211	$	1,684,869

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:

● Level 1: Quoted prices in active markets for identical assets

● Level 2: Significant other observable inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, either directly or indirectly, for substantially the full term of the financial instrument

● Level 3: Significant unobservable inputs

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 six months ended June 30, 2022 and 2021, there were no transfers in or out of Level 1, Level 2, or Level 3 assets and liabilities measured on a recurring basis.

10

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 June 30, 2022 and December 31, 2021.

	Fair Value Measurements at June 30, 2022
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(8,865,685	)	$	-
Commodity derivatives - non-current liabilities		-		(1,854,934	)		-
Total	$	-	$	(10,720,619	)	$	-

	Fair Value Measurements at December 31, 2021
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(1,264,935	)	$	-
Commodity derivatives - noncurrent liabilities		-		(1,099,388	)		-
Total	$	-	$	(2,364,323	)	$	-

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 June 30, 2022 and December 31, 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, accounts receivable, accounts payable and accrued liabilities, reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments.

Note 7. Risk Management

Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. Therefore, the Partnership periodically utilizes derivative contracts to manage the commodity price risk on the Partnership’s future oil production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations.

In accordance with the amended Simmons Loan Agreement discussed in Note 4. Debt, the Partnership was required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 2020 through February 2021. In July 2021, the Partnership began its risk management program required under the BF Loan Agreement (see Note 4. Debt) by entering into costless collar derivative contracts for the period from July 2021 to September 2023. The Partnership generally uses costless collar derivative contracts, which establish floor and ceiling prices on future anticipated production. The Partnership did not pay or receive a premium related to the costless collars into which it entered to remain compliant with each loan agreement, and the contracts will be settled monthly.

As of June 30, 2022 and December 31, 2021, the Partnership’s derivative instruments were in a loss position. The Partnership recognized total liabilities of approximately $10.7 million and $2.4 million, respectively, of which $8.9 million and $1.3 million, respectively, has been recorded as current in Derivative liability and $1.9 million and $1.1 million, respectively, has been recorded as Derivative liability – noncurrent on the Partnership’s consolidated balance sheets.

11

The Partnership did not designate its derivative instruments as hedges for accounting purposes and did not enter into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The following table presents the settlement losses of matured derivative instruments and non-cash mark-to-market gains (losses) for the periods presented.

	Three Months Ended June 30, 2022			Three Months Ended June 30, 2021		Six Months Ended June 30, 2022			Six Months Ended June 30, 2021
Settlement loss on matured derivatives	$	(2,467,491	)	$	-	$	(3,713,700	)	$	(1,182,420	)
Gain (loss) on mark-to-market of derivatives, net		49,971			-		(7,394,804	)		602,760
Loss on derivatives, net	$	(2,417,520	)	$	-	$	(11,108,504	)	$	(579,660	)

Settlements on matured derivatives above reflect realized losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash, unrealized) gains or losses above represent the change in fair value of derivative instruments which were held at period-end. Unrealized gains or losses do not represent actual settlements or payments made to or from the counterparty.

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

Settlement Period	Basis	Product	Volume	Weighted Average Floor / Ceiling Prices ($)
07/2022 - 12/2022	NYMEX	Oil (bbls)	159,000	50.00 / 72.00
01/2023 - 09/2023	NYMEX	Oil (bbls)	224,000	50.00 / 69.72
08/2022 - 12/2022	Henry Hub	Gas (MMbtu)	150,000	2.00 / 4.50
01/2023 - 09/2023	Henry Hub	Gas (MMbtu)	273,000	2.00 / 4.43

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.

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The Partnership Agreement provides that Payout occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per unit, regardless of the amount paid for the unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount.

All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:

● First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement;

● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%).

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 June 30, 2022, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.387671 per common unit, or approximately $45 million.

Note 9. Related Parties

The members of the General Partner are affiliates of Glade M. Knight, Chairman and Chief Executive Officer, 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.

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

On December 1, 2020, the Partnership entered into an Administrative Services Agreement (the “ASA”) with Regional Energy Investors, L.P. d/b/a Regional Energy Management (the “Administrator”) and ER12, whereby the Administrator 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 became effective January 1, 2021, and the Initial Term of the ASA will extend until the earlier of (a) five years or (b) when the Partnership and/or ER12 ceases to own its respective oil and natural gas assets. Provided the ASA is 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 six months ended June 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 $151,000 and $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

In July 2022, the Partnership declared and paid $2.5 million, or $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.

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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:

● the impact of and ongoing recovery from COVID-19;

● any impact of the ongoing Russian-Ukrainian conflict on the global energy markets;

● references to future success in the Partnership’s drilling and marketing activities;

● the Partnership’s business strategy;

● estimated future distributions;

● estimated future capital expenditures;

● sales of the Partnership’s properties and other liquidity events;

● competitive strengths and goals; and

● other similar matters.

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, 2021 and the following:

● that the Partnership’s development of its oil and gas properties may not be successful or that the Partnership’s operations on such properties may not be successful;

● general economic, market, or business conditions;

● changes in laws or regulations;

● the risk that the wells in which the Partnership acquired an interest are productive, but do not produce enough revenue to return the investment made;

● the risk that the wells the Partnership drills do not find hydrocarbons in commercial quantities or, even if commercial quantities are encountered, that actual production is lower than expected on the productive life of wells is shorter than expected;

● current credit market conditions and the Partnership’s ability to obtain long-term financing or refinancing debt for the Partnership’s drilling activities in a timely manner and on terms that are consistent with what the Partnership projects;

● uncertainties concerning the price of oil and natural gas, which may decrease and remain low for prolonged periods; and

● the risk that any hedging policy the Partnership employs to reduce the effects of changes in the prices of the Partnership’s production will not be effective.

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

The following discussion and analysis should be read in conjunction with the Partnership’s Unaudited Consolidated Financial Statements and Notes thereto, appearing elsewhere in this Quarterly Report on Form 10-Q, as well as the information contained in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2021.

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Overview

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

The Partnership has no officers, directors or employees. Instead, the General Partner manages the day-to-day affairs of the Partnership. All decisions regarding the management of the Partnership made by the General Partner are made by the Board of Directors of the General Partner and its officers.

The Partnership was formed to acquire and develop oil and gas properties located onshore in the United States. On December 18, 2015, the Partnership completed its first purchase in the Sanish field, acquiring an approximate 11% non-operated working interest in the Sanish Field Assets for approximately $159.6 million. On January 11, 2017, the Partnership closed on its second purchase in the Sanish field, acquiring an additional approximate 11% non-operated working interest in the Sanish Field Assets for approximately $128.5 million. On March 31, 2017, the Partnership closed on its third purchase in the Sanish field, acquiring an additional approximate average 10.5% non-operated working interest in 82 of the Partnership’s then 216 existing producing wells and 150 of the Partnership’s then 253 future development locations in the Sanish Field Assets for approximately $52.4 million.

Since the beginning of 2018, the Partnership has elected to participate in the drilling and completion of 84 new wells in the Sanish field under a drilling program administered primarily by Whiting Petroleum Corporation (“Whiting”). Fifty-six (56) of these 84 wells have been completed and were producing at June 30, 2022. The Partnership has 27 wells that are in-process as of June 30, 2022 and expects one additional well to commence drilling in the third quarter of 2022. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 84 wells is approximately $108 million, of which approximately $95 million had been incurred as of June 30, 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 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. As government-mandated COVID-19 restrictions eased during the fourth quarter of 2020 and into 2021, demand for oil and natural gas returned. Production restraint by domestic and foreign operators in 2021, in conjunction with higher worldwide demand during the prolonged recovery from COVID-19, contributed to higher commodity prices throughout 2021. The ongoing military conflict between Russia and Ukraine and related economic sanctions imposed on Russia has further exacerbated supply shortages, causing oil prices to increase even more during the first half of 2022.

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The following table lists average NYMEX prices for oil and natural gas for the three and six months ended June 30, 2022 and 2021.

	Three Months Ended June 30,				Percent			Six Months Ended June 30,				Percent
	2022		2021		Change			2022		2021		Change
Average market closing prices (1)
Oil (per Bbl)	$	108.52	$	66.17		64.0	%	$	101.77	$	62.22		63.6	%
Natural gas (per Mcf)	$	7.50	$	2.95		154.2	%	$	6.08	$	3.22		88.8	%

(1) Based on average NYMEX futures closing prices (oil) and NYMEX/Henry Hub spot prices (natural gas)

The Partnership’s revenues and cash flow from operations are highly sensitive to changes in oil and natural gas prices and to levels of production. If commodity prices significantly drop, such as the decline in the second quarter of 2020, and remain low, the Partnership will see a reduction in available capital for the development of its undrilled wellsites. Future growth is dependent on the Partnership’s ability to add reserves in excess of production. In addition to commodity price fluctuations, the Partnership faces the challenge of natural production volume declines. As reservoirs are depleted, oil and natural gas production from Partnership wells will decrease.

Results of Operations

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

The following table summarizes the results from operations, including production, of the Partnership’s non-operated working interest for the three and six months ended June 30, 2022 and 2021.

	Three Months Ended June 30,													Six Months Ended June 30,
	2022		Percent of Revenue			2021		Percent of Revenue			Percent Change			2022		Percent of Revenue			2021		Percent of Revenue			Percent Change
Total revenues	$	24,433,937		100.0	%	$	13,879,473		100.0	%		76.0	%	$	49,925,860		100.0	%	$	27,483,549		100.0	%		81.7	%
Production expenses		3,773,564		15.4	%		2,867,144		20.7	%		31.6	%		8,435,650		16.9	%		5,523,221		20.1	%		52.7	%
Production taxes		1,841,483		7.5	%		1,093,447		7.9	%		68.4	%		3,761,440		7.5	%		2,095,399		7.6	%		79.5	%
Depreciation, depletion, amortization and accretion		3,646,669		14.9	%		4,952,799		35.7	%		-26.4	%		9,079,655		18.2	%		9,840,216		35.8	%		-7.7	%
General and administrative expenses		492,839		2.0	%		315,832		2.3	%		56.0	%		1,076,091		2.2	%		847,130		3.1	%		27.0	%
Production (BOE):
Oil		190,120					196,817					-3.4	%		428,086					401,495					6.6	%
Natural gas		49,329					46,725					5.6	%		102,535					90,664					13.1	%
Natural gas liquids		37,989					38,792					-2.1	%		80,566					75,807					6.3	%
Total		277,438					282,334					-1.7	%		611,187					567,966					7.6	%
Average sales price per unit:
Oil (per Bbl)	$	105.43				$	60.30					74.8	%	$	96.81				$	55.97					73.0	%
Natural gas (per Mcf)		7.37					3.09					138.5	%		6.58					4.31					52.7	%
Natural gas liquids (per Bbl)		58.12					29.54					96.8	%		55.09					35.21					56.5	%
Combined (per BOE)		88.07					49.16					79.2	%		81.69					48.39					68.8	%
Average unit cost per BOE:
Production expenses		13.60					10.16					33.9	%		13.80					9.72					42.0	%
Production taxes		6.64					3.87					71.4	%		6.15					3.69					66.7	%
Depreciation, depletion, amortization and accretion		13.14					17.54					-25.1	%		14.86					17.33					-14.3	%
Capital expenditures	$	16,194,361				$	10,999,208							$	25,402,845				$	13,324,172

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Oil, natural gas and NGL revenues

For the three months ended June 30, 2022, revenues from oil, natural gas and NGL sales were $24.4 million. Revenues for the sale of crude oil were $20.0 million, which resulted in a realized price of $105.43 per barrel. Revenues for the sale of natural gas were $2.2 million, which resulted in a realized price of $7.37 per Mcf. Revenues for the sale of NGLs were $2.2 million, which resulted in a realized price of $58.12 per BOE of sold production. For the three months ended June 30, 2021, revenues for oil, natural gas and NGL sales were $13.9 million. Revenues for the sale of crude oil were $11.9 million, which resulted in a realized price of $60.30 per barrel. Revenues for the sale of natural gas were $0.9 million, which resulted in a realized price of $3.09 per Mcf. Revenues for the sale of NGLs were $1.1 million, which resulted in a realized price of $29.54 per BOE of sold production.

For the six months ended June 30, 2022, revenues from oil, natural gas and NGL sales were $49.9 million. Revenues for the sale of crude oil were $41.4 million, which resulted in a realized price of $96.81 per barrel. Revenues for the sale of natural gas were $4.0 million, which resulted in a realized price of $6.58 per Mcf. Revenues for the sale of NGLs were $4.4 million, which resulted in a realized price of $55.09 per BOE of sold production. For the six months ended June 30, 2021, revenues for oil, natural gas and NGL sales were $27.5 million. Revenues for the sale of crude oil were $22.5 million, which resulted in a realized price of $55.97 per barrel. Revenues for the sale of natural gas were $2.3 million, which resulted in a realized price of $4.31 per Mcf. Revenues for the sale of NGLs were $2.7 million, which resulted in a realized price of $35.21 per BOE of sold production.

The Partnership’s results for the three and six months ended June 30, 2022 were positively impacted by the significant increase in market prices of oil and natural gas when compared to the same periods of 2021. In addition, the Partnership continues to benefit from the easing of market imbalances and supply chain constraints that developed during the spring and summer of 2020 due to COVID-19, realized through reduced differentials (see below). The Partnership’s realized sales prices for NGLs are influenced by the components extracted, including ethane, propane and butane and natural gasoline, among others, and the respective market pricing for each component.

The Partnership has completed 50 new wells since the fourth quarter of 2019, of which 28 were completed and turned to sales during the second quarter of 2021 through the second quarter of 2022. Sold production volumes were flat when comparing the three-month periods ended June 30, 2022 and 2021, as production from newly-completed wells effectively offset natural production declines. In addition to natural production decline, the Williston Basin in North Dakota was hit with a late-season snowstorm that resulted in significant downtime for producing wells during April 2022, which negatively impacted production volumes during the second quarter of 2022. As the wells currently in various stages of the drilling and completion process as of June 30, 2022 are completed, the Partnership anticipates its sold production volumes will increase during the third and fourth quarters of 2022. Sold production for the Sanish Field Assets was approximately 3,000 BOE and 3,400 BOE per day for the three and six months ended June 30, 2022 and 2021, respectively, while sold production for the Sanish Field Assets was approximately 3,100 BOE per day for the three and six months ended June 30, 2021.

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

Oil differentials

The realized prices per barrel of oil above are based upon the NYMEX benchmark price less a cost to distribute the oil, or the differential. Oil price differentials primarily represent the transportation costs in moving produced oil at the wellhead to a refinery and are based on the availability of pipeline, rail and other transportation methods out of the Sanish field. Oil price differentials to the NYMEX benchmark price vary by operator based upon operator-specific contracts. Due to improvement in commodity prices and market-specific conditions in the Bakken, oil price differentials were approximately 50-60% less during the three and six months ended June 30, 2022 than those of the same periods of 2021, respectively.

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

Operating costs and expenses

Production expenses

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

For the three months ended June 30, 2022 and 2021, production expenses were $3.8 million and $2.9 million, respectively, and production expenses per BOE of sold production were $13.60 and $10.16, respectively. For the six months ended June 30, 2022, production expenses were $8.4 million and $5.5 million, respectively, and production expenses per BOE of sold production were $13.80 and $9.72, respectively. Production expenses per BOE increased in the three and six months ended June 30, 2022, in comparison to the same period of 2021, as a result of (i) an increase in lease operating and workover expenses as certain of the Partnership’s existing wells have required additional maintenance and/or rework to either maintain production efficiency or return to full production, and (ii) an increase in total gathering, processing and selling costs associated with the increased sale of the Partnership’s natural gas and NGL production. The production costs specific to the processing, treating and marketing of natural gas and NGLs are higher than those associated with oil, so an increase in sold natural gas and NGLs (in proportion to total sold volumes) results in a greater increase in these production expenses per BOE than the corresponding increase in production expenses for new oil production.

Production taxes

Taxes on the production and extraction of oil and gas are regulated and set by North Dakota tax authorities. Taxes on the sale of gas and NGL products are less than taxes levied on the sale of oil. Therefore, production taxes as a percentage of revenue may fluctuate dependent upon the ratio of sales of natural gas and NGLs to total sales. Production taxes for the three months ended June 30, 2022 and 2021 were $1.8 million (8% of revenue) and $1.1 million (8% of revenue), respectively. Production taxes for the six months ended June 30, 2022 and 2021 were $3.8 million (8% of revenue) and $2.1 million (8% of revenue), respectively.

General and administrative expenses

The principal components of general and administrative expense are accounting, legal and consulting fees. General and administrative expenses for the three months ended June 30, 2022 and 2021 were $0.5 million and $0.3 million, respectively. General and administrative expenses for the six months ended June 30, 2022 and 2021 were $1.1 million and $0.8 million, respectively.

19

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

DD&A of capitalized drilling and development costs of producing oil, natural gas and NGL properties are computed using the unit-of-production method on a field basis based on total estimated proved developed oil, natural gas and NGL reserves. Costs of acquiring proved properties are depleted using the unit-of-production method on a field basis based on total estimated proved developed and undeveloped reserves. DD&A for the three months ended June 30, 2022 and 2021 was $3.6 million and $5.0 million, and DD&A per BOE of sold production was $13.14 and $17.54, respectively. DD&A for the six months ended June 30, 2022 and 2021 was $9.1 million and $9.8 million, and DD&A per BOE of sold production was $14.86 and $17.33, respectively. The decrease in DD&A expense per BOE of production in the first half of 2022 is primarily due to the increase of the Partnership’s estimated proved undeveloped reserves during the most recent reserves analyses (as of December 31, 2021 and June 30, 2022) resulting from changes in the future drill schedule.

Loss on derivatives, net

Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. Periodically, the Partnership utilizes derivative contracts to manage the commodity price risk on the Partnership’s future oil production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations.

In accordance with the Partnership’s previous credit facility, the Partnership was required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 2020 through February 2021. In July 2021, the Partnership began its risk management program required under the BancFirst Loan Agreement by entering into costless collar derivative contracts for the period from July 2021 to September 2023.

The Partnership did not designate its 2021 or 2022 derivative instruments as hedges for accounting purposes and did not enter into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The following table presents settlements of its matured derivative instruments and the non-cash, mark-to-market gains or losses recorded during the periods presented.

	Three Months Ended June 30, 2022			Three Months Ended June 30, 2021		Six Months Ended June 30, 2022			Six Months Ended June 30, 2021
Settlement loss on matured derivatives	$	(2,467,491	)	$	-	$	(3,713,700	)	$	(1,182,420	)
Gain (loss) on mark-to-market of derivatives, net		49,971			-		(7,394,804	)		602,760
Loss on derivatives, net	$	(2,417,520	)	$	-	$	(11,108,504	)	$	(579,660	)

The Partnership’s oil production contracts that expired during the three months ended June 30, 2022 represented approximately 85,000 barrels of oil. The Partnership realized a loss of approximately $2.4 million, equating to an approximate loss of $28.33 per barrel, on its hedged oil production, and an approximate loss of $12.67 per barrel of total sold oil production for the second quarter of 2022. The Partnership’s natural gas production contracts that expired during the three months ended June 30, 2022 represented 90,000 MMBtu of produced natural gas. The Partnership realized a loss of approximately $59,000, equating to an approximate loss of $0.66 per MMBtu, on its hedged natural gas production, and an approximate loss $0.20 per MMBtu of total sold natural gas production for the second quarter of 2022.

The Partnership’s oil production contracts that expired during the six months ended June 30, 2022 represented approximately 173,000 barrels of oil. The Partnership realized a loss of approximately $3.7 million, equating to an approximate loss of $21.12 per barrel, on its hedged oil production, and an approximate loss of $8.54 per barrel of total sold oil production for the first half of 2022. The Partnership’s natural gas production contracts that expired during the six months ended June 30, 2022 represented 200,000 MMBtu of produced natural gas. The Partnership realized a loss of approximately $59,000, equating to an approximate loss of $0.30 per MMBtu, on its hedged natural gas production, and an approximate loss $0.10 per MMBtu of total sold natural gas production for the first half of 2022.

20

The Partnership’s oil production contracts that expired during the six months ended June 30, 2021 represented approximately 105,000 barrels of oil. The Partnership’s realized loss of approximately $1.2 million equated to an approximate loss of $11.26 per barrel of hedged oil production, and an approximate loss of $2.95 per barrel of total sold oil production for the first half of 2021. The Partnership’s natural gas production contracts that expired during the six months ended June 30, 2021 represented 120,000 MMBtu of natural gas; however, these natural gas production contracts 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 mark-to-market (non-cash, unrealized) gains or losses recorded for the three and six months ended June 30, 2022 and 2021 represent the change in fair value of the Partnership’s derivative instruments held at period-end. Unrealized gains and losses do not represent actual settlements or payments made to or from the counterparty.

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

Settlement Period	Basis	Product	Volume	Weighted Average Floor / Ceiling Prices ($)
07/2022 - 12/2022	NYMEX	Oil (bbls)	159,000	50.00 / 72.00
01/2023 - 09/2023	NYMEX	Oil (bbls)	224,000	50.00 / 69.72
08/2022 - 12/2022	Henry Hub	Gas (MMbtu)	150,000	2.00 / 4.50
01/2023 - 09/2023	Henry Hub	Gas (MMbtu)	273,000	2.00 / 4.43

Interest expense, net

Interest expense, net, for the three months ended June 30, 2022 and 2021 was $0.2 million and $0.5 million, respectively. Interest expense, net, for the six months ended June 30, 2022 and 2021 was $0.5 million and $1.0 million, respectively. The primary component of Interest expense, net, during the three- and six-month periods ended June 30, 2022 was interest expense on the BancFirst Credit Facility. The primary component of Interest expense, net, during the three- and six-month periods ended June 30, 2021 was interest expense on the BancFirst Credit Facility, the Simmons Credit Facility (paid in full in May 2021) and a related-party term loan (paid in full in March 2021).

Supplemental Non-GAAP Measure

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

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

The following table reconciles the Partnership’s GAAP net income to Adjusted EBITDAX for the three and six months ended June 30, 2022 and 2021.

	Three Months Ended June 30, 2022			Three Months Ended June 30, 2021		Six Months Ended June 30, 2022		Six Months Ended June 30, 2021
Net income	$	12,015,515		$	4,126,910	$	15,960,310	$	7,590,379
Interest expense, net		246,347			523,341		504,210		1,007,544
Depreciation, depletion, amortization and accretion		3,646,669			4,952,799		9,079,655		9,840,216
Exploration expenses		-			-		-		-
Non-cash (gain) loss on mark-to-market of derivatives, net		(49,971	)		-		7,394,804		(602,760	)
Adjusted EBITDAX	$	15,858,560		$	9,603,050	$	32,938,979	$	17,835,379

21

Liquidity and Capital Resources

Historically, the Partnership’s principal sources of liquidity have been cash on hand, the cash flow generated from the Sanish Field Assets, and availability under the Partnership’s revolving credit facility, if any. The Partnership generated approximately $43.5 million in cash flow from operating activities for the year ended December 31, 2021 and approximately $34.2 million in cash flow from operating activities for the six months ended June 30, 2022. In May 2021, the Partnership successfully refinanced its existing Simmons Bank credit facility and used the initial closing proceeds of approximately $40 million from the refinancing with BancFirst to fully repay the outstanding balance on the Simmons credit facility. From May 2021 through June 2022, the Partnership made principal payments on the BancFirst credit facility of approximately $24 million using excess cash flow from operations. As of June 30, 2022, the Partnership had approximately $20 million in accrued capital expenditures to its operators related to the drilling program discussed below in “Oil and Natural Gas Properties.” In addition to using cash flow from operations, the Partnership has borrowed approximately $7 million on the BancFirst credit facility during the third quarter of 2022 to pay its capital obligations as they become due under the drilling program.

The Partnership anticipates its cash on-hand, cash flow from operations and availability under its BancFirst credit facility will be adequate to meet its liquidity requirements for at least the next 12 months, including completing the outstanding capital expenditures discussed below. In addition, the Partnership met all conditions under the BancFirst Credit Facility to resume distributions in November 2021. The Partnership’s ability to make future distributions to its limited partners is contingent on remaining compliant with all applicable covenants under its BancFirst credit facility as well as ensuring the outstanding balance of the credit facility is at or below 50% of the Partnership’s current borrowing base. The Partnership can offer no assurance to the payment of distributions in future months; however, the General Partner will monitor payment of future monthly Partnership distributions in conjunction with the Partnership’s projected cash requirements for operations, payments on the BancFirst credit facility and capital expenditures for new wells.

The Partnership’s revenues and cash flow from operations are highly sensitive to changes in oil and natural gas prices and to levels of production. If commodity prices significantly drop, such as the decline in the second quarter of 2020, and remain low, the Partnership’s cash flow from operations may decline. This could have a significant impact on the Partnership’s available cash on-hand, the Partnership’s ability to participate in future drilling programs as proposed by the operators of the Sanish Field Assets and/or to fund any future distributions to its limited partners. Future growth is dependent on the Partnership’s ability to add reserves in excess of production. In addition to commodity price fluctuations, the Partnership faces the challenge of natural production volume declines. As reservoirs are depleted, oil and natural gas production from Partnership wells will decrease.

Financing

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

Partners’ Equity

The Partnership completed its best-efforts offering of common units on April 24, 2017. As of the conclusion of the offering on April 24, 2017, the Partnership sold approximately 19.0 million common units for total gross proceeds of $374.2 million and proceeds net of offering costs of $349.6 million.

Under the agreement with the Dealer Manager, the Dealer Manager received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager will also be paid a contingent incentive fee, which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold based on the performance of the Partnership. Based on the common units sold in the offering, the total contingent fee is a maximum of approximately $15.0 million, which will only be paid if Payout occurs, as defined in “Note 8. Capital Contribution and Partners’ Equity” in Part I, Item 1 of this Form 10-Q.

Distributions

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. 

22

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 of June 30, 2022, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.387671 per common unit, or approximately $45 million.

Oil and Natural Gas Properties

The Partnership incurred approximately $26.5 million and $13.3 million in capital expenditures for the six months ended June 30, 2022 and 2021, respectively.

Since the beginning of 2019, the Partnership has elected to participate in the drilling and completion of 78 new wells in the Sanish field. Fifty (50) of these 78 wells have been completed and were producing at June 30, 2022; the Partnership has an approximate non-operated working interest of 20% in these 50 wells. The Partnership has an estimated approximate non-operated working interest of 21% in 27 wells that are in-process as of June 30, 2022. The Partnership has an estimated approximate non-operated working interest of 19% in one additional well that had not commenced drilling as of June 30, 2022. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 78 wells is approximately $100 million, of which approximately $87 million was incurred as of June 30, 2022.

The Partnership anticipates its operators will complete the remaining 28 wells during the next three to nine months; however, completion of the wells is not in the Partnership’s control. The Partnership estimates the approximate $10 to $20 million in capital expenditures to fully pay for its recently-completed wells along with the remaining 28 wells in various stages of the drilling and completion process will be incurred during the remainder of 2022 based on the best available information regarding current capital investment plans from its operators. Many factors outside the Partnership’s control make it difficult to predict the amount and timing of capital expenditures for the remainder of 2022 and estimated capital expenditures could be significantly different from amounts actually invested. Because the Partnership’s operator is committed to drilling in the Sanish Field, the Partnership may be obligated to invest up to an additional $100 million in capital expenditures from 2023 through 2027 to participate in new well development in the Sanish Field without becoming subject to non-consent penalties under the joint operating agreements governing the Sanish Field Assets.

As described above, the Partnership’s liquidity is currently dependent upon cash on-hand, cash from operations and availability under the BancFirst Credit Facility. If the Partnership is not able to generate sufficient cash from operations or there is no availability under its credit facility to fund capital expenditures, it may not be able to complete its capital obligations presented by its operators or participate fully in future wells. If an operator elects to complete drilling or other significant capital expenditure activity and the Partnership is unable to fund the capital expenditures, the General Partner may decide to farmout the well. Also, if a well is proposed under the operating agreement for one of the properties the Partnership owns, the General Partner may elect to “non-consent” the well. Non-consenting a well will generally cause the Partnership not to be obligated to pay the costs of the well, but the Partnership will not be entitled to the proceeds of production from the well until a penalty is received by the parties that drilled the well.

Transactions with Related Parties

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

See further discussion in “Note 9. Related Parties” in Part I, Item 1 of this Form 10-Q.

Subsequent Events

In July 2022, the Partnership declared and paid $2.5 million, or $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.

23

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Partnership’s BancFirst Credit Facility is subject to a variable interest rate; information regarding this credit facility is contained in Item 1 – Financial Statements (Unaudited) and Notes to Consolidated Financial Statements: Note 4. Debt and Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, appearing elsewhere within this Quarterly Report on Form 10-Q.

Information regarding the Partnership’s hedging programs to mitigate commodity risks is contained in Item 1 – Financial Statements (Unaudited) and Notes to Consolidated Financial Statements: Note 7. Risk Management and Item 2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations, appearing elsewhere within this Quarterly Report on Form 10-Q.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rule 13a–15 and 15d–15 under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), the Partnership carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer of the General Partner, of the effectiveness of the Partnership’s disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Partnership’s disclosure controls and procedures were effective as of June 30, 2022 to provide reasonable assurance that information required to be disclosed in the Partnership’s reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The Partnership’s disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and the Chief Financial Officer of the General Partner, as appropriate, to allow timely decisions regarding required disclosure.

Change in Internal Controls Over Financial Reporting

There have not been any changes in the Partnership’s internal controls over financial reporting that occurred during the quarterly period ended June 30, 2022 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal controls over financial reporting.

24

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors

For a discussion of the Partnership’s potential risks and uncertainties, see the section titled “Risk Factors” in the Partnership’s 2021 Annual Report on Form 10-K. There have been no material changes to the risk factors previously disclosed in the 2021 Form 10-K.

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

Not applicable.

Item 3. Defaults upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

Exhibit No.	Description
31.1	Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002*
31.2	Certification of Chief Financial Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002*
32.1	Certification of Chief Executive Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
32.2	Certification of Chief Financial Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002*
101	The following materials from Energy 11, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2022 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Partners’ Equity, (iv) the Consolidated Statements of Cash Flows, and (v) related notes to these consolidated financial statements, tagged as blocks of text and in detail*
104	The cover page from the Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2022, formatted in iXBRL and contained in Exhibit 101

*Filed herewith.

25

SIGNATURES

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

Energy 11, L.P.
By: Energy 11 G.P., LLC, its General Partner
By:	/s/ Glade M. Knight
	Glade M. Knight
	Chief Executive Officer (Principal Executive Officer)
By:	/s/ David S. McKenney
	David S. McKenney
	Chief Financial Officer (Principal Financial and Accounting Officer)
Date: August 12, 2022

26

EX-31.1

EXHIBIT 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER PURSUANT TO RULE 13a-14(a)/15D-14(a)

I, Glade M. Knight, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Energy 11, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 12, 2022	By:	/s/ Glade M. Knight
	Name:	Glade M. Knight
	Title:	General Partner, Chief Executive Officer
		(Principal Executive Officer)

EX-31.2

EXHIBIT 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER PURSUANT TO RULE 13a-14(a)/15D-14(a)

I, David McKenney, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Energy 11, L.P. (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  August 12, 2022	By:	/s/ David S. McKenney
	Name:	David S. McKenney
	Title:	General Partner, Chief Financial Officer (Principal Financial and Accounting Officer)

EX-32.1

EXHIBIT 32.1

CERTIFICATION FURNISHED PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

This certification is furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350) and accompanies the Quarterly Report on Form 10-Q (the “Form 10-Q”) for the three months ended June 30, 2022 of Energy 11, L.P. (the “Partnership”).  I, Glade M. Knight, the Chief Executive Officer of the Partnership, certify that, based on my knowledge:

(1)   The Form 10-Q fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

(2)   The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Partnership as of and for the periods covered in this report.

Date:  August 12, 2022	By:	/s/ Glade M. Knight
	Name:	Glade M. Knight
	Title:	General Partner, Chief Executive Officer (Principal Executive Officer)

EX-32.2

EXHIBIT 32.2

CERTIFICATION FURNISHED PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

This certification is furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350) and accompanies the Quarterly Report on Form 10-Q (the “Form 10-Q”) for the three months ended June 30, 2022 of Energy 11, L.P. (the “Partnership”).  I, David McKenney, the Chief Financial Officer of the Partnership, certify that, based on my knowledge:

(1)   The Form 10-Q fully complies with the requirements of Section 13(a) or Section 15(d) of the Securities Exchange Act of 1934; and

(2)   The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Partnership as of and for the periods covered in this report.

Date: August 12, 2022	By:	/s/ David S. McKenney
	Name:	David S. McKenney
	Title:	General Partner, Chief Financial Officer (Principal Financial and Accounting Officer)

XML

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2022	Aug. 12, 2022
Document Information Line Items
Entity Registrant Name	Energy 11, L.P.
Document Type	10-Q
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding		18,973,474
Amendment Flag	false
Entity Central Index Key	0001581552
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Period End Date	Jun. 30, 2022
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	Q2
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Document Quarterly Report	true
Document Transition Report	false
Entity File Number	000-55615
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	46-3070515
Entity Address, Address Line One	120 W 3rd Street, Suite 220
Entity Address, City or Town	Fort Worth
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	76102
City Area Code	817
Local Phone Number	882-9192
Title of 12(b) Security	None
Entity Interactive Data Current	Yes

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Consolidated Balance Sheets - USD ($)	Jun. 30, 2022	Dec. 31, 2021
Assets
Cash and cash equivalents	$ 990,979	$ 912,828
Accounts receivable	15,608,650	15,118,535
Other current assets, net	222,312	317,497
Total Current Assets	16,821,941	16,348,860
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $107,071,733 and $98,150,833, respectively	342,629,381	325,032,321
Other assets	94,616	165,578
Total Assets	359,545,938	341,546,759
Liabilities
Accounts payable and accrued expenses	23,077,290	9,847,984
Derivative liability	8,865,685	1,264,935
Total Current Liabilities	31,942,975	11,112,919
Revolving credit facility	16,000,000	23,000,000
Asset retirement obligations	1,980,211	1,791,341
Derivative liability - noncurrent	1,854,934	1,099,388
Total Liabilities	51,778,120	37,003,648
Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)	307,769,545	304,544,838
General partner's interest	(1,727)	(1,727)
Class B Units (62,500 units issued and outstanding, respectively)	0	0
Total Partners’ Equity	307,767,818	304,543,111
Total Liabilities and Partners’ Equity	$ 359,545,938	$ 341,546,759

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Consolidated Balance Sheets (Parentheticals) - USD ($)	Jun. 30, 2022	Dec. 31, 2021
Statement of Financial Position [Abstract]
Oil and natural gas properties, accumulated depreciation, depletion and amortization (in Dollars)	$ 107,071,733	$ 98,150,833
Limited partners' interest, common units issued	18,973,474	18,973,474
Limited partners' interest, common units outstanding	18,973,474	18,973,474
Class B Units, units issued	62,500	62,500
Class B Units, units outstanding	62,500	62,500

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Consolidated Statements of Operations - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Revenues
Oil	$ 20,043,443	$ 11,868,210	$ 41,442,296	$ 22,470,147
Natural gas	2,182,702	865,226	4,045,315	2,343,986
Natural gas liquids	2,207,792	1,146,037	4,438,249	2,669,416
Total revenue	24,433,937	13,879,473	49,925,860	27,483,549
Operating costs and expenses
Production expenses	3,773,564	2,867,144	8,435,650	5,523,221
Production taxes	1,841,483	1,093,447	3,761,440	2,095,399
General and administrative expenses	492,839	315,832	1,076,091	847,130
Depreciation, depletion, amortization and accretion	3,646,669	4,952,799	9,079,655	9,840,216
Total operating costs and expenses	9,754,555	9,229,222	22,352,836	18,305,966
Operating income	14,679,382	4,650,251	27,573,024	9,177,583
Loss on derivatives, net	(2,417,520)	0	(11,108,504)	(579,660)
Interest expense, net	(246,347)	(523,341)	(504,210)	(1,007,544)
Total other expense, net	(2,663,867)	(523,341)	(11,612,714)	(1,587,204)
Net income	$ 12,015,515	$ 4,126,910	$ 15,960,310	$ 7,590,379
Basic and diluted net income per common unit (in Dollars per share)	$ 0.63	$ 0.22	$ 0.84	$ 0.4
Weighted average common units outstanding - basic and diluted (in Shares)	18,973,474	18,973,474	18,973,474	18,973,474

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Consolidated Statements of Partners' Equity - USD ($)	Total	Capital Unit, Class B [Member] Member Units [Member]	Limited Partner [Member]	General Partner [Member]
Balance at Dec. 31, 2020	$ 280,345,822		$ 280,347,549	$ (1,727)
Balance (in Shares) at Dec. 31, 2020		62,500	18,973,474
Net income	3,463,469		$ 3,463,469
Balance at Mar. 31, 2021	283,809,291		$ 283,811,018	(1,727)
Balance (in Shares) at Mar. 31, 2021		62,500	18,973,474
Balance at Dec. 31, 2020	280,345,822		$ 280,347,549	(1,727)
Balance (in Shares) at Dec. 31, 2020		62,500	18,973,474
Distributions declared and paid to common units	0
Net income	7,590,379
Balance at Jun. 30, 2021	287,936,201		$ 287,937,928	(1,727)
Balance (in Shares) at Jun. 30, 2021		62,500	18,973,474
Balance at Mar. 31, 2021	283,809,291		$ 283,811,018	(1,727)
Balance (in Shares) at Mar. 31, 2021		62,500	18,973,474
Net income	4,126,910		$ 4,126,910
Balance at Jun. 30, 2021	287,936,201		$ 287,937,928	(1,727)
Balance (in Shares) at Jun. 30, 2021		62,500	18,973,474
Balance at Dec. 31, 2021	$ 304,543,111		$ 304,544,838	(1,727)
Balance (in Shares) at Dec. 31, 2021	18,973,474	62,500	18,973,474
Distributions declared and paid to common units	$ (6,113,083)		$ (6,113,083)
Net income	3,944,795		3,944,795
Balance at Mar. 31, 2022	302,374,823		$ 302,376,550	(1,727)
Balance (in Shares) at Mar. 31, 2022		62,500	18,973,474
Balance at Dec. 31, 2021	$ 304,543,111		$ 304,544,838	(1,727)
Balance (in Shares) at Dec. 31, 2021	18,973,474	62,500	18,973,474
Distributions declared and paid to common units	$ (12,735,603)
Net income	15,960,310
Balance at Jun. 30, 2022	$ 307,767,818		$ 307,769,545	(1,727)
Balance (in Shares) at Jun. 30, 2022	18,973,474	62,500	18,973,474
Balance at Mar. 31, 2022	$ 302,374,823		$ 302,376,550	(1,727)
Balance (in Shares) at Mar. 31, 2022		62,500	18,973,474
Distributions declared and paid to common units	(6,622,520)		$ (6,622,520)
Net income	12,015,515		12,015,515
Balance at Jun. 30, 2022	$ 307,767,818		$ 307,769,545	$ (1,727)
Balance (in Shares) at Jun. 30, 2022	18,973,474	62,500	18,973,474

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Consolidated Statements of Partners' Equity (Parentheticals) - $ / shares	3 Months Ended
	Jun. 30, 2022	Mar. 31, 2022
Capital Unit, Class B [Member] | Member Units [Member]
Distributions declared and paid to common units, per unit	$ 0.349041	$ 0.322191

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Consolidated Statements of Cash Flows - USD ($)	3 Months Ended	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2022	Jun. 30, 2021
Cash flow from operating activities:
Net income	$ 12,015,515	$ 15,960,310	$ 7,590,379
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion	3,646,669	9,079,655	9,840,216
(Gain) loss on mark-to-market of derivatives, net	(49,971)	7,394,804	(602,760)
Non-cash expenses, net		70,962	99,650
Changes in operating assets and liabilities:
Accounts receivable		(490,115)	(2,623,270)
Other assets		95,185	96,140
Accounts payable and accrued expenses		2,106,786	158,668
Net cash flow provided by operating activities		34,217,587	14,559,023
Cash flow from investing activities:
Additions to oil and natural gas properties		(14,403,833)	(5,043,870)
Net cash flow used in investing activities		(14,403,833)	(5,043,870)
Cash flow from financing activities:
Cash paid for loan costs		0	(394,928)
Proceeds from (payments on) BancFirst revolving credit facility		(7,000,000)	40,063,389
Payments on Simmons revolving credit facility		0	(40,000,000)
Payments on affiliate term loan		0	(6,000,000)
Distributions paid to limited partners	(6,622,520)	(12,735,603)	0
Net cash flow used in financing activities		(19,735,603)	(6,331,539)
Decrease in cash and cash equivalents		78,151	3,183,614
Cash and cash equivalents, beginning of period		912,828	2,463,819
Cash and cash equivalents, end of period	$ 990,979	990,979	5,647,433
Interest paid		345,644	731,069
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties		$ 19,673,422	$ 9,812,130

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Partnership Organization

6 Months Ended

Jun. 30, 2022

Accounting Policies [Abstract]

Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block]

Note 1. Partnership Organization

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

As of 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 Petroleum Corporation (“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 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.

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2022

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

Note 2. Summary of Significant Accounting Policies

Basis of Presentation

The accompanying unaudited financial statements have been prepared in accordance with the instructions for Article 10 of SEC Regulation S-X. Accordingly, they do not include all of the information required by generally accepted accounting principles (“GAAP”) in the United States. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. These unaudited financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements included in its 2021 Annual Report on Form 10-K. Operating results for the three and six months ended June 30, 2022 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 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 Per Common Unit

Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three and six months ended June 30, 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 per common unit until such time that it is probable Payout (as discussed in Note 8) will occur.

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Oil and Natural Gas Investments

6 Months Ended

Jun. 30, 2022

Oil and Gas Property [Abstract]

Oil and Gas Properties [Text Block]

Note 3. Oil and Natural Gas Investments

On December 18, 2015, the Partnership completed its first purchase in the Sanish field, acquiring an approximate 11% non-operated working interest in the Sanish Field Assets for approximately $159.6 million. On January 11, 2017, the Partnership closed on its second purchase in the Sanish field, acquiring an additional approximate 11% non-operated working interest in the Sanish Field Assets for approximately $128.5 million. On March 31, 2017, the Partnership closed on its third purchase in the Sanish field, acquiring an additional approximate average 10.5% non-operated working interest in 82 of the Partnership’s then 216 existing producing wells and 150 of the Partnership’s then 253 future development locations in the Sanish Field Assets for approximately $52.4 million.

Since the beginning of 2018, the Partnership has elected to participate in the drilling and completion of 84 new wells in the Sanish field. Fifty-six (56) of these 84 wells have been completed and were producing at June 30, 2022. The Partnership has 27 wells that are in-process as of June 30, 2022 and expects one additional well to commence drilling during the third quarter of 2022. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 84 wells is approximately $108 million, of which approximately $95 million was incurred as of June 30, 2022.

The Partnership estimates the approximate $10 to $20 million in capital expenditures to fully pay for its recently-completed wells along with the remaining 28 wells in various stages of drilling and completion will be incurred through the remainder 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.

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Debt

6 Months Ended

Jun. 30, 2022

Debt Disclosure [Abstract]

Debt Disclosure [Text Block]

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 $0.1 million in deferred loan costs are recorded as Other assets on the Partnership’s consolidated balance sheet as of June 30, 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 is currently stipulated to be $1 million. Therefore, as of June 30, 2022, the borrowing base was $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 March 1, 2022 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, the BF Loan Agreement requires the Partnership to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production under certain conditions. As amended in 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 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 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:

● A minimum ratio of trailing 12-month EBITDAX to debt service coverage of 1.20 to 1.00

● A minimum ratio of current assets to current liabilities of 1.00 to 1.00

The BF Loan Agreement does restrict the Partnership’s ability to pay limited partner distributions if the outstanding balance of the BF Credit Facility is greater than 50% of the lesser of (i) the Maximum Credit Amount or (ii) the current borrowing base. 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 June 30, 2022.

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

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2022

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation Disclosure [Text Block]

Note 5. Asset Retirement Obligations

The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement costs in oil and natural gas properties in the period in which the asset retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance. The changes in the aggregate ARO are as follows:

	2022		2021
Balance at January 1	$	1,791,341	$	1,564,105
Well additions		30,115		78,511
Accretion		47,491		42,253
Revisions		111,264		-
Balance at June 30	$	1,980,211	$	1,684,869

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Fair Value of Financial Instruments

6 Months Ended

Jun. 30, 2022

Fair Value Disclosures [Abstract]

Fair Value Disclosures [Text Block]

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:

● Level 1: Quoted prices in active markets for identical assets

● Level 2: Significant other observable inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, either directly or indirectly, for substantially the full term of the financial instrument

● Level 3: Significant unobservable inputs

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 six months ended June 30, 2022 and 2021, there were no transfers in or out of Level 1, Level 2, or Level 3 assets and liabilities measured on a recurring basis.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2022 and December 31, 2021.

	Fair Value Measurements at June 30, 2022
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(8,865,685	)	$	-
Commodity derivatives - non-current liabilities		-		(1,854,934	)		-
Total	$	-	$	(10,720,619	)	$	-

	Fair Value Measurements at December 31, 2021
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(1,264,935	)	$	-
Commodity derivatives - noncurrent liabilities		-		(1,099,388	)		-
Total	$	-	$	(2,364,323	)	$	-

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 June 30, 2022 and December 31, 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, accounts receivable, accounts payable and accrued liabilities, reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments.

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Risk Management

6 Months Ended

Jun. 30, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities Disclosure [Text Block]

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 June 30, 2022 and December 31, 2021, the Partnership’s derivative instruments were in a loss position. The Partnership recognized total liabilities of approximately $10.7 million and $2.4 million, respectively, of which $8.9 million and $1.3 million, respectively, has been recorded as current in Derivative liability and $1.9 million and $1.1 million, respectively, has been recorded as Derivative liability – noncurrent on the Partnership’s consolidated balance sheets.

The Partnership did not designate its derivative instruments as hedges for accounting purposes and did not enter into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The following table presents the settlement losses of matured derivative instruments and non-cash mark-to-market gains (losses) for the periods presented.

	Three Months Ended June 30, 2022			Three Months Ended June 30, 2021		Six Months Ended June 30, 2022			Six Months Ended June 30, 2021
Settlement loss on matured derivatives	$	(2,467,491	)	$	-	$	(3,713,700	)	$	(1,182,420	)
Gain (loss) on mark-to-market of derivatives, net		49,971			-		(7,394,804	)		602,760
Loss on derivatives, net	$	(2,417,520	)	$	-	$	(11,108,504	)	$	(579,660	)

Settlements on matured derivatives above reflect realized losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price. The mark-to-market (non-cash, unrealized) gains or losses above represent the change in fair value of derivative instruments which were held at period-end. Unrealized gains or losses do not represent actual settlements or payments made to or from the counterparty.

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

Settlement Period	Basis	Product	Volume	Weighted Average Floor / Ceiling Prices ($)
07/2022 - 12/2022	NYMEX	Oil (bbls)	159,000	50.00 / 72.00
01/2023 - 09/2023	NYMEX	Oil (bbls)	224,000	50.00 / 69.72
08/2022 - 12/2022	Henry Hub	Gas (MMbtu)	150,000	2.00 / 4.50
01/2023 - 09/2023	Henry Hub	Gas (MMbtu)	273,000	2.00 / 4.43

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.

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Capital Contribution and Partners' Equity

6 Months Ended

Jun. 30, 2022

Partners' Capital Notes [Abstract]

Partners' Capital Notes Disclosure [Text Block]

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:

● First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement;

● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%).

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 June 30, 2022, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.387671 per common unit, or approximately $45 million.

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Related Parties

6 Months Ended

Jun. 30, 2022

Related Party Transactions [Abstract]

Related Party Transactions Disclosure [Text Block]

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

On December 1, 2020, the Partnership entered into an Administrative Services Agreement (the “ASA”) with Regional Energy Investors, L.P. d/b/a Regional Energy Management (the “Administrator”) and ER12, whereby the Administrator 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 became effective January 1, 2021, and the Initial Term of the ASA will extend until the earlier of (a) five years or (b) when the Partnership and/or ER12 ceases to own its respective oil and natural gas assets. Provided the ASA is 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 six months ended June 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 $151,000 and $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.

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Subsequent Events

6 Months Ended

Jun. 30, 2022

Subsequent Events [Abstract]

Subsequent Events [Text Block]

Note 10. Subsequent Events

In July 2022, the Partnership declared and paid $2.5 million, or $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.

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Accounting Policies, by Policy (Policies)

6 Months Ended

Jun. 30, 2022

Accounting Policies [Abstract]

Basis of Accounting, Policy [Policy Text Block]

Basis of Presentation

The accompanying unaudited financial statements have been prepared in accordance with the instructions for Article 10 of SEC Regulation S-X. Accordingly, they do not include all of the information required by generally accepted accounting principles (“GAAP”) in the United States. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. These unaudited financial statements should be read in conjunction with the Partnership’s audited consolidated financial statements included in its 2021 Annual Report on Form 10-K. Operating results for the three and six months ended June 30, 2022 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2022.

Cash and Cash Equivalents, Policy [Policy Text Block]

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, Policy [Policy Text Block]

Use of Estimates

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

Revenue [Policy Text Block]

Revenue Recognition

The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Accounts receivable in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.

Earnings Per Share, Policy [Policy Text Block]

Net Income Per Common Unit

Basic net income per common unit is computed as net income divided by the weighted average number of common units outstanding during the period. Diluted net income per common unit is calculated after giving effect to all potential common units that were dilutive and outstanding for the period. There were no common units with a dilutive effect for the three and six months ended June 30, 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 per common unit until such time that it is probable Payout (as discussed in Note 8) will occur.

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2022

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations [Table Text Block]

The Partnership records an asset retirement obligation (“ARO”) and capitalizes the asset retirement costs in oil and natural gas properties in the period in which the asset retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit-of-production basis. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance. The changes in the aggregate ARO are as follows:

	2022		2021
Balance at January 1	$	1,791,341	$	1,564,105
Well additions		30,115		78,511
Accretion		47,491		42,253
Revisions		111,264		-
Balance at June 30	$	1,980,211	$	1,684,869

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Fair Value of Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2022

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

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 June 30, 2022 and December 31, 2021.

	Fair Value Measurements at June 30, 2022
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(8,865,685	)	$	-
Commodity derivatives - non-current liabilities		-		(1,854,934	)		-
Total	$	-	$	(10,720,619	)	$	-

	Fair Value Measurements at December 31, 2021
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity derivatives - current liabilities	$	-	$	(1,264,935	)	$	-
Commodity derivatives - noncurrent liabilities		-		(1,099,388	)		-
Total	$	-	$	(2,364,323	)	$	-

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Risk Management (Tables)

6 Months Ended

Jun. 30, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

The Partnership did not designate its derivative instruments as hedges for accounting purposes and did not enter into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership’s consolidated statements of operations as a gain or loss on derivative instruments. The following table presents the settlement losses of matured derivative instruments and non-cash mark-to-market gains (losses) for the periods presented.

	Three Months Ended June 30, 2022			Three Months Ended June 30, 2021		Six Months Ended June 30, 2022			Six Months Ended June 30, 2021
Settlement loss on matured derivatives	$	(2,467,491	)	$	-	$	(3,713,700	)	$	(1,182,420	)
Gain (loss) on mark-to-market of derivatives, net		49,971			-		(7,394,804	)		602,760
Loss on derivatives, net	$	(2,417,520	)	$	-	$	(11,108,504	)	$	(579,660	)

Schedule of Derivative Instruments [Table Text Block]

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.

Settlement Period	Basis	Product	Volume	Weighted Average Floor / Ceiling Prices ($)
07/2022 - 12/2022	NYMEX	Oil (bbls)	159,000	50.00 / 72.00
01/2023 - 09/2023	NYMEX	Oil (bbls)	224,000	50.00 / 69.72
08/2022 - 12/2022	Henry Hub	Gas (MMbtu)	150,000	2.00 / 4.50
01/2023 - 09/2023	Henry Hub	Gas (MMbtu)	273,000	2.00 / 4.43

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Partnership Organization (Details) shares in Millions			6 Months Ended	46 Months Ended
	Dec. 18, 2015	Jul. 09, 2013 USD ($)	Jun. 30, 2022	Apr. 24, 2017 USD ($) shares
Partnership Organization (Details) [Line Items]
Limited Liability Company or Limited Partnership, Business, Formation State		Delaware
Partners' Capital Account, Contributions (in Dollars)		$ 1,000
Best-Efforts Offering [Member]
Partnership Organization (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares) | shares				19.0
Proceeds from Issuance of Common Limited Partners Units (in Dollars)				$ 374,200,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units (in Dollars)				$ 349,600,000
Non-operated Completed Wells [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net	11.00%		25.00%
Oil, Productive Well, Number of Wells, Net			269
Non-operated Wells in the Process of Drilling [Member]
Partnership Organization (Details) [Line Items]
Oil and Gas, Present Activity, Well in Process of Drilling			27
Non-operated Wells in the Process of Drilling [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Partnership Organization (Details) [Line Items]
Gas and Oil Area Developed, Net			21.00%
Oil and Gas, Present Activity, Well in Process of Drilling			27

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Oil and Natural Gas Investments (Details)				1 Months Ended	6 Months Ended	54 Months Ended
	Mar. 31, 2017	Jan. 11, 2017 USD ($)	Dec. 18, 2015 USD ($)	Mar. 31, 2017 USD ($)	Jun. 30, 2022 USD ($)	Jun. 30, 2022
Oil and Natural Gas Investments (Details) [Line Items]
Wells in Various Stages of Drilling and Completion Process					28
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Wells Not Yet Commenced Drilling					1
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					$ 108,000,000
Costs Incurred, Development Costs (in Dollars)					95,000,000
Sanish Field Located in Mountrail County, North Dakota [Member] | Minimum [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					10
Sanish Field Located in Mountrail County, North Dakota [Member] | Maximum [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Estimated Capital Expenditures, Drilling and Completion of Wells (in Dollars)					$ 20,000,000
Acquisition No. 1 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Business Combination, Consideration Transferred (in Dollars)			$ 159,600,000
Acquisition No. 2 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net		11.00%
Business Combination, Consideration Transferred (in Dollars)		$ 128,500,000
Acquisition No. 3 [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net	10.50%
Business Combination, Consideration Transferred (in Dollars)				$ 52,400,000
Number of Producing Partnership Wells Acquired	82
Oil, Productive Well, Number of Wells, Net	216			216
Number of Future Development Partnership Locations Acquired	150
Gas and Oil Area Undeveloped, Net	253
Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Wells Elected to Participate in Drilling						84
Non-operated Completed Wells [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Oil and Gas, Development Well Drilled, Net Productive, Number						56
Non-operated Completed Wells [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net			11.00%		25.00%
Oil, Productive Well, Number of Wells, Net					269	269
Non-operated Wells in the Process of Drilling [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Oil and Gas, Present Activity, Well in Process of Drilling					27	27
Non-operated Wells in the Process of Drilling [Member] | Sanish Field Located in Mountrail County, North Dakota [Member]
Oil and Natural Gas Investments (Details) [Line Items]
Gas and Oil Area Developed, Net					21.00%
Oil and Gas, Present Activity, Well in Process of Drilling					27	27

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Debt (Details) - USD ($)			6 Months Ended
	May 13, 2021	Nov. 21, 2017	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Debt (Details) [Line Items]
Long-Term Line of Credit			$ 16,000,000		$ 23,000,000
Debt Issuance Costs, Noncurrent, Net			100,000
Repayments of Lines of Credit			0	$ 40,000,000
Line of Credit Facility, Fair Value of Amount Outstanding			$ 16,000,000		$ 23,000,000
Revolving Credit Facility [Member]
Debt (Details) [Line Items]
Debt Instrument, Face Amount	$ 60,000,000	$ 40,000,000
Debt Instrument, Maturity Date	Mar. 01, 2024	Jul. 31, 2021
Long-Term Debt, Percentage Bearing Variable Interest, Percentage Rate	4.25%		5.25%
Long-Term Line of Credit	$ 40,000,000		$ 16,000,000
Debt Instrument, Fee	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
Debt Issuance Costs, Gross	$ 400,000
Debt Issuance Costs, Current, Net			$ 100,000
Line of Credit Facility, Commitment Fee Description	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
Proceeds from Lines of Credit	$ 40,000,000
Repayments of Lines of Credit	$ 40,000,000
Line of Credit Facility, Collateral	The BF Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells
Line of Credit Facility, Borrowing Capacity, Description	Under the BF Loan Agreement, the initial borrowing base was $60 million. The Partnership’s borrowing base is reduced by a Monthly Commitment Reduction, which is currently stipulated to be $1 million. Therefore, as of June 30, 2022, the borrowing base was $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 March 1, 2022 redetermination analysis. The Lender is also permitted to cause the borrowing base to be redetermined up to two times during a 12-month period
Line of Credit Facility, Covenant Compliance			The Partnership was in compliance with its applicable covenants at June 30, 2022.
Revolving Credit Facility [Member] | Prime Rate [Member]
Debt (Details) [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%
Debt Instrument, Minimum Interest Rate	4.00%

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Asset Retirement Obligations (Details) - Schedule of Asset Retirement Obligations - USD ($)	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021
Schedule of Asset Retirement Obligations [Abstract]
Balance	$ 1,791,341	$ 1,564,105
Balance	1,980,211	1,684,869
Well additions	30,115	78,511
Accretion	47,491	42,253
Revisions	$ 111,264	$ 0

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Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis - USD ($)	Jun. 30, 2022	Dec. 31, 2021
Fair Value, Inputs, Level 1 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current liabilities	$ 0	$ 0
Commodity derivatives - noncurrent liabilities	0	0
Total	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current liabilities	(8,865,685)	(1,264,935)
Commodity derivatives - noncurrent liabilities	(1,854,934)	(1,099,388)
Total	(10,720,619)	(2,364,323)
Fair Value, Inputs, Level 3 [Member]
Fair Value of Financial Instruments (Details) - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Commodity derivatives - current liabilities	0	0
Commodity derivatives - noncurrent liabilities	0	0
Total	$ 0	$ 0

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Risk Management (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Jun. 30, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Discussion of Price Risk Derivative Risk Management Policy	Debt, the Partnership was required to maintain a risk management program to manage the commodity price risk on the Partnership’s future oil and natural gas production for the period from August 2020 through February 2021.
Derivative Liability	$ 2,400,000	$ 10,700,000
Derivative Liability, Current	1,264,935	8,865,685
Derivative Liability, Noncurrent	$ 1,099,388	$ 1,854,934

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Risk Management (Details) - Schedule of Derivative Instruments in Statement of Financial Position, Fair Value - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Abstract]
Settlement loss on matured derivatives	$ (2,467,491)	$ 0	$ (3,713,700)	$ (1,182,420)
Gain (loss) on mark-to-market of derivatives, net	49,971	0	(7,394,804)	602,760
Loss on derivatives, net	$ (2,417,520)	$ 0	$ (11,108,504)	$ (579,660)

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Risk Management (Details) - Schedule of Derivative Instruments - Price Risk Derivative [Member]	6 Months Ended
	Jun. 30, 2022 $ / bbl bbl
Costless Collar Agreements 1 [Member]
Derivative [Line Items]
Basis	NYMEX
Product	Oil (bbls)
Volume | bbl	159,000
Floor Price	50
Ceiling Price	72
Costless Collar Agreements 2 [Member]
Derivative [Line Items]
Basis	NYMEX
Product	Oil (bbls)
Volume | bbl	224,000
Floor Price	50
Ceiling Price	69.72
Costless Collar Agreements 3 [Member]
Derivative [Line Items]
Basis	Henry Hub
Product	Gas (MMbtu)
Volume | bbl	150,000
Floor Price	2
Ceiling Price	4.5
Costless Collar Agreements 4 [Member]
Derivative [Line Items]
Basis	Henry Hub
Product	Gas (MMbtu)
Volume | bbl	273,000
Floor Price	2
Ceiling Price	4.43

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Capital Contribution and Partners' Equity (Details) - USD ($) $ / shares in Units, shares in Millions		3 Months Ended		6 Months Ended		46 Months Ended
	Jul. 09, 2013	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2022	Jun. 30, 2021	Apr. 24, 2017
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Contributions	$ 1,000
Distributions to organizational limited partner	$ 990
Managing Dealer, Selling Commissions, Percentage				6.00%
Managing Dealer, Maximum Contingent Incentive Fee on Gross Proceeds, Percentage				4.00%
Maximum Contingent Offering Costs, Selling Commissions and Marketing Expenses		$ 15,000,000		$ 15,000,000
Key Provisions of Operating or Partnership Agreement, Description				The Partnership Agreement provides that Payout occurs on the day when the aggregate amount distributed with respect to each of the common units equals $20.00 plus the Payout Accrual. The Partnership Agreement defines “Payout Accrual” as 7% per annum simple interest accrued monthly until paid on the Net Investment Amount outstanding from time to time. The Partnership Agreement defines Net Investment Amount initially as $20.00 per unit, regardless of the amount paid for the unit. If at any time the Partnership distributes to holders of common units more than the Payout Accrual, the amount the Partnership distributes in excess of the Payout Accrual will reduce the Net Investment Amount. All distributions made by the Partnership after Payout, which may include all or a portion of the proceeds of the sale of all or substantially all of the Partnership’s assets, will be made as follows:  ● First, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) to the Dealer Manager, as the Dealer Manager contingent incentive fee paid under the Dealer Manager Agreement, 30%, and (iv) the remaining amount, if any (currently 13.125%), to the Record Holders of outstanding common units, pro rata based on their percentage interest until such time as the Dealer Manager receives the full amount of the Dealer Manager contingent incentive fee under the Dealer Manager Agreement;   ● Thereafter, (i) to the Record Holders of the Incentive Distribution Rights, 35%; (ii) to the Record Holders of the Outstanding Class B units, pro rata based on the number of Class B units owned, 35% multiplied by a fraction, the numerator of which is the number of Class B units outstanding and the denominator of which is 100,000 (currently, there are 62,500 Class B units outstanding; therefore, Class B units could receive 21.875%); (iii) the remaining amount to the Record Holders of outstanding common units, pro rata based on their percentage interest (currently 43.125%).
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share)		$ 0.349041		$ 0.671232
Distribution Made to Limited Partner, Cash Distributions Paid		$ 6,622,520	$ 6,113,083	$ 12,735,603	$ 0
Annualized Rate of Retun				7.00%
Distribution at Payout to limited partner, per common unit (in Dollars per share)				$ 2.387671
Distribution at Payout to limited partner				$ 45,000,000
Best-Efforts Offering [Member]
Capital Contribution and Partners' Equity (Details) [Line Items]
Partners' Capital Account, Units, Sale of Units (in Shares)						19.0
Proceeds from Issuance of Common Limited Partners Units						$ 374,200,000
Proceeds, Net of Offering Costs, from Issuance of Common Limited Partners Units						$ 349,600,000

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Related Parties (Details) - USD ($)		3 Months Ended		6 Months Ended
	Jan. 01, 2020	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
General Partner [Member]
Related Parties (Details) [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party		$ 39,000	$ 30,000	$ 76,000	$ 62,000
Due to Related Parties, Current		39,000		39,000
Administrative Service Agreement [Member]
Related Parties (Details) [Line Items]
Related Party Transaction, Selling, General and Administrative Expenses from Transactions with Related Party		$ 134,000	$ 151,000	$ 274,000	$ 291,000
Related Party, Administrative Service Agreement	Under the ASA, the Administrator will also assist Energy Resources 12 GP, LLC, the general partner of ER12 (“ER12’s General Partner”), with the day-to-day operations of ER12. ER12 currently pays ER12’s General Partner an annual management fee of 0.5% of the total gross equity proceeds raised by ER12 in its best-efforts offering. Under the ASA, ER12’s General Partner will pay one-half of its annual management fee to the Administrator in exchange for the services to be provided under the ASA. This fee is only applicable to ER12 and does not apply to the Partnership. The Administrator is owned by entities that are controlled by Messrs. Keating and Mallick.

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Subsequent Events (Details) - USD ($)	1 Months Ended	2 Months Ended	3 Months Ended		6 Months Ended
	Jul. 31, 2022	Aug. 31, 2022	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2022	Jun. 30, 2021
Subsequent Events (Details) [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid			$ 6,622,520	$ 6,113,083	$ 12,735,603	$ 0
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share)			$ 0.349041		$ 0.671232
Capital Expenditures Incurred but Not yet Paid					$ 19,673,422	$ 9,812,130
Subsequent Event [Member]
Subsequent Events (Details) [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid	$ 2,500,000
Distribution Made to Limited Partner, Distributions Paid, Per Unit (in Dollars per share)	$ 0.134247
Proceeds from Lines of Credit		$ 7,000,000