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 September 30, 2023

☐ 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 November 13, 2023, 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 – September 30, 2023 and December 31, 2022	3
		Consolidated Statements of Operations – Three and nine months ended September 30, 2023 and 2022	4
		Consolidated Statements of Partners’ Equity – Three and nine months ended September 30, 2023 and 2022	5
		Consolidated Statements of Cash Flows – Nine months ended September 30, 2023 and 2022	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

	September 30,			December 31,
	2023			2022
	(unaudited)
Assets
Cash and cash equivalents	$	341,325		$	3,053,120
Accounts receivable		15,575,780			17,173,549
Other current assets, net		219,601			317,248
Total Current Assets		16,136,706			20,543,917
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $138,956,698 and $119,045,055, respectively		342,378,757			353,519,338
Other assets		-			23,654
Total Assets	$	358,515,463		$	374,086,909
Liabilities
Revolving credit facility	$	7,000,000		$	-
Accounts payable and accrued expenses		9,493,149			15,170,168
Derivative liability		513,275			3,173,965
Total Current Liabilities		17,006,424			18,344,133
Revolving credit facility		-			22,600,000
Asset retirement obligations		2,048,293			1,966,738
Total Liabilities		19,054,717			42,910,871
Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)		339,462,473			331,177,765
General partner's interest		(1,727	)		(1,727	)
Class B Units (62,500 units issued and outstanding, respectively)		-			-
Total Partners’ Equity		339,460,746			331,176,038
Total Liabilities and Partners’ Equity	$	358,515,463		$	374,086,909

See notes to consolidated financial statements.

3

Energy 11, L.P.

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended			Three Months Ended			Nine Months Ended			Nine Months Ended
	September 30, 2023			September 30, 2022			September 30, 2023			September 30, 2022
Revenues
Oil	$	21,325,216		$	27,811,323		$	67,345,791		$	69,253,619
Natural gas		837,361			2,886,757			2,984,405			6,932,072
Natural gas liquids		1,913,593			2,278,848			5,793,553			6,717,097
Total revenue		24,076,170			32,976,928			76,123,749			82,902,788
Operating costs and expenses
Production expenses		6,405,176			4,402,718			20,605,740			12,838,368
Production taxes		1,931,082			2,602,071			6,029,821			6,363,511
General and administrative expenses		297,531			480,776			1,381,386			1,556,868
Depreciation, depletion, amortization and accretion		6,519,826			5,777,217			19,992,113			14,856,872
Total operating costs and expenses		15,153,615			13,262,782			48,009,060			35,615,619
Operating income		8,922,555			19,714,146			28,114,689			47,287,169
Gain (loss) on derivatives, net		(770,882	)		4,300,050			1,252,427			(6,808,453	)
Interest expense, net		(227,611	)		(411,333	)		(1,021,277	)		(915,543	)
Total other income (expense), net		(998,493	)		3,888,717			231,150			(7,723,996	)
Net income	$	7,924,062		$	23,602,863		$	28,345,839		$	39,563,173
Basic and diluted net income per common unit	$	0.42		$	1.24		$	1.49		$	2.09
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, 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
Distributions declared and paid to common units ($0.375891 per unit)		-		(7,131,956	)		-		-		-			(7,131,956	)
Net income - three months ended September 30, 2022		-		23,602,863			-		-		-			23,602,863
Balances - September 30, 2022		18,973,474	$	324,240,452			62,500	$	-	$	(1,727	)	$	324,238,725
Balances - December 31, 2022		18,973,474	$	331,177,765			62,500	$	-	$	(1,727	)	$	331,176,038
Distributions declared to common units ($0.357671 per unit)		-		(6,786,261	)		-		-		-			(6,786,261	)
Net income - three months ended March 31, 2023		-		12,999,267			-		-		-			12,999,267
Balances - March 31, 2023		18,973,474		337,390,771			62,500		-		(1,727	)		337,389,044
Distributions declared to common units ($0.35000 per unit)		-		(6,640,716	)		-		-		-			(6,640,716	)
Adjustment to state tax withholding for limited partners		-		6,562			-		-		-			6,562
Net income - three months ended June 30, 2023		-		7,422,510			-		-		-			7,422,510
Balances - June 30, 2023		18,973,474	$	338,179,127			62,500	$	-	$	(1,727	)	$	338,177,400
Distributions declared to common units ($0.35000 per unit)		-		(6,640,716	)		-		-		-			(6,640,716	)
Net income - three months ended September 30, 2023		-		7,924,062			-		-		-			7,924,062
Balances - September 30, 2023		18,973,474	$	339,462,473			62,500	$	-	$	(1,727	)	$	339,460,746

See notes to consolidated financial statements.

5

Energy 11, L.P.

Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended			Nine Months Ended
	September 30, 2023			September 30, 2022
Cash flow from operating activities:
Net income	$	28,345,839		$	39,563,173
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion		19,992,113			14,856,872
(Gain) loss on mark-to-market of derivatives, net		(3,033,037	)		1,167,463
Non-cash expenses, net		106,443			106,443
Changes in operating assets and liabilities:
Accounts receivable		1,597,770			(8,042,546	)
Other assets		14,858			(62,218	)
Accounts payable and accrued expenses		435,294			1,886,910
Net cash flow provided by operating activities		47,459,280			49,476,097
Cash flow from investing activities:
Additions to oil and natural gas properties		(14,160,303	)		(33,096,053	)
Net cash flow used in investing activities		(14,160,303	)		(33,096,053	)
Cash flow from financing activities:
Proceeds from BancFirst revolving credit facility		-			13,100,000
Payments on BancFirst revolving credit facility		(15,600,000	)		(7,000,000	)
Distributions paid to limited partners		(20,410,772	)		(19,867,559	)
Net cash flow used in financing activities		(36,010,772	)		(13,767,559	)
Increase (decrease) in cash and cash equivalents		(2,711,795	)		2,612,485
Cash and cash equivalents, beginning of period		3,053,120			912,828
Cash and cash equivalents, end of period	$	341,325		$	3,525,313
Interest paid	$	825,731		$	757,134
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$	3,153,861		$	15,685,423

See notes to consolidated financial statements.

6

Energy 11, L.P.

Notes to Consolidated Financial Statements

September 30, 2023

(Unaudited)

Note 1. Partnership Organization

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

As of September 30, 2023, the Partnership owned an approximate 24% non-operated working interest in 295 producing wells, an estimated approximate 14% non-operated working interest in four wells in various stages of the drilling and completion process and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). Chord Energy Corporation (“Chord”), the product of a merger between Whiting Petroleum Corporation and Oasis Petroleum Inc., is one of the largest producers in the basin and operates substantially all of the Sanish Field Assets.

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

The Partnership’s fiscal year ends on December 31.

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

Cash and Cash Equivalents

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

Use of Estimates

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

Revenue Recognition

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

7

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

Accounts Receivable and Concentration of Credit Risk

For the quarter ended September 30, 2023, the Partnership’s oil, natural gas and NGL sales were through two operators. Substantially all the Partnership’s accounts receivable is due from Chord, the largest operator of the Sanish Field Assets (operators have accounts receivable from purchasers of oil, natural gas and NGLs). Oil, natural gas and NGL sales receivables are generally unsecured. This industry and location concentration has the potential to impact the Partnership’s overall exposure to credit risk, in that the purchasers of the Partnership’s oil, natural gas and NGLs and the operators of the properties the Partnership has an interest in may be similarly affected by changes in economic, industry or other conditions. At September 30, 2023 and December 31, 2022, the Partnership did not reserve for bad debt expense, as all amounts are deemed collectible. Chord is the current operator of 99% of the Partnership’s producing properties. All oil and natural gas producing activities of the Partnership are in North Dakota and represent substantially all of the business activities of the Partnership.

Income Tax

The Partnership is taxed as a partnership for federal and state income tax purposes. Typically, the Partnership has not recorded a provision for income taxes since the liability for such taxes is that of each of the partners rather than the Partnership. In mid-2022, the Partnership was contacted by the state of North Dakota, which asserted that the Partnership has an obligation to make tax payments on behalf of certain non-resident partners. The Partnership reached a resolution with the state of North Dakota that entailed the Partnership making a payment of taxes on behalf of certain non-resident limited partners to the state for the tax years of 2021 and 2022. The Partnership made a payment of approximately $243,000 (approximately $0.013 per common unit) in May 2023 that settled the 2021 tax year. The Partnership anticipates that the estimate recorded at December 31, 2022 of approximately $315,000 for the 2022 tax year will be settled and paid in the fourth quarter of 2023. The Partnership’s income tax returns are subject to examination by the federal and state taxing authorities, and changes, if any, could adjust the individual income tax of the partners.

The Partnership has evaluated whether any material tax position taken will more likely than not be sustained upon examination by the appropriate taxing authority and believes that all such material tax positions taken are supportable by existing laws and related interpretations.

Net Income Per Common Unit

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

Note 3. Oil and Natural Gas Investments

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

Since the beginning of 2018, the Partnership has elected to participate in the drilling and completion of 86 new wells in the Sanish field, of which 82 have been completed and were producing at September 30, 2023. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 86 wells is approximately $121 million, of which approximately $120 million was incurred as of September 30, 2023.

8

The Partnership estimates the approximate $1 million in capital expenditures to fully pay for its recently completed wells along with the remaining four (4) wells in various stages of drilling and completion will be incurred through the fourth quarter of 2023 based on the best available information regarding current capital investment plans from its operators. However, many factors outside the Partnership’s control make it difficult to predict the amount and timing of capital expenditures, and estimated capital expenditures could be significantly different from amounts actually invested.

Note 4. Debt

Revolving Credit Facility

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 $59,000 of the deferred loan costs remain unamortized as of September 30, 2023; these costs are included in Other current assets, net on the Partnership’s consolidated balance sheet. The Partnership also is required to pay an annual fee to the Lender of $30,000, and an unused facility fee of 0.25% on the unused portion of the Revolving Credit Facility, based on borrowings outstanding during a quarter. The maturity date is March 1, 2024.

At closing, the Partnership borrowed approximately $40 million. The proceeds were used to pay the $40 million outstanding balance and accrued interest on the Partnership’s previous credit facility. Any further advances under the BF Credit Facility are to be used to fund capital expenditures for the development of the Partnership’s undrilled acreage. Under the terms of the BF Loan Agreement, the Partnership may make voluntary prepayments, in whole or in part, at any time with no penalty. The BF Credit Facility is secured by a mortgage and first lien position on at least 90% of the Partnership’s producing wells.

Under the BF Loan Agreement, the initial borrowing base was $60 million. The 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. In conjunction with the Lender’s September 1, 2023 redetermination analysis, the Lender confirmed the fixed borrowing base of $30 million and there would be no required Monthly Commitment Reduction. The Lender is also permitted to cause the borrowing base to be redetermined up to two times during a 12-month period. Outstanding borrowings under the BF Credit Facility cannot exceed the lesser of the borrowing base or the Maximum Credit Amount at any time. The interest rate is equal to the Wall Street Journal Prime Rate plus 0.50%, with a floor of 4.00%.

Also, the BF Loan Agreement requires the Partnership to maintain a risk management program to manage the commodity price risk of the Partnership’s future oil and gas production under certain conditions. As amended in August 2022, the Partnership is not required to enter into future hedging transactions as long as the Partnership maintains a BF Credit Facility utilization rate of less than or equal to 20% of the Partnership’s PV-9 (defined as the net present value, discounted at 9% per annum), as calculated by the Lender during the Lender’s scheduled semi-annual redeterminations described above. However, the Partnership must hedge at least 50% of its rolling 12-month projected future production if the Partnership’s utilization of the BF Credit Facility is greater than 20% but less than or equal to 30% of PV-9, and at least 50% of its rolling 24-month projected future production if the Partnership’s utilization of the Revolving Credit Facility is greater than 30% of PV-9. Based on the Partnership’s utilization of the BF Credit Facility and Lender’s current calculation of PV-9, the Partnership was not subject to any hedging requirements under the amended BF Loan Agreement as of September 30, 2023.

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

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

● 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 (“Current Ratio”)

9

As amended in March 2023, the Partnership is permitted to make distributions to its limited partners so long as the Partnership is in compliance with its debt service coverage ratio and no other event of default has occurred. The March 2023 amendment to the BF Loan Agreement eliminated the restriction on the Partnership’s ability to pay limited partner distributions if the outstanding balance of the BF Credit Facility was greater than 50% of the lesser of (i) the Maximum Credit Amount or (ii) the current borrowing base. As amended in June 2023, beginning with the quarter ended June 30, 2023, the Partnership is permitted to exclude all loans outstanding under the BF Loan Agreement (i.e., the “BF Credit Facility”) in total current liabilities when calculating the Current Ratio.

At September 30, 2023, the outstanding balance on the BF Credit Facility was approximately $7.0 million, and the interest rate was 9.00%. The Partnership was in compliance with all covenants as of September 30, 2023.

At September 30, 2023 and December 31, 2022, the outstanding balances on the BF Credit Facility of approximately $7.0 million and $22.6 million, respectively, approximated the fair market value of the BF Credit Facility. The Partnership estimated the fair value of its credit facility by discounting the future cash flows of the instrument at estimated market rates consistent with the maturity of a debt obligation with similar credit terms and credit characteristics, which are Level 3 inputs under the fair value hierarchy. Market rates take into consideration general market conditions and maturity.

Note 5. Asset Retirement Obligations

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

	2023		2022
Balance at January 1	$	1,966,738	$	1,791,341
Well additions		1,086		73,508
Accretion		80,469		71,993
Revisions		-		111,264
Balance at September 30	$	2,048,293	$	2,048,106

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 three and nine months ended September 30, 2023 and 2022, 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 September 30, 2023 and December 31, 2022.

	Fair Value Measurements at September 30, 2023
	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	$	-	$	(513,275	)	$	-
Total	$	-	$	(513,275	)	$	-

	Fair Value Measurements at December 31, 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	$	-	$	(3,173,965	)	$	-
Total	$	-	$	(3,173,965	)	$	-

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, using various methodologies and significant observable inputs. The fair value of the commodity derivatives noted above are included in the Partnership’s consolidated balance sheets at September 30, 2023 and December 31, 2022. See additional detail in Note 7. Risk Management.

Fair Value of Other Financial Instruments

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

Note 7. Risk Management

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

In July 2021, the Partnership began its risk management program required under the BF Loan Agreement (see Note 4. Debt). To meet BF Loan Agreement requirements, the Partnership entered in to costless collar derivative contracts for the period from July 2021 to September 2023; costless collar contracts 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 the BF Loan Agreement, and the contracts were settled monthly. With the settlement of the September oil and natural gas production contracts during the third quarter of 2023, the Partnership is currently not required to hedge future production under the BF Loan Agreement; therefore, the Partnership has no outstanding derivative contracts as of September 30, 2023.

The Partnership’s derivative liability as of September 30, 2023 of approximately $0.5 million represents the settlement loss on the September 2023 oil contract. The Partnership’s derivative instruments were also in a loss position as of December 31, 2022, so the Partnership recognized a current Derivative liability of approximately $3.2 million on the Partnership’s consolidated balance sheet.

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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 September 30, 2023			Three Months Ended September 30, 2022			Nine Months Ended September 30, 2023			Nine Months Ended September 30, 2022
Settlement loss on matured derivatives	$	(1,284,710	)	$	(1,927,290	)	$	(1,780,610	)	$	(5,640,990	)
Gain (loss) on mark-to-market of derivatives, net		513,828			6,227,340			3,033,037			(1,167,463	)
Gain (loss) on derivatives, net	$	(770,882	)	$	4,300,050		$	1,252,427		$	(6,808,453	)

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

Note 8. Capital Contribution and Partners’ Equity

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

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

Under the agreement with David Lerner Associates, Inc. (the “Dealer Manager”), the Dealer Manager received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Dealer Manager will also be paid a contingent incentive fee, which is a cash payment of up to an amount equal to 4% of gross proceeds of the common units sold based on the performance of the Partnership. Based on the common units sold through the best-efforts offering, the total contingent fee is a maximum of approximately $15.0 million.

Prior to “Payout,” which is defined below, all of the distributions made by the Partnership, if any, will be paid to the holders of common units. Accordingly, the Partnership will not make any distributions with respect to the Incentive Distribution Rights or with respect to Class B units and will not make the contingent incentive payments to the Dealer Manager, until Payout occurs.

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

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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.

For the three and nine months ended September 30, 2023, the Partnership paid distributions of $0.350000 and $1.075753 per common unit, or $6.6 million and $20.4 million, respectively. In addition, the Partnership declared a monthly cash distribution to its holders of common units of $0.12 per common unit for the month of September 2023. The declared distribution of approximately $2.3 million, which is included in Accounts payable and accrued expenses on the Partnership’s balance sheet as of September 30, 2023, was paid on October 4, 2023 to the common unit holders on record as of September 30, 2023.

For the three and nine months ended September 30, 2022, the Partnership paid distributions of $0.375891 and $1.047123, or $7.1 million and $19.9 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 described in Income Tax in Note 2. Summary of Significant Accounting Policies, in May 2023, the Partnership paid a withholding tax of approximately $0.012830 per common unit to the state of North Dakota on behalf of its limited partners related to tax year 2021. The payment of this withholding tax reduced the total unpaid Payout Accrual. Therefore, as of September 30, 2023, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.374841 per common unit, or approximately $45 million.

Note 9. Related Parties

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

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

For the three and nine months ended September 30, 2023, approximately $68,000 and $172,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At September 30, 2023, approximately $68,000 was due to a member of the General Partner and is included in Accounts payable and accrued expenses in the consolidated balance sheets. For the three and nine months ended September 30, 2022, approximately $32,000 and $108,000 of general and administrative costs were incurred by a member of the General Partner and have been reimbursed by the Partnership.

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

On April 5, 2023, the Partnership and ER12 entered into an agreement (the “Agreement”) with Messrs. Knight, McKenney, Keating and Mallick, and various affiliates of each, including the Administrator. Pursuant to the Agreement, the ASA was terminated effective immediately, subject to a 60-day transition period to transition the services being provided by the Administrator to Partnership and ER12 management. All Administrator costs and expenses were accumulated (based on actual costs incurred with no mark-up or profit to the Administrator) and approved by the Partnership prior to reimbursement. Costs and expenses reimbursed under the ASA included, but were not limited to, employee wages and benefits, rent for office space and network and information technology support. Other expenses, such as business travel costs and accounting, legal or banking services, were not incurred by the Administrator on behalf of the Partnership without prior express written consent of the Partnership. Costs and expenses attributable to the services performed by the Administrator under the ASA have been reimbursed by the Partnership. For the nine months ended September 30, 2023, approximately $165,000 of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator. For the three and nine months ended September 30, 2022, approximately $149,000 and $423,000 of costs and expenses subject to the ASA were reimbursed by the Partnership to the Administrator.

Also pursuant to the Agreement, the affiliates of Messrs. Keating and Mallick sold (i) all interests in the General Partner; (ii) all common unit interests in the Partnership; (iii) all Class B Unit interests in the Partnership; and (iv) their Class B Unit interests in ER12’s General Partner to an affiliate of Mr. Knight and withdrew as members of General Partner and ER12’s General Partner. Each of Messrs. Keating and Mallick also resigned their positions as director and as Co-Chief Operating Officer of the General Partner. Additionally, Clifford J. Merritt resigned as President of the General Partner. Prior to the execution of the Agreement, the Administrator assisted 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 paid 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.

Note 10. Subsequent Events

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

In October 2023, the Partnership declared a monthly cash distribution to its holders of common units of $0.11 per outstanding common unit for the month of October 2023. The distribution of approximately $2.1 million was paid on November 3, 2023 to common unit holders on record as of October 31, 2023.

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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 conflict between Russia and Ukraine on the global energy markets;

● any impact of the ongoing conflict in the Middle East among several countries 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, 2022 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, 2022.

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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 86 new wells in the Sanish field, of which 82 have been completed and were producing as of September 30, 2023. The Partnership has four (4) wells that are in-process as of September 30, 2023 that are anticipated to be completed during the fourth quarter of 2023. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 86 wells is approximately $120 million, of which approximately $119 million had been incurred as of September 30, 2023. See additional detail in “Oil and Natural Gas Properties” below.

As a result of its acquisitions and completed drilling during the period of ownership, as of September 30, 2023, the Partnership owned an approximate 24% non-operated working interest in 295 producing wells, an estimated approximate 14% non-operated working interest in four wells in various stages of the drilling and completion process and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). Chord Energy Corporation (“Chord”), the product of a merger between Whiting Petroleum Corporation and Oasis Petroleum Inc., is one of the largest producers in the basin and operates substantially all of the Sanish Field Assets.

Current Price Environment

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

Commodity prices strengthened throughout 2021, primarily driven by increased demand resulting from the initial recovery from the COVID-19 pandemic and production restraint by domestic and foreign operators. The start of the military conflict between Russia and Ukraine in March 2022 (which remains ongoing), related economic sanctions imposed on Russia and additional production growth by OPEC further exacerbated supply shortages, causing oil prices to peak at over $120 per barrel during the second quarter of 2022. Since, persistent concerns about a recession and short-term softening of global and domestic demand contributed to lower commodity prices during the first half of 2023.By the end of the third quarter of 2023, oil prices had rebounded to approximately $90 per barrel, primarily due to Saudi Arabia and Russia continuing their commitments to production cuts, the domestic economy outperforming expectations, and American-based producers remaining cautious to ramp up production.

On October 7, 2023, the conflict between Israel and Palestinian territories was reignited when Hamas, a militant group in control of Gaza, carried out a surprise attack on Israeli cities and towns near the Gaza strip. Both sides have been in constant combat since. The length and outcome of the military conflicts between Ukraine and Russia as well as Israel and Hamas are highly unpredictable, and further escalation of these conflicts could lead to significant market and other disruptions, such as volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, political and social instability and other material and adverse effects on macroeconomic conditions. The short- and long-term impact of these conflicts on the operations and financial condition of the Partnership and the global economy is uncertain.

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

	Three Months Ended September 30,				Percent			Nine Months Ended September 30,				Percent
	2023		2022		Change			2023		2022		Change
Average market closing prices (1)
Oil (per Bbl)	$	82.22	$	91.43		-10.1	%	$	77.28	$	98.25		-21.3	%
Natural gas (per Mcf)	$	2.59	$	8.03		-67.7	%	$	2.46	$	6.74		-63.5	%

(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 nine months ended September 30, 2023 and 2022.

	Three Months Ended September 30,													Nine Months Ended September 30,
	2023		Percent of Revenue			2022		Percent of Revenue			Percent Change			2023		Percent of Revenue			2022		Percent of Revenue			Percent Change
Total revenues	$	24,076,170		100.0	%	$	32,976,928		100.0	%		-27.0	%	$	76,123,749		100.0	%	$	82,902,788		100.0	%		-8.2	%
Production expenses		6,405,176		26.6	%		4,402,718		13.4	%		45.5	%		20,605,740		27.1	%		12,838,368		15.5	%		60.5	%
Production taxes		1,931,082		8.0	%		2,602,071		7.9	%		-25.8	%		6,029,821		7.9	%		6,363,511		7.7	%		-5.2	%
Depreciation, depletion, amortization and accretion		6,519,826		27.1	%		5,777,217		17.5	%		12.9	%		19,992,113		26.3	%		14,856,872		17.9	%		34.6	%
General and administrative expenses		297,531		1.2	%		480,776		1.5	%		-38.1	%		1,381,386		1.8	%		1,556,868		1.9	%		-11.3	%
Production (BOE):
Oil		257,363					309,744					-16.9	%		864,564					737,830					17.2	%
Natural gas		67,764					61,563					10.1	%		207,166					164,098					26.2	%
Natural gas liquids		67,519					52,673					28.2	%		198,138					133,239					48.7	%
Total		392,646					423,980					-7.4	%		1,269,868					1,035,167					22.7	%
Average sales price per unit:
Oil (per Bbl)	$	82.86				$	89.79					-7.7	%	$	77.90				$	93.86					-17.0	%
Natural gas (per Mcf)		2.06					7.82					-73.7	%		2.40					7.04					-65.9	%
Natural gas liquids (per Bbl)		28.34					43.26					-34.5	%		29.24					50.41					-42.0	%
Combined (per BOE)		61.32					77.78					-21.2	%		59.95					80.09					-25.1	%
Average unit cost per BOE:
Production expenses		16.31					10.38					57.1	%		16.23					12.40					30.9	%
Production taxes		4.92					6.14					-19.9	%		4.75					6.15					-22.8	%
Depreciation, depletion, amortization and accretion		16.60					13.63					21.9	%		15.74					14.35					9.7	%
Capital expenditures	$	4,978,103				$	14,704,221							$	8,769,977				$	41,192,067

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Oil, natural gas and NGL revenues

For the three months ended September 30, 2023, revenues from oil, natural gas and NGL sales were $24.1 million. Revenues for the sale of crude oil were $21.3 million, which resulted in a realized price of $82.86 per barrel. Revenues for the sale of natural gas were $0.8 million, which resulted in a realized price of $2.06 per Mcf. Revenues for the sale of NGLs were $1.9 million, which resulted in a realized price of $28.34 per BOE of sold production. For the three months ended September 30, 2022, revenues from oil, natural gas and NGL sales were $33.0 million. Revenues for the sale of crude oil were $27.8 million, which resulted in a realized price of $89.79 per barrel. Revenues for the sale of natural gas were $2.9 million, which resulted in a realized price of $7.82 per Mcf. Revenues for the sale of NGLs were $2.3 million, which resulted in a realized price of $43.26 per BOE of sold production.

For the nine months ended September 30, 2023, revenues from oil, natural gas and NGL sales were $76.1 million. Revenues for the sale of crude oil were $67.3 million, which resulted in a realized price of $77.90 per barrel. Revenues for the sale of natural gas were $3.0 million, which resulted in a realized price of $2.40 per Mcf. Revenues for the sale of NGLs were $5.8 million, which resulted in a realized price of $29.24 per BOE of sold production. For the nine months ended September 30, 2022, revenues from oil, natural gas and NGL sales were $82.9 million. Revenues for the sale of crude oil were $69.3 million, which resulted in a realized price of $93.86 per barrel. Revenues for the sale of natural gas were $6.9 million, which resulted in a realized price of $7.04 per Mcf. Revenues for the sale of NGLs were $6.7 million, which resulted in a realized price of $50.41 per BOE of sold production.

The Partnership completed 29 wells during the second, third and fourth quarters of 2022, and these new wells provided an immediate boost in production during the third and fourth quarters of 2022 as well as the first quarter of 2023. When comparing the nine-month periods ended September 30, 2023 and 2022, the completion of these new wells provided an increase to 2023 production, with sold production for the Sanish Field Assets approximating 4,700 BOE per day in 2023 to 3,800 BOE per day in 2022. Sold production was approximately 4,300 BOE per day and 4,600 BOE per day for three months ended September 30, 2023 and 2022.

The Partnership’s total revenues from oil, natural gas and NGL sales in 2023 have been negatively impacted by decreases in market prices of oil and natural gas when compared to the same periods of 2022, of which the factors for the reduction in market prices were discussed in Current Price Environment above. 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.

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. The Dakota Access Pipeline is a significant pipeline that transports oil and natural gas from North Dakota fields. Its use by operators in the region is currently in ongoing litigation in the United States. If use of the Dakota Access Pipeline or any other 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 oil differentials, realized sales prices, results of operations and/or cash flows.

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Operating costs and expenses

Production expenses

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

For the three months ended September 30, 2023 and 2022, production expenses were $6.4 million and $4.4 million, respectively, and production expenses per BOE of sold production were $16.31 and $10.38, respectively. For the nine months ended September 30, 2023 and 2022, production expenses were $20.6 million and $12.8 million, respectively, and production expenses per BOE of sold production were $16.23 and $12.40, respectively. The rise in production expenses per BOE is the result of the following: (1) higher gathering and processing expenses tied to oil production in 2023; (2) downward pressure on natural gas prices as well as adjustments to operator contracts resulted in additional marketing and selling costs to sell the Partnership’s natural gas and NGLs during 2023; and (3) an increase in workover expenses as certain of the Partnership’s newest producing wells have scheduled maintenance after reaching certain minimum production thresholds. Lingering inflation also has kept production expenses elevated when compared to prior periods.

Production taxes

Taxes on the production and extraction of oil and gas are regulated and set by North Dakota tax authorities. Taxes on the sale of gas and NGL products are less than taxes levied on the sale of oil. Therefore, production taxes as a percentage of revenue may fluctuate dependent upon the ratio of sales of natural gas and NGLs to total sales. Production taxes for the three months ended September 30, 2023 and 2022 were $1.9 million (8% of revenue) and $2.6 million (8% of revenue), respectively. Production taxes for the nine months ended September 30, 2023 and 2022 were $6.0 million (8% of revenue) and $6.4 million (8% of revenue), respectively.

General and administrative expenses

The principal components of general and administrative expense are accounting, legal and consulting fees. General and administrative expenses for the three months ended September 30, 2023 and 2022 were $0.3 million and $0.5 million, respectively. General and administrative expenses for the nine months ended September 30, 2023 and 2022 were $1.4 million and $1.6 million, respectively.

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

DD&A of capitalized drilling and development costs of producing oil, natural gas and NGL properties are computed using the unit-of-production method on a field basis based on total estimated proved developed oil, natural gas and NGL reserves. Costs of acquiring proved properties are depleted using the unit-of-production method on a field basis based on total estimated proved developed and undeveloped reserves. DD&A for the three months ended September 30, 2023 and 2022 was $6.5 million and $5.8 million, and DD&A per BOE of sold production was $16.60 and $13.63, respectively. DD&A for the nine months ended September 30, 2023 and 2022 was $20.0 million and $14.9 million, and DD&A per BOE of sold production was $15.74 and $14.35, respectively.

The increase in DD&A expense per BOE of production for the three and nine months ended September 30, 2023 is primarily due to the decrease of the Partnership’s estimated proved undeveloped reserves during the most recent reserves analyses (as of June 30, 2023) resulting from changes to well production forecasts.

Gain (loss) on derivatives, net

Participation in the oil and gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership’s future earnings are subject to these risks. Periodically, the Partnership utilizes derivative contracts to manage the commodity price risk on the Partnership’s future oil production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations. In September 2023, the Partnership settled its final future oil production contract that was required under the original terms and conditions of the BF Loan Agreement.

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The Partnership did not designate its 2022 or 2023 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 September 30, 2023			Three Months Ended September 30, 2022			Nine Months Ended September 30, 2023			Nine Months Ended September 30, 2022
Settlement loss on matured derivatives	$	(1,284,710	)	$	(1,927,290	)	$	(1,780,610	)	$	(5,640,990	)
Gain (loss) on mark-to-market of derivatives, net		513,828			6,227,340			3,033,037			(1,167,463	)
Gain (loss) on derivatives, net	$	(770,882	)	$	4,300,050		$	1,252,427		$	(6,808,453	)

The Partnership’s oil production contracts that expired during the three months ended September 30, 2023 represented approximately 76,000 barrels of oil. The Partnership realized a loss of approximately $1.3 million, equating to an approximate loss of $16.90 per barrel, on its hedged oil production, and an approximate loss of $4.99 per barrel of total sold oil production for the third quarter of 2023. The Partnership’s natural gas production contracts that expired during the three months ended September 30, 2023 represented 63,000 MMBtu of produced natural gas; however, these natural gas production contracts were settled at no cost or benefit to the Partnership, as contract prices on settlement dates were within the established floor and ceiling prices.

The Partnership’s oil production contracts that expired during the nine months ended September 30, 2023 represented approximately 224,000 barrels of oil. The Partnership realized a loss of approximately $1.8 million, equating to an approximate loss of $7.95 per barrel, on its hedged oil production, and an approximate loss of $2.06 per barrel of total year-to-date sold oil production through the third quarter of 2023. The Partnership’s natural gas production contracts that expired during the nine months ended September 30, 2023 represented 275,000 MMBtu of produced natural gas; however, these natural gas production contracts were settled at no cost or benefit to the Partnership, as contract prices on settlement dates were within the established floor and ceiling prices.

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

The Partnership’s oil production contracts that expired during the nine months ended September 30, 2022 represented approximately 254,000 barrels of oil. The Partnership realized a loss of approximately $5.2 million, equating to an approximate loss of $20.62 per barrel, on its hedged oil production, and an approximate loss of $7.10 per barrel of total sold oil production through the first three quarters of 2022. The Partnership’s natural gas production contracts that expired during the nine months ended September 30, 2022 represented 290,000 MMBtu of produced natural gas. The Partnership realized a loss of approximately $0.4 million, equating to an approximate loss of $1.39 per MMBtu, on its hedged natural gas production, and an approximate loss $0.41 per MMBtu of total sold natural gas production through the first three quarters of 2022.

The mark-to-market (non-cash, unrealized) gains or losses recorded for the three and nine months ended September 30, 2023 and 2022 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 Partnership does not have any outstanding derivative contracts as of September 30, 2023.

Interest expense, net

Interest expense, net, for the three months ended September 30, 2023 and 2022 was $0.2 million and $0.4 million, respectively. Interest expense, net, for the nine months ended September 30, 2023 and 2022 was $1.0 million and $0.9 million, respectively. The Partnership’s interest expense increased through the first three quarters of 2023, compared to the same period of 2022, primarily due to an increase in interest rates. The primary component of Interest expense, net, is interest expense on the BF Credit Facility.

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Supplemental Non-GAAP Measure

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

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

The following table reconciles the Partnership’s GAAP net income to Adjusted EBITDAX for the three and nine months ended September 30, 2023 and 2022.

	Three Months Ended September 30, 2023			Three Months Ended September 30, 2022			Nine Months Ended September 30, 2023			Nine Months Ended September 30, 2022
Net income	$	7,924,062		$	23,602,863		$	28,345,839		$	39,563,173
Interest expense, net		227,611			411,333			1,021,277			915,543
Depreciation, depletion, amortization and accretion		6,519,826			5,777,217			19,992,113			14,856,872
Exploration expenses		-			-			-			-
Non-cash (gain) loss on mark-to-market of derivatives, net		(513,828	)		(6,227,340	)		(3,033,037	)		1,167,463
Adjusted EBITDAX	$	14,157,671		$	23,564,073		$	46,326,192		$	56,503,051

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 had approximately $3.7 million in cash on hand and approximately $26 million in availability under the BF Credit Facility at the time of filing of this Form 10-Q. The Partnership has also generated approximately $47.5 million in cash flow from operating activities for the nine months ended September 30, 2023.

The Partnership anticipates its cash on-hand, cash flow from operations and availability under the BF Credit Facility will be adequate to meet its liquidity requirements for at least the next 12 months, including completing the outstanding capital expenditures discussed below. The BF Credit Facility matures on March 1, 2024. The Partnership is working with its Lender to ensure the Partnership has an available credit facility to use, as necessary, for future capital commitments and drilling opportunities (see below in “Oil and Natural Gas Properties”). Based on the March 2023 BF Loan Agreement amendment, the Partnership is permitted to make distributions to limited partners regardless of BF Credit Facility utilization so long as the Partnership is in compliance with the applicable covenants and no other event of default has occurred. 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 BF 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.

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Financing

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

Partners’ Equity

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

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

Distributions

For the three and nine months ended September 30, 2023, the Partnership paid distributions of $0.350000 and $1.075753 per common unit, or $6.6 million and $20.4 million, respectively. In addition, the Partnership declared a monthly cash distribution to its holders of common units of $0.12 per common unit for the month of September 2023. The declared distribution of approximately $2.3 million, which is included in Accounts payable and accrued expenses on the Partnership’s balance sheet as of September 30, 2023, was paid on October 4, 2023 to the common unit holders on record as of September 30, 2023.

For the three and nine months ended September 30, 2022, the Partnership paid distributions of $0.375891 and $1.047123, or $7.1 million and $19.9 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 of September 30, 2023, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.374841 per common unit, or approximately $45 million.

Oil and Natural Gas Properties

The Partnership incurred approximately $8.8 million and $41.2 million in capital expenditures for the nine months ended September 30, 2023 and 2022, respectively.

Since the beginning of 2019, the Partnership has elected to participate in the drilling and completion of 80 new wells in the Sanish field. As of September 30, 2023, approximately 76 of these 80 wells have been completed and were producing; the Partnership has an approximate non-operated working interest of 21% in these 76 wells. The Partnership has an estimated approximate non-operated working interest of 14% in four wells that are in-process as of September 30, 2023. In total, the Partnership’s estimated share of capital expenditures for the drilling and completion of these 80 wells is approximately $113 million, of which approximately $112 million was incurred as of September 30, 2023.

The Partnership anticipates its operator will complete the remaining four wells during the fourth quarter of 2023; however, completion of the wells is not in the Partnership’s control. The Partnership estimates the majority of the approximate $1 million in capital expenditures to fully pay for the remaining four wells in the completion process will be incurred during the fourth quarter of 2023 based on the best available information regarding current capital investment plans from its operators. In addition, during the fourth quarter of 2023, the Partnership elected to participate in the drilling of six (6) new wells proposed by Chord. The Partnership has an estimated approximate 20% non-operated working interest in these six wells, and the estimate of capital costs to complete these wells is approximately $12 million. Based on best information available from its operator, the drilling and completion of these six wells will occur during the fourth quarter of 2023 and first quarter of 2024, and the related capital expenditures will be incurred through the second quarter of 2024.

Aside from receiving well proposals, many factors outside the Partnership’s control make it difficult to predict the amount and timing of capital expenditures for 2024 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 2024 through 2028 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.

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As described above, the Partnership’s liquidity is currently dependent upon cash on-hand, cash from operations and availability under the BF 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 October 2023, the Partnership paid approximately $2.3 million, or $0.12 per outstanding common unit, in distributions to its holders of common units.

In October 2023, the Partnership declared a monthly cash distribution to its holders of common units of $0.11 per outstanding common unit for the month of October 2023. The distribution of approximately $2.1 million was paid on November 3, 2023 to common unit holders on record as of October 31, 2023.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Partnership’s BF 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 September 30, 2023 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 September 30, 2023 that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal controls over financial reporting.

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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 2022 Annual Report on Form 10-K. There have been no material changes to the risk factors previously disclosed in the 2022 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 September 30, 2023 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 September 30, 2023, formatted in iXBRL and contained in Exhibit 101

*Filed herewith.

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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: November 13, 2023

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