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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended June 30, 2026

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

FOR THE TRANSITION PERIOD FROM TO

Commission File Number 000-55615

Energy 11, L.P.

(Exact name of registrant as specified in its charter)

Delaware		46-3070515
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

120 W 3rd Street, Suite 220 Fort Worth, Texas		76102
(Address of principal executive offices)		(Zip Code)

(817) 882-9192

(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑

As of August 12, 2026, the Partnership had 18,973,474 common units outstanding.

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Energy 11, L.P.

Form 10-Q

Index

		Page Number
PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)	3

	Consolidated Balance Sheets – June 30, 2026 and December 31, 2025	3

	Consolidated Statements of Operations – Three and six months ended June 30, 2026 and 2025	4

	Consolidated Statements of Partners’ Equity – Three and six months ended June 30, 2026 and 2025	5

	Consolidated Statements of Cash Flows – Six months ended June 30, 2026 and 2025	6

	Notes to Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	26

Item 4.	Controls and Procedures	26

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	27

Item 1A.	Risk Factors	27

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	27

Item 3.	Defaults upon Senior Securities	27

Item 4.	Mine Safety Disclosures	27

Item 5.	Other Information	27

Item 6.	Exhibits	27

Signatures		28

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Energy 11, L.P.

Consolidated Balance Sheets

	*June 30,*			*December 31,*
	*2026*			*2025*
	(unaudited)
Assets
Cash and cash equivalents	$	8,837,602		$	6,897,207
Accounts receivable		8,592,270			6,216,739
Derivative asset		1,081,062			-
Other current assets, net		-			101,020
Total Current Assets		18,510,934			13,214,966

Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $213,993,804 and $203,009,147, respectively		305,908,673			315,539,034
Total Assets	$	324,419,607		$	328,754,000

Liabilities
Accounts payable and accrued expenses	$	8,051,303		$	6,021,436
Total Current Liabilities		8,051,303			6,021,436

Asset retirement obligations		2,289,019			2,234,607
Total Liabilities		10,340,322			8,256,043

Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)		314,081,012			320,499,684
General partner's interest		(1,727	)		(1,727	)
Class B Units (62,500 units issued and outstanding, respectively)		-			-
Total Partners’ Equity		314,079,285			320,497,957

Total Liabilities and Partners’ Equity	$	324,419,607		$	328,754,000

See notes to consolidated financial statements.

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Energy 11, L.P.

Consolidated Statements of Operations

(Unaudited)

	*Three Months Ended*			*Three Months Ended*			*Six Months Ended*			*Six Months Ended*
	*June 30, 2026*			*June 30, 2025*			*June 30, 2026*			*June 30, 2025*

Revenues
Oil	$	13,650,570		$	13,732,158		$	25,141,646		$	30,614,673
Natural gas		519,784			989,832			2,420,615			2,681,702
Natural gas liquids		2,257,975			1,821,422			3,619,268			4,106,968
Total revenue		16,428,329			16,543,412			31,181,529			37,403,343

Operating costs and expenses
Production expenses		4,769,910			6,069,324			9,358,053			12,014,097
Production taxes		1,125,531			1,087,999			2,071,406			2,578,549
General and administrative expenses		200,734			305,068			587,144			827,751
Depreciation, depletion, amortization and accretion		5,332,120			7,194,457			11,039,068			14,447,032
Total operating costs and expenses		11,428,295			14,656,848			23,055,671			29,867,429

Operating income		5,000,034			1,886,564			8,125,858			7,535,914

Gain on derivatives, net		1,068,434			-			1,068,434			-
Interest expense, net		(6,320	)		(27,735	)		(54,715	)		(95,158	)
Total other income (expense), net		1,062,114			(27,735	)		1,013,719			(95,158	)

Net income	$	6,062,148		$	1,858,829		$	9,139,577		$	7,440,756

Basic and diluted net income per common unit	$	0.32		$	0.10		$	0.48		$	0.39

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.

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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, 2024		18,973,474	$	338,843,557			62,500	$	-	$	(1,727	)	$	338,841,830
Distributions declared to common units ($0.35 per unit)		-		(6,640,716	)		-		-		-			(6,640,716	)
Net income - three months ended March 31, 2025		-		5,581,927			-		-		-			5,581,927
Balances - March 31, 2025		18,973,474		337,784,768			62,500		-		(1,727	)		337,783,041
Distributions declared to common units ($0.35 per unit)		-		(6,640,716	)		-		-		-			(6,640,716	)
State tax withholding payments made on behalf of limited partners		-		(400,000	)		-		-		-			(400,000	)
Reversal of estimated state tax withholding for limited partners		-		400,000			-		-		-			400,000
Net income - three months ended June 30, 2025		-		1,858,829			-		-		-			1,858,829
Balances - June 30, 2025		18,973,474	$	333,002,881			62,500	$	-	$	(1,727	)	$	333,001,154

Balances - December 31, 2025		18,973,474	$	320,499,684			62,500	$	-	$	(1,727	)	$	320,497,957
Distributions declared to common units ($0.35 per unit)		-		(6,640,716	)		-		-		-			(6,640,716	)
Net income - three months ended March 31, 2026		-		3,077,429			-		-		-			3,077,429
Balances - March 31, 2026		18,973,474		316,936,397			62,500		-		(1,727	)		316,934,670
Distributions declared to common units ($0.47 per unit)		-		(8,917,533	)		-		-		-			(8,917,533	)
State tax withholding payments made on behalf of limited partners		-		(675,000	)		-		-		-			(675,000	)
Reversal of estimated state tax withholding for limited partners		-		675,000			-		-		-			675,000
Net income - three months ended June 30, 2026		-		6,062,148			-		-		-			6,062,148
Balances - June 30, 2026		18,973,474	$	314,081,012			62,500	$	-	$	(1,727	)	$	314,079,285

See notes to consolidated financial statements.

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Energy 11, L.P.

Consolidated Statements of Cash Flows

(Unaudited)

	*Six Months Ended*			*Six Months Ended*
	*June 30, 2026*			*June 30, 2025*

Cash flow from operating activities:
Net income	$	9,139,577		$	7,440,756

Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion		11,039,068			14,447,032
Gain on mark-to-market of derivatives, net		(1,081,062	)		-

Changes in operating assets and liabilities:
Accounts receivable		(2,375,531	)		4,528,648
Other assets		101,020			125,388
Accounts payable and accrued expenses		(274,281	)		282,504

Net cash flow provided by operating activities		16,548,791			26,824,328

Cash flow from investing activities:
Additions to oil and natural gas properties		(651,964	)		(2,507,545	)

Net cash flow used in investing activities		(651,964	)		(2,507,545	)

Cash flow from financing activities:
Payments on BancFirst revolving credit facility		-			(5,000,000	)
Payments for state withholding taxes on behalf of limited partners		(675,000	)		(400,000	)
Distributions paid to limited partners		(13,281,432	)		(13,281,432	)

Net cash flow used in financing activities		(13,956,432	)		(18,681,432	)

Increase in cash and cash equivalents		1,940,395			5,635,351
Cash and cash equivalents, beginning of period		6,897,207			227,859

Cash and cash equivalents, end of period	$	8,837,602		$	5,863,210

Interest paid	$	23,125		$	85,457

Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$	758,524		$	1,416,003

See notes to consolidated financial statements.

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Energy 11, L.P.

Notes to Consolidated Financial Statements

June 30, 2026

(Unaudited)

Note 1. Partnership Organization

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

As of June 30, 2026, the Partnership owned an approximate 24% non-operated working interest in 308 producing wells and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). Chord Energy Corporation (“Chord”) 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 Annual Report on Form 10-K for the year ended December 31, 2025. Operating results for the three and six months ended June 30, 2026 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2026.

Segment Information

The Partnership has identified only one reportable business segment, which as a non-operated interest owner of the Sanish Field Assets, is the production and sale of oil, natural gas and natural gas liquids ("NGLs"). All of the Partnership’s operations and assets are located in North Dakota, and substantially all of its revenues are attributable to United States customers.

The operating results of the Partnership’s single reportable segment are evaluated by the General Partner’s Chief Executive Officer, who has been determined to be the Partnership’s Chief Operating Decision Maker (“CODM”), to make key operating decisions, such as the allocation of resources and the evaluation of operating segment performance. The primary measure of profit and loss evaluated by the Partnership’s CODM for its single reportable segment is net income. Net income, total assets and all significant segment expense items are presented in the Partnership’s consolidated financial statements and notes to the consolidated financial statements.

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Cash and Cash Equivalents

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

Use of Estimates

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

Revenue Recognition

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

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

Accounts Receivable and Concentration of Credit Risk

For the quarter ended June 30, 2026, 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 June 30, 2026 and December 31, 2025, 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 the business activities of the Partnership.

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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. In accordance with its settlements with the state of North Dakota, the Partnership made payments of (i) approximately $243,000 (approximately $0.013 per common unit) in May 2023 for tax year 2021; (ii) approximately $353,000 (approximately $0.019 per common unit) in April 2024 for tax year 2022; (iii) approximately $869,000 (approximately $0.046 per common unit) in April 2024 for tax year 2023; (iv) approximately $400,000 (approximately $0.021 per common unit) in April 2025 for tax year 2024; and (v) approximately $675,000 (approximately $0.036 per common unit) in April 2026 for tax year 2025.

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 six months ended June 30, 2026. 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 7) will occur.

Recently Issued Accounting Standards

In November 2024, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) No. 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. This standard requires that public business entities disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. This ASU is effective for annual reporting periods beginning after December 15, 2026, and interim periods within annual reporting periods beginning after December 15, 2027. Early adoption is permitted. The Partnership is currently evaluating this ASU to determine its impact on the Partnership’s financial statements and related disclosures.

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Note 3. Oil and Natural Gas Investments

The Partnership incurred approximately $1.4 million in capital expenditures for the six-month period ending June 30, 2026. The Partnership has drilled and completed 101 new wells since the beginning of 2018, with the Partnership’s estimated share of capital expenditures for the drilling and completion of those 101 wells totaling approximately $148.0 million.

Note 4. Debt

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 provided for a revolving credit facility (“BF Credit Facility”) with an approved maximum credit amount of $60 million, subject to borrowing base restrictions. On February 27, 2024, the Partnership and its Lender entered into an amendment (“Fifth Amendment”) to the BF Loan Agreement, effective March 1, 2024, that renewed and extended the BF Credit Facility for two additional years to March 1, 2026. Under the terms and conditions of the Fifth Amendment, the Partnership paid a loan fee to the Lender of $100,000, and the borrowing base of the BF Credit Facility was $20 million. Total loan costs associated with the Fifth Amendment, which totaled approximately $121,000, were capitalized and amortized through March 1, 2026.

In February 2026, the Partnership and its Lender entered into an amendment ("Seventh Amendment") to the BF Loan Agreement, effective March 1, 2026 ("Effective Date"), which renewed and extended the BF Credit Facility for one additional year to March 1, 2027. In addition to the maturity date extension, other key terms of the Seventh Amendment included (i) the Partnership voluntarily electing to reduce its borrowing base to $10 million (as of the Effective Date); (ii) the incremental borrowing fee decreased from 50 basis points to 25 basis points; and (iii) the Partnership paying a renewal fee to the Lender of $25,000.

The interest rate is equal to the Wall Street Journal Prime Rate plus 0.50%, with a floor of 4.00%.

Any 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 certain of the Partnership’s producing wells.

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 redeterminations. 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 BF 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 June 30, 2026. The hedge transactions discussed in Note 7. Risk Management were made at the discretion of the Partnership.

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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 1.0
	●	A minimum ratio of current assets to current liabilities of 1.00 to 1.00

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. In addition, the Sixth Amendment to the BF Loan Agreement allows the Partnership to include any unused amount of BF Credit Facility in its calculation of current assets, which began with the quarter ended September 30, 2024.

The Partnership was in compliance with its applicable covenants and had no outstanding borrowings on the BF Credit Facility at June 30, 2026 and December 31, 2025.

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:

	*2026*			*2025*
Balance at January 1	$	2,234,607		$	2,195,629
Well additions		-			-
Accretion		105,386			108,275
Revisions		(50,974	)		(129,212	)
Balance at June 30	$	2,289,019		$	2,174,692

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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 six months ended June 30, 2026, there were no transfers in or out of Level 1, Level 2, or Level 3 assets and liabilities measured on a recurring basis.

As required, financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following table sets forth by level within the fair value hierarchy the Partnership’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2026.

	*Fair Value Measurements at June 30, 2026*
	*Quoted Prices in Active Markets for Identical Assets (Level 1)*		*Significant Other Observable Inputs (Level 2)*		*Significant Unobservable Inputs (Level 3)*
Commodity derivatives - current assets	$	-	$	1,081,062	$	-
Total	$	-	$	1,081,062	$	-

The Level 2 instruments presented in the table above consist of the Partnership’s costless collar commodity derivative instruments. The fair value of the Partnership’s derivative financial instruments is determined based upon future prices, volatility and time to maturity, among other things. Counterparty statements are utilized to determine the value of the commodity derivative instruments and are reviewed and corroborated using various methodologies and significant observable inputs. The fair value of the commodity derivatives noted above are included in the Partnership’s consolidated balance sheet at June 30, 2026. 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 expenses, reflect these items’ cost, which approximates fair value based on the timing of the anticipated cash flows, current market conditions and short-term maturity of these instruments.

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Note 7. Risk Management

Participation in the oil and natural 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. 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 March 2026, the Partnership entered into costless collar derivative contracts to mitigate the commodity price risk for a portion of the Partnership's expected oil production for the period from April 2026 to December 2026. The Partnership generally uses costless collar derivative contracts, which establish floor and ceiling prices on future anticipated production. The Partnership did not pay or receive a premium related to the costless collars into which it entered, and the contracts will be settled monthly.

As of June 30, 2026, the Partnership’s derivative instruments were in an asset position. The Partnership recognized total assets of approximately $1.1 million, which has been recorded as Derivative asset on the Partnership’s consolidated balance sheet as of June 30, 2026.

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 for the periods presented.

	Three Months Ended June 30, 2026			Six Months Ended June 30, 2026
Settlement loss on matured derivatives	$	(12,628	)	$	(12,628	)
Gain on mark-to-market of derivatives		1,081,062			1,081,062
Gain on derivatives, net	$	1,068,434		$	1,068,434

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

Settlement Period		*Basis*		*Product*		*Volume*			*Floor / Ceiling Prices ($)*
07/2026 - 12/2026		NYMEX		Oil (bbls)		132,000			75.00 / 98.00

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

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Note 8. Capital Contribution and Partners' Equity

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

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

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

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

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

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

●

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

●

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

All items of income, gain, loss and deduction will be allocated to each Partner’s capital account in a manner generally consistent with the distribution procedures outlined above.

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For the three and six months ended June 30, 2026, the Partnership paid distributions of $0.35 per common unit and $0.70 per common unit, or $6.6 million and $13.3 million, respectively. In June 2026, the Partnership declared its regularly scheduled cash distribution to its holders of common units of $0.12 per common unit for the month of June 2026. In addition, the General Partner approved a special distribution of $0.12 per common unit to holders that reduces the accumulated unpaid distribution total. In total, these declared distributions of $0.24 per common unit, or approximately $4.6 million, have been included in Accounts payable and accrued expenses on the Partnership’s consolidated balance sheet as of June 30, 2026. The distributions were paid on July 6, 2026 to the common unit holders on record as of June 30, 2026.

For the three and six months ended June 30, 2025, the Partnership paid distributions of $0.35 per common unit and $0.70 per common unit, or $6.6 million and $13.3 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. After the July 6, 2026 payment of the declared June distributions, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.083789 per common unit, or approximately $39.5 million.

Note 9. 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 any existing related party transactions, as well as any new significant related party transactions.

For the three and six months ended June 30, 2026, approximately $83,000 and $170,000 of general and administrative costs were incurred by a member of the General Partner and have been or will be reimbursed by the Partnership. At June 30, 2026, approximately $83,000 was due to a member of the General Partner; these costs are included in Accounts payable and accrued expenses in the consolidated balance sheets. For the three and six months ended June 30, 2025, approximately $78,000 and $167,000 of general and administrative costs were incurred by a member of the General Partner and have been reimbursed by the Partnership.

Note 10. Subsequent Events

In July 2026, the Partnership paid approximately $4.6 million, or $0.24 per outstanding common unit, in distributions to its holders of common units.

In July 2026, the Partnership declared a monthly cash distribution to its holders of common units of $0.11 per outstanding common unit for the month of July 2026. The distribution of approximately $2.1 million was paid on August 5, 2026 to common unit holders on record as of July 31, 2026.

In August 2026, the Partnership declared a monthly cash distribution to holders of Partnership common units of $0.12 per outstanding common unit for the month of August 2026. This August distribution is scheduled to be paid on September 3, 2026 to common unit holders on record as of August 31, 2026. Further, the Partnership is scheduled to declare a monthly cash distribution to holders of Partnership common units of $0.12 per outstanding common unit for the month of September 2026.

In addition to the scheduled September 2026 distribution, the General Partner has approved a special distribution of $0.12 per common unit to holders of Partnership common units that will reduce the accumulated unpaid distribution total. This special distribution, along with the scheduled September 2026 distribution, is scheduled to be paid on October 5, 2026 to common unit holders on record as of September 30, 2026. Together, the total distributions to be paid on October 5, 2026 amount to $0.24 per common unit.

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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:

	●	any impact of the ongoing Iranian-Israeli-American and Russian-Ukrainian conflicts and/or other Middle Eastern conflicts 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, 2025 (the "2025 Form 10-K") 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 local, state, and federal laws, regulations or policies that may affect the Partnership or the oil and natural gas industry as a whole (such as the effects of tax law changes, and changes in environmental, health, and safety regulation and regulations addressing climate change, and trade policy and tariffs);
	●	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.

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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 (this "Form 10-Q"), as well as the information contained in the 2025 Form 10-K.

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.

The Partnership has drilled and completed 101 new wells since the beginning of 2018; the Partnership’s estimated share of capital expenditures for the drilling and completion of these 101 wells totaled approximately $148.0 million. The Partnership has incurred approximately $1.4 million in capital expenditures through the six months ended June 30, 2026.

As a result of its acquisitions and completed drilling during the period of ownership, as of June 30, 2026, the Partnership owned an approximate 24% non-operated working interest in 308 producing wells and future development sites in the Sanish field located in Mountrail County, North Dakota (collectively, the “Sanish Field Assets”). Chord Energy Corporation (“Chord”), one of the largest producers in the basin, 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 Russia and the Middle East; forecasted levels of global economic growth combined with forecasted global supply; supply levels of oil and natural gas due to exploration and development activities in the United States; environmental and climate change regulation; actions taken by the Organization of the Petroleum Exporting Countries (“OPEC”) and certain non-member oil-producing countries, including Russia ("OPEC+"); and the strength of the U.S. dollar in international currency markets.

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The Partnership’s oil and natural gas revenues are heavily weighted to oil, so any material change to market pricing for oil has a more significant impact to the Partnership’s operational performance. While full-year 2025 oil prices averaged in the mid $60s per barrel, oil prices declined throughout 2025, with the average spot price decreasing from approximately $79 per barrel in January 2025 to approximately $59 per barrel in December 2025. Oil prices increased modestly through February 2026, then in late February and early March 2026, military conflict involving the United States, Israel and Iran escalated in the Middle East, increasing geopolitical uncertainty in global energy markets and contributing to rapid increases in market oil prices. Average market spot prices increased to approximately $91 per barrel in March 2026 and continued to increase in April and May, averaging at or above $100 per barrel each month. Oil prices subsequently declined in June 2026 as expectations of a resolution between the United States and Iran contributed to increased shipping traffic through the Strait of Hormuz, which temporarily restored previously disrupted oil production and trade flows. Despite the subsequent decline in prices, continued geopolitical uncertainty and the potential for disruptions to oil production and transportation routes may contribute to continued volatility in oil prices.

Natural gas prices also experienced a seasonal increase during the first quarter of 2026. Specifically, bitter cold temperatures persisted throughout the United States in January 2026, contributing to monthly average market prices exceeding $7.50 per MMBtu. Natural gas prices have since declined significantly as weather conditions improved and production and storage levels recovered.

Significant reductions in commodity prices along with inflationary costs could impact the Partnership and its financial performance. Future growth is dependent on the Partnership’s ability to add reserves in excess of production. In addition to commodity price fluctuations, the Partnership faces the challenge of natural production volume declines. As reservoirs are depleted, oil and natural gas production from Partnership wells will decrease.

The following table lists average NYMEX prices for oil and natural gas for the three and six months ended June 30, 2026 and 2025.

	Three Months Ended June 30,				Percent			Six Months Ended June 30,				Percent
	2026		2025		Change			2026		2025		Change
Average market closing prices⁽¹⁾
Oil (per Bbl)	$	95.65	$	64.57		48.1	%	$	84.29	$	68.12		23.7	%
Natural gas (per Mcf)	$	2.95	$	3.19		-7.5	%	$	3.81	$	3.66		4.1	%

⁽¹⁾	Based on average NYMEX WTI and Henry Hub daily spot prices reported by the EIA.

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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 NGLs, (3) production costs per BOE and (4) capital expenditures.

The following table summarizes the results from operations, including production, of the Partnership’s non-operated working interest for the three and six months ended June 30, 2026 and 2025.

	Three Months Ended June 30,													Six Months Ended June 30,
	2026		Percent of Revenue			2025		Percent of Revenue			Percent Change			2026		Percent of Revenue			2025		Percent of Revenue			Percent Change
Total revenues	$	16,428,329		100.0	%	$	16,543,412		100.0	%		-0.7	%	$	31,181,529		100.0	%	$	37,403,343		100.0	%		-16.6	%
Production expenses		4,769,910		29.0	%		6,069,324		36.7	%		-21.4	%		9,358,053		30.0	%		12,014,097		32.1	%		-22.1	%
Production taxes		1,125,531		6.9	%		1,087,999		6.6	%		3.4	%		2,071,406		6.6	%		2,578,549		6.9	%		-19.7	%
Depreciation, depletion, amortization and accretion		5,332,120		32.5	%		7,194,457		43.5	%		-25.9	%		11,039,068		35.4	%		14,447,032		38.6	%		-23.6	%
General and administrative expenses		200,734		1.2	%		305,068		1.8	%		-34.2	%		587,144		1.9	%		827,751		2.2	%		-29.1	%

Production (BOE):
Oil		142,444					221,829					-35.8	%		304,727					464,359					-34.4	%
Natural gas		61,820					76,402					-19.1	%		125,575					146,670					-14.4	%
Natural gas liquids		57,189					70,995					-19.4	%		106,819					132,761					-19.5	%
Total		261,453					369,226					-29.2	%		537,121					743,790					-27.8	%

Average sales price per unit:
Oil (per Bbl)	$	95.83				$	61.90					54.8	%	$	82.51				$	65.93					25.1	%
Natural gas (per Mcf)		1.40					2.16					-35.2	%		3.21					3.05					5.2	%
Natural gas liquids (per Bbl)		39.48					25.66					53.9	%		33.88					30.93					9.5	%
Combined (per BOE)		62.83					44.81					40.2	%		58.05					50.29					15.4	%

Average unit cost per BOE:
Production expenses		18.24					16.44					10.9	%		17.42					16.15					7.9	%
Production taxes		4.30					2.95					45.8	%		3.86					3.47					11.2	%
Depreciation, depletion, amortization and accretion		20.39					19.49					4.6	%		20.55					19.42					5.8	%

Capital expenditures	$	1,013,375				$	1,476,114							$	1,354,296				$	2,032,047

Oil, natural gas and NGL revenues

For the three months ended June 30, 2026, revenues from oil, natural gas and NGL sales were $16.4 million. Revenues for the sale of crude oil were $13.7 million, which resulted in a realized price of $95.83 per Bbl. Revenues for the sale of natural gas were $0.5 million, which resulted in a realized price of $1.40 per Mcf. Revenues for the sale of NGLs were $2.3 million, which resulted in a realized price of $39.48 per Bbl. For the three months ended June 30, 2025, revenues from oil, natural gas and NGL sales were $16.5 million. Revenues for the sale of crude oil were $13.7 million, which resulted in a realized price of $61.90 per Bbl. Revenues for the sale of natural gas were $1.0 million, which resulted in a realized price of $2.16 per Mcf. Revenues for the sale of NGLs were $1.8 million, which resulted in a realized price of $25.66 per Bbl.

For the six months ended June 30, 2026, revenues from oil, natural gas and NGL sales were $31.2 million. Revenues for the sale of crude oil were $25.1 million, which resulted in a realized price of $82.51 per Bbl. Revenues for the sale of natural gas were $2.4 million, which resulted in a realized price of $3.21 per Mcf. Revenues for the sale of NGLs were $3.6 million, which resulted in a realized price of $33.88 per Bbl. For the six months ended June 30, 2025, revenues from oil, natural gas and NGL sales were $37.4 million. Revenues for the sale of crude oil were $30.6 million, which resulted in a realized price of $65.93 per Bbl. Revenues for the sale of natural gas were $2.7 million, which resulted in a realized price of $3.05 per Mcf. Revenues for the sale of NGLs were $4.1 million, which resulted in a realized price of $30.93 per Bbl.

The Partnership’s sold production volumes of approximately 2,900 BOE per day and 3,000 BOE per day for the three and six months ended June 30, 2026 indicate a substantial decrease compared to the three and six months ended June 30, 2025, primarily due to the natural production decline of aging wells. The Partnership's primary operator completed 15 new wells during the summer of 2024, which contributed to higher daily production during 2025, with daily production for the three and six months ended June 30, 2025 of 4,100 BOE per day in both periods. New wells often have high levels of production immediately following completion, then decline to more consistent levels.

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As noted above, the escalation of the conflict among the United States, Israel and Iran directly contributed to a rapid increase in market prices for oil from March 2026 through May 2026. The higher oil market prices correspondingly led to increased realized sales prices for the Partnership's sold production, which helped to offset the natural decline in well production during the three and six months ended June 30, 2026. Seasonality and heightened winter demand led to higher natural gas prices during the first quarter of 2026, but the Partnership experienced a decline in natural gas revenue during the three months ended June 30, 2026 as market prices for natural gas fell. Further, the Partnership's differential between market prices and realized sales prices increased, which led to lower natural gas revenue during the second quarter of 2026 when compared to the same period of 2025.

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. On average, the Partnership’s realized oil differential has improved since the first quarter of 2025, as the differential for the three and six months ended June 30, 2026 was approximately $2.50 per barrel and $0.50 per barrel lower compared to the same periods of 2025, respectively. Lower oil differentials increase the Partnership’s realized oil sales prices.

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 June 30, 2026 and 2025, production expenses were $4.8 million and $6.1 million, respectively, and production expenses per BOE of sold production were $18.24 and $16.44, respectively. For the six months ended June 30, 2026 and 2025, production expenses were $9.4 million and $12.0 million, respectively, and production expenses per BOE of sold production were $17.42 and $16.15, respectively. Production expenses per BOE of sold production have increased in 2026 primarily as a result of lower sold production volumes, which decreases the production base over which fixed operating costs are spread.

Production taxes

Taxes on the production and extraction of oil and natural gas are regulated and set by North Dakota tax authorities. Taxes on the sale of natural gas and NGL products are less than taxes levied on the sale of oil. Therefore, production taxes as a percentage of revenue may fluctuate dependent upon the ratio of sales of natural gas and NGLs to total sales. Production taxes for the three months ended June 30, 2026 and 2025 were $1.1 million (6.9% of revenue) and $1.1 million (6.6% of revenue), respectively. Production taxes for the six months ended June 30, 2026 and 2025 were $2.1 million (6.6% of revenue) and $2.6 million (6.9% of revenue), respectively. Oil production comprised approximately 54% and 57% of the Partnership’s sold production volumes for the three and six months ended June 30, 2026, compared to 60% and 62% for the three and six months ended June 30, 2025.

General and administrative expenses

The principal components of general and administrative expense are accounting, legal and consulting fees. General and administrative expenses for the three months ended June 30, 2026 and 2025 were $0.2 million and $0.3 million, respectively. General and administrative expenses for the six months ended June 30, 2026 and 2025 were $0.6 million and $0.8 million, respectively. Reduced legal and professional fees have resulted in lower general and administrative expenses in 2026.

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

DD&A of capitalized drilling and development costs of producing oil, natural gas and NGL properties are computed using the unit-of-production method on a field basis based on total estimated proved developed oil, natural gas and NGL reserves. Costs of acquiring proved properties are depleted using the unit-of-production method on a field basis based on total estimated proved developed and undeveloped reserves. DD&A for the three months ended June 30, 2026 and 2025 was $5.3 million and $7.2 million, and DD&A per BOE of sold production was $20.39 and $19.49, respectively. DD&A for the six months ended June 30, 2026 and 2025 was $11.0 million and $14.4 million, and DD&A per BOE of sold production was $20.55 and $19.42, respectively. The increase in DD&A expense per BOE of production in 2026 is primarily due to the decrease of the Partnership’s estimated proved undeveloped reserves during the most recent reserves analyses (as of December 31, 2025 and June 30, 2026) resulting from well production performance and future forecasts.

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Gain on derivatives, net

Participation in the oil and natural 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. 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 March 2026, the Partnership entered into costless collar derivative contracts to mitigate the commodity price risk for a portion of the Partnership's expected oil production for the period from April 2026 to December 2026. The Partnership generally uses costless collar derivative contracts, which establish floor and ceiling prices on future anticipated production.

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 for the periods presented.

	Three Months Ended June 30, 2026			Six Months Ended June 30, 2026
Settlement loss on matured derivatives	$	(12,628	)	$	(12,628	)
Gain on mark-to-market of derivatives		1,081,062			1,081,062
Gain on derivatives, net	$	1,068,434		$	1,068,434

The Partnership’s oil production contracts that expired during the three and six months ended June 30, 2026 represented approximately 66,000 barrels of oil. The Partnership realized a loss of approximately $13,000 on the settlement of those contracts, equating to an approximate loss of $0.19 per barrel, on its hedged oil production, and an approximate loss of $0.09 per barrel of total sold oil production for the second quarter of 2026.

The mark-to-market (non-cash, unrealized) gain recorded for the three and six months ended June 30, 2026 represents the change in fair value of the Partnership’s derivative instruments held at period-end. Unrealized gains and losses do not represent actual settlements or payments made to or from the counterparty.

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

Settlement Period		Basis		Product		Volume			Floor / Ceiling Prices ($)
07/2026 - 12/2026		NYMEX		Oil (bbls)		132,000			75.00 / 98.00

Interest expense, net

Interest expense, net, for the three months ended June 30, 2026 and 2025 was $6,000 and $28,000, respectively. Interest expense, net, for the six months ended June 30, 2026 and 2025 was $55,000 and $95,000, respectively. The Partnership had no outstanding balance on the BF Credit Facility during the first half of 2026, so the expense recorded primarily represents expensed loan costs and non-use fees under the BF Loan Agreement.

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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 an alternative to, net income, operating income, cash flow from operating activities or other measures of financial performance presented in accordance with GAAP. Adjusted EBITDAX is not necessarily indicative of funds available to fund the Partnership’s cash needs, including its ability to make cash distributions. Although Adjusted EBITDAX, as calculated by the Partnership, may not be comparable to Adjusted EBITDAX as reported by other companies that do not define such terms exactly as the Partnership defines such terms, the Partnership believes this supplemental measure is useful to investors when comparing the Partnership’s results between periods and with other energy companies.

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

The following table reconciles the Partnership’s GAAP net income to Adjusted EBITDAX for the three and six months ended June 30, 2026 and 2025.

	Three Months Ended June 30, 2026			Three Months Ended June 30, 2025		Six Months Ended June 30, 2026			Six Months Ended June 30, 2025
Net income	$	6,062,148		$	1,858,829	$	9,139,577		$	7,440,756
Interest expense, net		6,320			27,735		54,715			95,158
Depreciation, depletion, amortization and accretion		5,332,120			7,194,457		11,039,068			14,447,032
Exploration expenses		-			-		-			-
Non-cash gain on mark-to-market of derivatives		(1,081,062	)		-		(1,081,062	)		-
Adjusted EBITDAX	$	10,319,526		$	9,081,021	$	19,152,298		$	21,982,946

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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 $8.8 million in cash on hand and $10 million in availability under the BF Credit Facility at June 30, 2026. The Partnership generated approximately $16.5 million and $43.7 million in net cash flow from operating activities for the six months ended June 30, 2026 and year ended December 31, 2025, respectively.

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. Based on the terms and conditions of the February 2024 fifth amendment to the BF Loan Agreement, 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, capital expenditures for new wells and payments on the BF Credit Facility, as necessary based on usage.

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

Financing

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

Partners’ Equity

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

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

Distributions

For the three and six months ended June 30, 2026, the Partnership paid distributions of $0.35 per common unit and $0.70 per common unit, or $6.6 million and $13.3 million, respectively. In June, the Partnership declared its regularly scheduled cash distribution to its holders of common units of $0.12 per common unit for the month of June 2026. Also in June, the General Partner approved a special distribution of $0.12 per common unit to holders that reduces the accumulated unpaid distribution total. In total, these declared distributions of $0.24 per common unit, or approximately $4.6 million, were included in Accounts payable and accrued expenses on the Partnership’s balance sheet as of June 30, 2026 and were paid on July 6, 2026 to the common unit holders on record as of June 30, 2026.

For the three and six months ended June 30, 2025, the Partnership paid distributions of $0.35 per common unit and $0.70 per common unit, or $6.6 million and $13.3 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. After the July 6, 2026 payment of the declared June distributions, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.083789 per common unit, or approximately $39.5 million.

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Oil and Natural Gas Properties

The Partnership incurred approximately $1.4 million and $2.0 million in capital expenditures for the six months ended June 30, 2026 and 2025, respectively.

The Partnership anticipates that it may be obligated to invest at least an additional $100 million from 2026 through 2030 to participate in new well development in the Sanish Field without becoming subject to non-consent penalties under the joint operating agreements governing the Sanish Field Assets.

As described above, the Partnership’s liquidity is currently dependent upon cash on-hand, cash from operations and availability under the 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.

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

Critical Accounting Estimates

There have been no material changes to the Partnership's critical accounting estimates from those disclosed in Item 7, “Management's Discussion and Analysis of Financial Condition and Results of Operations,” of the Partnership's Annual Report on Form 10-K for the year ended December 31, 2025.

Subsequent Events

In July 2026, the Partnership paid approximately $4.6 million, or $0.24 per outstanding common unit, in distributions to its holders of common units.

In July 2026, the Partnership declared a monthly cash distribution to its holders of common units of $0.11 per outstanding common unit for the month of July 2026. The distribution of approximately $2.1 million was paid on August 5, 2026 to common unit holders on record as of July 31, 2026.

In August 2026, the Partnership declared a monthly cash distribution to holders of Partnership common units of $0.12 per outstanding common unit for the month of August 2026. This August distribution is scheduled to be paid on September 3, 2026 to common unit holders on record as of August 31, 2026. Further, the Partnership is scheduled to declare a monthly cash distribution to holders of Partnership common units of $0.12 per outstanding common unit for the month of September 2026.

In addition to the scheduled September 2026 distribution, the General Partner has approved a special distribution of $0.12 per common unit to holders of Partnership common units that will reduce the accumulated unpaid distribution total. This special distribution, along with the scheduled September 2026 distribution, is scheduled to be paid on October 5, 2026 to common unit holders on record as of September 30, 2026. Together, the total distributions to be paid on October 5, 2026 amount to $0.24 per common unit.

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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 June 30, 2026 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 Control Over Financial Reporting

There have not been any changes in the Partnership’s internal control over financial reporting that occurred during the quarterly period ended June 30, 2026 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 2025 Form 10-K. There have been no material changes to the risk factors previously disclosed in the 2025 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.

During the three months ended June 30, 2026, no director or officer of the General Partner adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.

Item 6. Exhibits.

Exhibit No.		Description
31.1		Certification of Chief Executive Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002*
31.2		Certification of Chief Financial Officer Pursuant to Section 302 of Sarbanes-Oxley Act of 2002*
32.1		Certification of Chief Executive Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002**
32.2		Certification of Chief Financial Officer Pursuant to Section 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002**
101		The following materials from Energy 11, L.P.’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2026 formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) the Consolidated Balance Sheets, (ii) the Consolidated Statements of Operations, (iii) the Consolidated Statements of Partners’ Equity, (iv) the Consolidated Statements of Cash Flows, and (v) related notes to these consolidated financial statements, tagged as blocks of text and in detail*
104		The cover page from the Partnership’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2026, formatted in iXBRL and contained in Exhibit 101

*	Filed herewith.
**	Furnished herewith.

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SIGNATURES

Pursuant to the requirements 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 GP, LLC, its General Partner

By:	/s/ Glade M. Knight
	Glade M. Knight
	Chief Executive Officer
	(Principal Executive Officer)

By:	/s/ David S. McKenney
	David S. McKenney
	Chief Financial Officer
	(Principal Financial and Accounting Officer)

Date: August 12, 2026