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 March 31, 2024

☐ 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 May 15, 2024, 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 – March 31, 2024 and December 31, 2023	3
		Consolidated Statements of Operations – Three months ended March 31, 2024 and 2023	4
		Consolidated Statements of Partners’ Equity – Three months ended March 31, 2024 and 2023	5
		Consolidated Statements of Cash Flows – Three months ended March 31, 2024 and 2023	6
		Notes to Consolidated Financial Statements	7
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	21
	Item 4.	Controls and Procedures	21
PART II. OTHER INFORMATION
	Item 1.	Legal Proceedings	22
	Item 1A.	Risk Factors	22
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	22
	Item 3.	Defaults upon Senior Securities	22
	Item 4.	Mine Safety Disclosures	22
	Item 5.	Other Information	22
	Item 6.	Exhibits	22
Signatures			23

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Energy 11, L.P.

Consolidated Balance Sheets

	March 31,			December 31,
	2024			2023
	(unaudited)
Assets
Cash and cash equivalents	$	3,511,085		$	1,209,813
Accounts receivable		10,108,880			11,451,882
Other current assets, net		109,708			127,298
Total Current Assets		13,729,673			12,788,993
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $152,178,726 and $146,161,010, respectively		337,707,889			338,545,992
Other assets		55,353			-
Total Assets	$	351,492,915		$	351,334,985
Liabilities
Accounts payable and accrued expenses	$	11,640,767		$	9,285,194
Total Current Liabilities		11,640,767			9,285,194
Revolving credit facility		-			-
Asset retirement obligations		2,088,399			2,060,520
Total Liabilities		13,729,166			11,345,714
Partners’ Equity
Limited partners' interest (18,973,474 common units issued and outstanding, respectively)		337,765,476			339,990,998
General partner's interest		(1,727	)		(1,727	)
Class B Units (62,500 units issued and outstanding, respectively)		-			-
Total Partners’ Equity		337,763,749			339,989,271
Total Liabilities and Partners’ Equity	$	351,492,915		$	351,334,985

See notes to consolidated financial statements.

3

Energy 11, L.P.

Consolidated Statements of Operations

(Unaudited)

	Three Months Ended			Three Months Ended
	March 31, 2024			March 31, 2023
Revenues
Oil	$	15,558,497		$	24,976,638
Natural gas		841,405			1,470,349
Natural gas liquids		2,001,759			1,920,000
Total revenue		18,401,661			28,366,987
Operating costs and expenses
Production expenses		5,158,144			6,727,225
Production taxes		1,395,000			2,226,208
General and administrative expenses		481,795			752,984
Depreciation, depletion, amortization and accretion		6,045,594			6,617,645
Total operating costs and expenses		13,080,533			16,324,062
Operating income		5,321,128			12,042,925
Gain on derivatives, net		-			1,412,708
Interest expense, net		(50,492	)		(456,366	)
Total other income (expense), net		(50,492	)		956,342
Net income	$	5,270,636		$	12,999,267
Basic and diluted net income per common unit	$	0.28		$	0.69
Weighted average common units outstanding - basic and diluted		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			Total
	Common Units		Amount			Units		Amount		Partner Amount			Partners' Equity
Balances - December 31, 2022		18,973,474	$	331,177,765			62,500	$	-	$	(1,727	)	$	331,176,038
Distributions declared to common units ($0.322191 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
Balances - December 31, 2023		18,973,474	$	339,990,998			62,500	$	-	$	(1,727	)	$	339,989,271
Distributions declared to common units ($0.40 per unit)		-		(7,589,390	)		-		-		-			(7,589,390	)
Adjustments to state tax withholding for limited partners		-		93,232			-		-		-			93,232
Net income - three months ended March 31, 2024		-		5,270,636			-		-		-			5,270,636
Balances - March 31, 2024		18,973,474	$	337,765,476			62,500	$	-	$	(1,727	)	$	337,763,749

See notes to consolidated financial statements.

5

Energy 11, L.P.

Consolidated Statements of Cash Flows

(Unaudited)

	Three Months Ended			Three Months Ended
	March 31, 2024			March 31, 2023
Cash flow from operating activities:
Net income	$	5,270,636		$	12,999,267
Adjustments to reconcile net income to cash from operating activities:
Depreciation, depletion, amortization and accretion		6,045,594			6,617,645
Gain on mark-to-market of derivatives, net		-			(1,722,658	)
Non-cash expenses, net		-			35,481
Changes in operating assets and liabilities:
Accounts receivable		1,343,002			(1,900,895	)
Other assets		(37,763	)		92,856
Accounts payable and accrued expenses		(119,347	)		74,516
Net cash flow provided by operating activities		12,502,122			16,196,212
Cash flow from investing activities:
Additions to oil and natural gas properties		(2,611,460	)		(7,656,051	)
Net cash flow used in investing activities		(2,611,460	)		(7,656,051	)
Cash flow from financing activities:
Payments on BancFirst revolving credit facility		-			(4,100,000	)
Distributions paid to limited partners		(7,589,390	)		(7,129,340	)
Net cash flow used in financing activities		(7,589,390	)		(11,229,340	)
Increase (decrease) in cash and cash equivalents		2,301,272			(2,689,179	)
Cash and cash equivalents, beginning of period		1,209,813			3,053,120
Cash and cash equivalents, end of period	$	3,511,085		$	363,941
Interest paid	$	-		$	407,285
Supplemental non-cash information:
Accrued capital expenditures related to additions to oil and natural gas properties	$	4,760,204		$	1,877,094

See notes to consolidated financial statements.

6

Energy 11, L.P.

Notes to Consolidated Financial Statements

March 31, 2024

(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 March 31, 2024, the Partnership owned an approximate 24% non-operated working interest in 299 producing wells, an estimated approximate 20% non-operated working interest in 6 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 2023 Annual Report on Form 10-K. Operating results for the three months ended March 31, 2024 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2024.

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 March 31, 2024, 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 March 31, 2024 and December 31, 2023, 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. In accordance with its settlements with the state of North Dakota, the Partnership has 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; and (iii) approximately $869,000 (approximately $0.046 per common unit) in April 2024 for tax year 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.

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.

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 months ended March 31, 2024. 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 6) 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.

8

The Partnership has drilled and completed 86 new wells since the beginning of 2018; the Partnership’s estimated share of capital expenditures for the drilling and completion of these 86 wells totaled approximately $120 million. Since October 2023, the Partnership has elected to participate in 15 more wells, of which at least six (6) were in-process as of March 31, 2024. The Partnership has an approximate 18% non-operated working interest in these 15 wells, which are anticipated to be completed in the first half of 2024 at a total estimated cost to the Partnership of approximately $26 million. The Partnership has incurred approximately $4.2 million in capital expenditures to date related to these in-process wells as of March 31, 2024.

The Partnership estimates the remaining capital expenditures to fully pay for these new wells will be incurred through the third quarter of 2024 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 provided 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. Total capitalized loan costs, which were approximately $400,000, were recorded as Other assets on the Partnership’s balance sheets and were amortized in full through February 2024. The Partnership also paid an annual fee to the Lender of $30,000, and an unused facility fee of 0.25% on the unused portion of the BF Credit Facility, based on borrowings outstanding during a quarter.

On February 27, 2024, the Partnership and its Lender entered into an amendment (“Fifth Amendment”) to the BF Loan Agreement, effective March 1, 2024 (“Effective Date”), that renewed and extended the BF Credit Facility for two additional years to March 1, 2026 (“Revised Maturity Date”). Key terms and conditions of the Fifth Amendment include:

● As of the Effective Date, the borrowing base of the BF Credit Facility is $20,000,000.

● As amended, the Partnership remains subject to a semiannual redetermination of its borrowing base, but the Partnership is only required to perform an annual analysis of its proven oil and natural gas reserves as of January 1 of each year.

● The Partnership paid a loan fee to the Lender associated with the Fifth Amendment of $100,000.

● Previously under the BF Loan Agreement, the Partnership was required to pay a $30,000 annual administrative fee to the Lender. Because BancFirst will be the only Lender effective March 1, 2024, the administrative fee has been waived through the Revised Maturity Date.

Loan costs associated with the Fifth Amendment, which totaled approximately $121,000, were capitalized and will be amortized through the Revised Maturity Date. 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 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 March 31, 2024.

9

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

In addition, 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 Partnership was in compliance with its applicable covenants and had no outstanding borrowings on the BF Credit Facility at March 31, 2024.

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:

	2024		2023
Balance at January 1	$	2,060,520	$	1,966,738
Well additions		-		1,086
Accretion		27,879		26,412
Revisions		-		-
Balance at March 31	$	2,088,399	$	1,994,236

Note 6. 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.

10

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

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

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

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

In January 2024, the General Partner declared a special distribution of $0.05 per common unit that reduced the accumulated unpaid distribution total described below. For the three months ended March 31, 2024, the Partnership paid distributions of $0.40 per common unit, or $7.6 million. 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 March 2024. 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 March 31, 2024, was paid on April 3, 2024 to the common unit holders on record as of March 31, 2024.

For the three months ended March 31, 2023, the Partnership paid distributions of $0.375753 per common unit, or $7.1 million.

The Partnership accumulates unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are required to be paid before final Payout occurs, as defined above. As of the filing date of this Form 10-Q, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.260447 per common unit, or approximately $43 million.

Note 7. 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 natural 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 months ended March 31, 2024 and 2023, approximately $99,000 and $41,000 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 March 31, 2024, approximately $99,000 was due to a member of the General Partner; these costs are included in Accounts payable and accrued expenses in the consolidated balance sheets.

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.

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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. Prior to termination, all Administrator costs and expenses subject to the ASA 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 three months ended March 31, 2023, approximately $132,000 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 8. Subsequent Events

In April 2024, the Partnership paid approximately $2.3 million, or $0.12 per outstanding common unit, in distributions to its holders of common units.

In April 2024, the Partnership declared a monthly cash distribution to its holders of common units of $0.11 per outstanding common unit for the month of April 2024. The distribution of approximately $2.1 million was paid on May 3, 2024 to common unit holders on record as of April 30, 2024.

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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 Russian-Ukrainian and Israeli-Hamas 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, 2023 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, 2023.

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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.

The Partnership has drilled and completed 86 new wells since the beginning of 2018; the Partnership’s estimated share of capital expenditures for the drilling and completion of these 86 wells totaled approximately $120 million. Since October 2023, the Partnership has elected to participate in 15 more wells, of which at least six (6) were in-process as of March 31, 2024. These 15 wells are anticipated to be completed in the first half of 2024 at a total estimated cost to the Partnership of approximately $26 million. See additional detail in “Oil and Natural Gas Properties” below. The Partnership has incurred approximately $4.2 million in capital expenditures to date related to these in-process wells as of March 31, 2024.

As a result of its acquisitions and completed drilling during the period of ownership, as of March 31, 2024, the Partnership owned an approximate 24% non-operated working interest in 299 producing wells, an estimated approximate 20% non-operated working interest in six 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 Russia and the Middle East; forecasted levels of global economic growth combined with forecasted global supply; supply levels of oil and natural gas due to exploration and development activities in the United States; environmental and climate change regulation; actions taken by the Organization of the Petroleum Exporting Countries (“OPEC”); and the strength of the U.S. dollar in international currency markets.

The 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 months ended March 31, 2024 and 2023.

	Three Months Ended March 31,				Percent
	2024		2023		Change
Average market closing prices (1)
Oil (per Bbl)	$	76.91	$	75.99		1.2	%
Natural gas (per Mcf)	$	2.15	$	2.64		-18.6	%

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

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. 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 months ended March 31, 2024 and 2023.

	Three Months Ended March 31,
	2024		Percent of Revenue			2023		Percent of Revenue			Percent Change
Total revenues	$	18,401,661		100.0	%	$	28,366,987		100.0	%		-35.1	%
Production expenses		5,158,144		28.0	%		6,727,225		23.7	%		-23.3	%
Production taxes		1,395,000		7.6	%		2,226,208		7.8	%		-37.3	%
Depreciation, depletion, amortization and accretion		6,045,594		32.9	%		6,617,645		23.3	%		-8.6	%
General and administrative expenses		481,795		2.6	%		752,984		2.7	%		-36.0	%
Production (BOE):
Oil		205,822					326,566					-37.0	%
Natural gas		59,265					62,669					-5.4	%
Natural gas liquids		53,929					58,014					-7.0	%
Total		319,016					447,249					-28.7	%
Average sales price per unit:
Oil (per Bbl)	$	75.59				$	76.48					-1.2	%
Natural gas (per Mcf)		2.37					3.91					-39.4	%
Natural gas liquids (per Bbl)		37.12					33.10					12.1	%
Combined (per BOE)		57.68					63.43					-9.1	%
Average unit cost per BOE:
Production expenses		16.17					15.04					7.5	%
Production taxes		4.37					4.98					-12.1	%
Depreciation, depletion, amortization and accretion		18.95					14.80					28.1	%
Capital expenditures	$	5,179,613				$	990,044

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Oil, natural gas and NGL revenues

For the three months ended March 31, 2024, revenues from oil, natural gas and NGL sales were $18.4 million. Revenues for the sale of crude oil were $15.6 million, which resulted in a realized price of $75.59 per barrel. Revenues for the sale of natural gas were $0.8 million, which resulted in a realized price of $2.37 per Mcf. Revenues for the sale of NGLs were $2.0 million, which resulted in a realized price of $37.12 per BOE of sold production. For the three months ended March 31, 2023, revenues from oil, natural gas and NGL sales were $28.4 million. Revenues for the sale of crude oil were $25.0 million, which resulted in a realized price of $76.48 per barrel. Revenues for the sale of natural gas were $1.5 million, which resulted in a realized price of $3.91 per Mcf. Revenues for the sale of NGLs were $1.9 million, which resulted in a realized price of $33.10 per BOE of sold production.

The Partnership’s results for the three months ended March 31, 2024 were negatively impacted by adverse weather conditions in North Dakota; extremely cold temperatures for a multi-day stretch in mid-January led to suspended production throughout the Bakken. North Dakota’s Department of Mineral Resources reported a basin-wide drop in oil production of approximately 13.5% in January. Sold production for the Sanish Field Assets was approximately 3,500 BOE per day for the three months ended March 31, 2024, compared to 4,900 BOE per day for the three months ended March 31, 2023. The completion of thirteen (13) new wells that were turned to sales during the fourth quarter of 2022 directly contributed to the higher production volumes in the first quarter of 2023.

The Partnership’s results for the three months ended March 31, 2024 were also negatively impacted by lower realized sales prices for oil (see Oil differentials below) and natural gas. Continued high inventories and lower demand stemming from warmer winter weather conditions across the country kept natural gas prices low throughout the first quarter of 2024. However, high natural gas market spot prices in December 2022 carried over to early January 2023 natural gas sales, which fueled the Partnership’s realized natural gas sales prices in excess of the market average during the first quarter of 2023.

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 increased by approximately $1.65 and $1.30 per barrel of oil during the first quarter of 2024 in comparison to the first and fourth quarters of 2023, respectively, which reduced 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.

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 March 31, 2024 and 2023, production expenses were $5.2 million and $6.7 million, respectively, and production expenses per BOE of sold production were $16.17 and $15.04, respectively. The increase in production expenses per BOE is primarily due to the decrease in sold production volumes, which decreases the production base over which fixed operating costs are spread.

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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 March 31, 2024 and 2023 were $1.4 million (8% of revenue) and $2.2 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 March 31, 2024 and 2023 were $0.5 million and $0.8 million, respectively. The Partnership realized a decrease in personnel-related costs and legal expenses during the first quarter of 2024, compared to the same period of 2023.

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 March 31, 2024 and 2023 was $6.0 million and $6.6 million, and DD&A per BOE of sold production was $18.95 and $14.80, respectively. The increase in DD&A expense per BOE of production in the first quarter of 2024 is primarily due to the decrease of the Partnership’s estimated proved undeveloped reserves during the most recent reserves analyses (as of December 31, 2023) resulting from changes in the future drill schedule and well production forecasts.

Gain 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.

The Partnership did not designate its 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 March 31, 2023
Settlement loss on matured derivatives	$	(309,950	)
Gain on mark-to-market of derivatives, net		1,722,658
Gain on derivatives, net	$	1,412,708

The Partnership’s oil production contracts that expired during the three months ended March 31, 2023 represented approximately 75,000 barrels of oil. The Partnership realized a loss of approximately $0.3 million, equating to an approximate loss of $4.13 per barrel, on its hedged oil production. The Partnership’s natural gas production contracts that expired during the three months ended March 31, 2023 represented 90,000 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 mark-to-market (non-cash, unrealized) gain recorded for the three months ended March 31, 2023 represents the change in fair value of the Partnership’s derivative instruments held at period-end. Unrealized gains (or losses) do not represent actual settlements or payments made to or from the counterparty.

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Interest expense, net

Interest expense, net, for the three months ended March 31, 2024 and 2023 was $50,000 and $0.5 million, respectively. The primary component of Interest expense, net, during the first quarter of 2023 was interest expense on the BF Credit Facility. The Partnership had no outstanding balance on its BF Credit Facility during the first quarter of 2024, so the expense recorded during the three months ended March 31, 2024 represented the amortization of capitalized loan costs and non-use fees under the BF Loan Agreement.

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 months ended March 31, 2024 and 2023.

	Three Months Ended March 31, 2024		Three Months Ended March 31, 2023
Net income	$	5,270,636	$	12,999,267
Interest expense, net		50,492		456,366
Depreciation, depletion, amortization and accretion		6,045,594		6,617,645
Exploration expenses		-		-
Non-cash gain on mark-to-market of derivatives, net		-		(1,722,658	)
Adjusted EBITDAX	$	11,366,722	$	18,350,620

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 $2.1 million in cash on hand at the time of filing of this Form 10-Q, and the Partnership generated approximately $12.5 million and $66.3 million in cash flow from operating activities for the quarter ended March 31, 2024 and year ended December 31, 2023, respectively. In February 2024, the Partnership successfully renewed its BF Credit Facility and currently has $20 million in availability under the BF Credit Facility.

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 (see “Oil and Natural Gas Properties”). 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.

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

Financing

See further discussion of the Partnership’s 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 6. Capital Contribution and Partners’ Equity” in Part I, Item 1 of this Form 10-Q.

Distributions

In January 2024, the General Partner declared a special distribution of $0.05 per common unit that reduced the accumulated unpaid distribution total described below. For the three months ended March 31, 2024, the Partnership paid distributions of $0.40 per common unit, or $7.6 million. 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 March 2024. 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 March 31, 2024, was paid on April 3, 2024 to the common unit holders on record as of March 31, 2024.

For the three months ended March 31, 2023, the Partnership paid distributions of $0.375753 per common unit, or $7.1 million.

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 the filing date of this Form 10-Q, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.260447 per common unit, or approximately $43 million.

Oil and Natural Gas Properties

The Partnership incurred approximately $5.2 million and $1.0 million in capital expenditures for the three months ended March 31, 2024 and 2023, respectively.

Since October 2023, the Partnership has elected to participate in the drilling and completion of 15 new wells, of which at least six (6) were in-process as of March 31, 2024. The Partnership has an approximate 18% non-operated working interest in these 15 wells, which are anticipated to be completed in the first half of 2024. The Partnership has incurred approximately $4.2 million in capital expenditures to date related to these in-process wells as of March 31, 2024. The Partnership estimates the approximate $20 million to $22 million in capital expenditures to fully pay to complete these 15 wells will be incurred through the first three quarters of 2024 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 when wells will be completed as well as the amount and timing of capital expenditures for 2024. Estimated capital expenditures could be significantly different from amounts actually invested.

In addition to the wells in which the Partnership has already elected to participate, the Partnership anticipates that it may be obligated to invest an additional $60 to $70 million 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 7. Related Parties” in Part I, Item 1 of this Form 10-Q.

Subsequent Events

In April 2024, the Partnership paid approximately $2.3 million, or $0.12 per outstanding common unit, in distributions to its holders of common units.

In April 2024, the Partnership declared a monthly cash distribution to its holders of common units of $0.11 per outstanding common unit for the month of April 2024. The distribution of approximately $2.1 million was paid on May 3, 2024 to common unit holders on record as of April 30, 2024.

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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.

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 March 31, 2024 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 March 31, 2024 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 2023 Annual Report on Form 10-K. There have been no material changes to the risk factors previously disclosed in the 2023 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
10.1	Fifth Amendment to Credit Agreement dated effective as of March 1, 2024 by and among Energy 11 Operating Company, LLC and Energy 11, L.P., as Borrowers, BancFirst, as Administrative Agent for the Lender hereto (incorporated by reference from Exhibit 10.1 to the Partnership’s Current Report on Form 8-K filed on February 28, 2024)
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 March 31, 2024 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 March 31, 2024, 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: May 15, 2024

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