UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
For
the quarterly period ended
FOR THE TRANSITION PERIOD FROM TO
Commission
File Number
(Exact name of registrant as specified in its charter)
(State or other jurisdiction | (IRS Employer | |
| ||
(Address of principal executive offices) | (Zip Code) |
(
(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 | ||
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.
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).
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 ☐ | |
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, 2025, the Partnership had
Energy 11, L.P.
Form 10-Q
Index
Page Number | ||
PART I. FINANCIAL INFORMATION | ||
Item 1. | Financial Statements (Unaudited) | 3 |
Consolidated Balance Sheets – March 31, 2025 and December 31, 2024 | 3 | |
Consolidated Statements of Operations – Three months ended March 31, 2025 and 2024 | 4 | |
Consolidated Statements of Partners’ Equity – Three months ended March 31, 2025 and 2024 | 5 | |
Consolidated Statements of Cash Flows – Three months ended March 31, 2025 and 2024 | 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 | 19 |
Item 4. | Controls and Procedures | 19 |
PART II. OTHER INFORMATION | ||
Item 1. | Legal Proceedings | 20 |
Item 1A. | Risk Factors | 20 |
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 20 |
Item 3. | Defaults upon Senior Securities | 20 |
Item 4. | Mine Safety Disclosures | 20 |
Item 5. | Other Information | 20 |
Item 6. | Exhibits | 20 |
Signatures | 21 |
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Energy 11, L.P.
Consolidated Balance Sheets
March 31, | December 31, | |||||||
2025 | 2024 | |||||||
(unaudited) | ||||||||
Assets | ||||||||
Cash and cash equivalents | $ | $ | ||||||
Accounts receivable | ||||||||
Other current assets, net | ||||||||
Total Current Assets | ||||||||
Oil and natural gas properties, successful efforts method, net of accumulated depreciation, depletion and amortization of $ | ||||||||
Other assets | ||||||||
Total Assets | $ | $ | ||||||
Liabilities | ||||||||
Accounts payable and accrued expenses | $ | $ | ||||||
Total Current Liabilities | ||||||||
Revolving credit facility | ||||||||
Asset retirement obligations | ||||||||
Total Liabilities | ||||||||
Partners’ Equity | ||||||||
Limited partners’ interest ( | ||||||||
General partner’s interest | ( | ) | ( | ) | ||||
Class B Units ( | ||||||||
Total Partners’ Equity | ||||||||
Total Liabilities and Partners’ Equity | $ | $ |
See notes to consolidated financial statements.
3
Energy 11, L.P.
Consolidated Statements of Operations
(Unaudited)
Three Months Ended | Three Months Ended | |||||||
March 31, 2025 | March 31, 2024 | |||||||
Revenues | ||||||||
Oil | $ | $ | ||||||
Natural gas | ||||||||
Natural gas liquids | ||||||||
Total revenue | ||||||||
Operating costs and expenses | ||||||||
Production expenses | ||||||||
Production taxes | ||||||||
General and administrative expenses | ||||||||
Depreciation, depletion, amortization and accretion | ||||||||
Total operating costs and expenses | ||||||||
Operating income | ||||||||
Interest expense, net | ( | ) | ( | ) | ||||
Total interest expense, net | ( | ) | ( | ) | ||||
Net income | $ | $ | ||||||
Basic and diluted net income per common unit | $ | $ | ||||||
Weighted average common units outstanding - basic and diluted |
See notes to consolidated financial statements.
4
Energy 11, L.P.
Consolidated Statements of Partners’ Equity
(Unaudited)
Limited Partner | Class B | General Partner | Total Partners’ | |||||||||||||||||||||
Common Units | Amount | Units | Amount | Amount | Equity | |||||||||||||||||||
Balances - December 31, 2023 | $ | $ | - | $ | ( | ) | $ | |||||||||||||||||
Distributions declared to common units ($ | - | ( | ) | - | - | - | ( | ) | ||||||||||||||||
State tax withholding payments made on behalf of limited partners | - | ( | ) | - | - | - | ( | ) | ||||||||||||||||
Reversal of estimated state tax withholding for limited partners | - | - | - | - | ||||||||||||||||||||
Net income - three months ended March 31, 2024 | - | - | - | - | ||||||||||||||||||||
Balances - March 31, 2024 | $ | $ | - | $ | ( | ) | $ | |||||||||||||||||
Balances - December 31, 2024 | $ | $ | - | $ | ( | ) | $ | |||||||||||||||||
Distributions declared to common units ($ | - | ( | ) | - | - | - | ( | ) | ||||||||||||||||
Net income - three months ended March 31, 2025 | - | - | - | - | ||||||||||||||||||||
Balances - March 31, 2025 | $ | $ | - | $ | ( | ) | $ |
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, 2025 | March 31, 2024 | |||||||
Cash flow from operating activities: | ||||||||
Net income | $ | $ | ||||||
Adjustments to reconcile net income to cash from operating activities: | ||||||||
Depreciation, depletion, amortization and accretion | ||||||||
Changes in operating assets and liabilities: | ||||||||
Accounts receivable | ||||||||
Other assets | ( | ) | ||||||
Accounts payable and accrued expenses | ( | ) | ||||||
Net cash flow provided by operating activities | ||||||||
Cash flow from investing activities: | ||||||||
Additions to oil and natural gas properties | ( | ) | ( | ) | ||||
Net cash flow used in investing activities | ( | ) | ( | ) | ||||
Cash flow from financing activities: | ||||||||
Payments on BancFirst revolving credit facility | ( | ) | ||||||
Distributions paid to limited partners | ( | ) | ( | ) | ||||
Net cash flow used in financing activities | ( | ) | ( | ) | ||||
Increase in cash and cash equivalents | ||||||||
Cash and cash equivalents, beginning of period | ||||||||
Cash and cash equivalents, end of period | $ | $ | ||||||
Interest paid | $ | $ | ||||||
Supplemental non-cash information: | ||||||||
Accrued capital expenditures related to additions to oil and natural gas properties | $ | $ |
See notes to consolidated financial statements.
6
Energy 11, L.P.
Notes to Consolidated Financial Statements
March 31, 2025
(Unaudited)
Note 1. Partnership Organization
Energy
11, L.P. (the “Partnership”) is a
As
of March 31, 2025, the Partnership owned an approximate
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 2024 Annual Report on Form 10-K. Operating results for the three months ended March 31, 2025 are not necessarily indicative of the results that may be expected for the twelve-month period ending December 31, 2025.
Segment Information
The
Partnership has identified only
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.
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.
Reclassifications
Certain prior period amounts in the consolidated financial statements have been reclassified to conform to the current period presentation with no effect on previously reported net income, partners’ equity or cash flows.
7
Revenue Recognition
The Partnership is bound by a joint operating agreement with the operator of each of its producing wells. Under the joint operating agreement, the Partnership’s proportionate share of production is marketed at the discretion of the operators. The Partnership typically satisfies its performance obligations upon transfer of control of its products and records the related revenue in the month production is delivered to the purchaser. As the Partnership does not operate its properties, it receives actual oil, natural gas, and NGL sales volumes and prices, net of costs incurred by the operators, two to three months after the date production is delivered by the operator. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from the Partnership’s operators are accrued in Accounts receivable in the consolidated balance sheets. Variances between the Partnership’s estimated revenue and actual payments are recorded in the month the payment is received; differences have been and are insignificant. As a result, the variable consideration is not constrained. The Partnership has elected to utilize the practical expedient in ASC 606 that states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Each delivery of product represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.
Virtually all of the Partnership’s contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.
Accounts Receivable and Concentration of Credit Risk
For
the quarter ended March 31, 2025, 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, 2025 and December 31, 2024, the Partnership did not reserve
for bad debt expense, as all amounts are deemed collectible. Chord is the current operator of
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
$
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
8
Recently Adopted Accounting Standards
In November 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which requires significant segment disclosures on an annual and interim basis. Additionally, it requires disclosure of the title and position of the Chief Operating Decision Maker (“CODM”) and requires a public entity that has a single reportable segment to provide all disclosures required by the amendments in this ASU and all existing segment disclosures in Topic 280. The new standard is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. The adoption of this ASU only impacted disclosures with no impact on the Partnership’s consolidated financial statements. The Partnership adopted this ASU effective December 31, 2024 as noted in its 2024 Form 10-K; see Segment Information above.
Recently Issued Accounting Standards
In November 2024, the FASB issued 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.
Note 3. Oil and Natural Gas Investments
The Partnership incurred approximately $
The Partnership has drilled and completed
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 (“Maximum Credit Amount”) of $
On
February 27, 2024,
● | As of the Effective Date, the borrowing base of the BF Credit Facility was, and remains, $ |
● | 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 $ |
Loan
costs associated with the Fifth Amendment, which totaled approximately $
9
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 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, 2025.
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 was in compliance with its applicable covenants and had no outstanding borrowings on the BF Credit Facility at March 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.
2025 | 2024 | |||||||
Balance at January 1 | $ | $ | ||||||
Well additions | ||||||||
Accretion | ||||||||
Revisions | ||||||||
Balance at March 31 | $ | $ |
Note 6. Capital Contribution and Partners’ Equity
At
inception, the General Partner and organizational limited partner made initial capital contributions totaling $
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
10
Under
the agreement with David Lerner Associates, Inc. (the “Dealer Manager”), the Dealer Manager received a total of
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.
For
the three months ended March 31, 2025, the Partnership paid distributions of $
For
the three months ended March 31, 2024, the Partnership paid distributions of $
The
Partnership accumulates unpaid distributions based on an annualized return of seven percent (
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.
11
For
the three months ended March 31, 2025 and 2024, approximately $
Note 8. Subsequent Events
In
April 2025, the Partnership paid approximately $
In
April 2025, on behalf of its limited partners, the Partnership made a payment to the State of North Dakota of approximately $
In
April 2025, the Partnership declared a monthly cash distribution to its holders of common units of $
12
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 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, 2024 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. |
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, 2024.
13
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 $146 million. The Partnership has incurred approximately $0.6 million in capital expenditures during the first quarter of 2025.
As a result of its acquisitions and completed drilling during the period of ownership, as of March 31, 2025, the Partnership owned an approximate 24% non-operated working interest in 312 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.
Current Price Environment
Oil, natural gas and natural gas liquids (“NGL”) prices are determined by many factors outside of the Partnership’s control and are subject to macroeconomic market volatility. Historically, 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 and production quotas set by the Organization of the Petroleum Exporting Countries (“OPEC”); and the strength of the U.S. dollar in international currency markets.
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. Oil prices declined through the first quarter of 2025 and continued into the second quarter, with oil prices closing at $57.13 per barrel on May 5, 2025 (the lowest level since the second quarter of 2021). Factors negatively impacting oil prices in 2025 include (i) confusion and uncertainty regarding U.S. trade policies and tariffs and the related concern of increased inflation; (ii) the decision by OPEC to increase its production quotas in May 2025; and (iii) global economic growth projections and the impact on global oil consumption.
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 months ended March 31, 2025 and 2024.
Three Months Ended March 31, | Percent | |||||||||||
2025 | 2024 | Change | ||||||||||
Average market closing prices (1) | ||||||||||||
Oil (per Bbl) | $ | 71.53 | $ | 76.91 | -7.0 | % | ||||||
Natural gas (per Mcf) | $ | 4.14 | $ | 2.15 | 92.6 | % |
(1) | Based on average NYMEX futures closing prices (oil) and NYMEX/Henry Hub spot prices (natural gas) |
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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 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, 2025 and 2024.
Three Months Ended March 31, | ||||||||||||||||||||
2025 | Percent of Revenue | 2024 | Percent of Revenue | Percent Change | ||||||||||||||||
Total revenues | $ | 20,859,931 | 100.0 | % | $ | 18,401,661 | 100.0 | % | 13.4 | % | ||||||||||
Production expenses | 5,944,773 | 28.5 | % | 5,158,144 | 28.0 | % | 15.3 | % | ||||||||||||
Production taxes | 1,490,550 | 7.1 | % | 1,395,000 | 7.6 | % | 6.8 | % | ||||||||||||
Depreciation, depletion, amortization and accretion | 7,252,575 | 34.8 | % | 6,045,594 | 32.9 | % | 20.0 | % | ||||||||||||
General and administrative expenses | 522,683 | 2.5 | % | 481,795 | 2.6 | % | 8.5 | % | ||||||||||||
Production (BOE): | ||||||||||||||||||||
Oil | 242,530 | 205,822 | 17.8 | % | ||||||||||||||||
Natural gas | 70,267 | 59,265 | 18.6 | % | ||||||||||||||||
Natural gas liquids | 61,767 | 53,929 | 14.5 | % | ||||||||||||||||
Total | 374,564 | 319,016 | 17.4 | % | ||||||||||||||||
Average sales price per unit: | ||||||||||||||||||||
Oil (per Bbl) | $ | 69.61 | $ | 75.59 | -7.9 | % | ||||||||||||||
Natural gas (per Mcf) | 4.01 | 2.37 | 69.2 | % | ||||||||||||||||
Natural gas liquids (per Bbl) | 37.00 | 37.12 | -0.3 | % | ||||||||||||||||
Combined (per BOE) | 55.69 | 57.68 | -3.5 | % | ||||||||||||||||
Average unit cost per BOE: | ||||||||||||||||||||
Production expenses | 15.87 | 16.17 | -1.8 | % | ||||||||||||||||
Production taxes | 3.98 | 4.37 | -9.0 | % | ||||||||||||||||
Depreciation, depletion, amortization and accretion | 19.36 | 18.95 | 2.2 | % | ||||||||||||||||
Capital expenditures | $ | 555,933 | $ | 5,179,613 |
Oil, natural gas and NGL revenues
For the three months ended March 31, 2025, revenues from oil, natural gas and NGL sales were $20.9 million. Revenues for the sale of crude oil were $16.9 million, which resulted in a realized price of $69.61 per barrel. Revenues for the sale of natural gas were $1.7 million, which resulted in a realized price of $4.01 per Mcf. Revenues for the sale of NGLs were $2.3 million, which resulted in a realized price of $37.00 per BOE of sold production. 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.
Compared to the three months ended March 31, 2024, the Partnership’s results for the three months ended March 31, 2025 were positively impacted by the completion of 15 new wells during the summer of 2024. Sold production for the Sanish Field Assets was approximately 4,200 BOE per day for the three months ended March 31, 2025, compared to 3,500 BOE per day for the three months ended March 31, 2024.
The Partnership’s sold production volumes helped offset the impact of lower oil market prices during the three months ended March 31, 2025. However, supply constraints and heightened demand due to cold winter temperatures led to sustained higher natural gas prices during the first quarter of 2025, contributing to higher Partnership natural gas revenue compared to the first quarter of 2024.
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.
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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 $0.70 and $1.00 per barrel of oil during the first quarter of 2025 in comparison to the first and fourth quarters of 2024, 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, 2025 and 2024, production expenses were $5.9 million and $5.2 million, respectively, and production expenses per BOE of sold production were $15.87 and $16.17, respectively. The decrease in production expenses per BOE is primarily due to the increase in sold production volumes, which increases the production base over which fixed operating costs are spread.
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, 2025 and 2024 were $1.5 million (7% of revenue) and $1.4 million (8% of revenue), respectively.
General and administrative expenses
The principal components of general and administrative expense are accounting, legal and consulting fees. General and administrative expenses for the three months ended March 31, 2025 and 2024 were $0.5 million in both periods.
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, 2025 and 2024 was $7.3 million and $6.0 million, and DD&A per BOE of sold production was $19.36 and $18.95, respectively. The increase in DD&A expense per BOE of production in the first quarter of 2025 is primarily due to the decrease of the Partnership’s estimated proved undeveloped reserves during the most recent reserves analyses (as of December 31, 2024) resulting from changes in the future drill schedule and well production forecasts.
Interest expense, net
Interest expense, net, for the three months ended March 31, 2025 and 2024 was $67,000 and $50,000, respectively. The Partnership had little to no outstanding balance on its BF Credit Facility during the first quarters of 2024 and 2025, so the expense recorded during these three-month periods primarily represented the amortization of capitalized 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; and (iv) exploration expenses, 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, 2025 and 2024.
Three Months Ended March 31, 2025 | Three Months Ended March 31, 2024 | |||||||
Net income | $ | 5,581,927 | $ | 5,270,636 | ||||
Interest expense, net | 67,423 | 50,492 | ||||||
Depreciation, depletion, amortization and accretion | 7,252,575 | 6,045,594 | ||||||
Exploration expenses | - | - | ||||||
Adjusted EBITDAX | $ | 12,901,925 | $ | 11,366,722 |
Liquidity and Capital Resources
Historically, the Partnership’s principal sources of liquidity have been cash on hand, the cash flow generated from the Sanish Field Assets, and availability under the Partnership’s revolving credit facility, if any. The Partnership had approximately $3.6 million in cash on hand and $20 million in availability under the BF Credit Facility at March 31, 2025, and the Partnership generated approximately $16.1 million and $53.7 million in cash flow from operating activities for the quarter ended March 31, 2025 and year ended December 31, 2024, 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.
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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
For the three months ended March 31, 2025, the Partnership paid distributions of $0.35 per common unit, or $6.6 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 2025. 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, 2025, was paid on April 3, 2025 to the common unit holders on record as of March 31, 2025.
For the three months ended March 31, 2024, the Partnership paid distributions of $0.40 per common unit, or $7.6 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 $2.239365 per common unit, or approximately $42 million.
Oil and Natural Gas Properties
The Partnership incurred approximately $0.6 million and $5.2 million in capital expenditures for the three months ended March 31, 2025 and 2024, respectively. During the summer of 2024, Chord substantially completed the drilling of 15 new wells, in which the Partnership had an average approximate non-operated working interest of 18%. The Partnership’s proportionate share of the related capital expenditures was approximately $26 million.
The Partnership anticipates that it may be obligated to invest at least an additional $100 million from 2025 through 2029 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, 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 2025, the Partnership paid approximately $2.3 million, or $0.12 per outstanding common unit, in distributions to its holders of common units.
In April 2025, on behalf of its limited partners, the Partnership made a payment to the State of North Dakota of approximately $400,000 for estimated withholding taxes for tax year 2024. This payment reduced the unpaid Payout Accrual by $0.021082 per common unit. As of the filing date of this Form 10-Q, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.239365 per common unit, or approximately $42 million.
In April 2025, 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 2025. The distribution of approximately $2.1 million was paid on May 5, 2025 to common unit holders on record as of April 30, 2025.
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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, 2025 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, 2025 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 2024 Annual Report on Form 10-K. There have been no material changes to the risk factors previously disclosed in the 2024 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.
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 March 31, 2025 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, 2025, 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, 2025 |
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