Quarterly Report for Quarter Ending June 30, 2025 (Form 10-Q)

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.

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 $147 million. The Partnership has incurred approximately $2.0 million in capital expenditures during the first half of 2025.

As a result of its acquisitions and completed drilling during the period of ownership, as of June 30, 2025, the Partnership owned an approximate 24% non-operated working interest in 309 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 first 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. In July 2025, OPEC announced an additional production increase for August 2025, which could lead to further pressure on oil prices.

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

The following table lists average NYMEX prices for oil and natural gas for the three and six months ended June 30, 2025 and 2024.

		Three Months Ended June 30,								Percent				Six Months Ended June 30,								Percent
		2025				2024				Change				2025				2024				Change
Average market closing prices (1)
Oil (per Bbl)		$	63.87			$	80.66				-20.8	%		$	67.67			$	78.81				-14.1	%
Natural gas (per Mcf)		$	3.19			$	2.07				54.1	%		$	3.66			$	2.11				73.5	%

(1)

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

Results of Operations

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

The following table summarizes the results from operations, including production, of the Partnership's non-operated working interest for the three and six months ended June 30, 2025 and 2024.

		Three Months Ended June 30,																				Six Months Ended June 30,
		2025				Percent of Revenue				2024				Percent of Revenue				Percent Change				2025				Percent of Revenue				2024				Percent of Revenue				Percent Change
Total revenues		$	16,543,412				100.0	%		$	16,986,275				100.0	%			-2.6	%		$	37,403,343				100.0	%		$	35,387,936				100.0	%			5.7	%
Production expenses			6,069,324				36.7	%			4,960,463				29.2	%			22.4	%			12,014,097				32.1	%			10,118,607				28.6	%			18.7	%
Production taxes			1,087,999				6.6	%			1,371,927				8.1	%			-20.7	%			2,578,549				6.9	%			2,766,927				7.8	%			-6.8	%
Depreciation, depletion, amortization and accretion			7,194,457				43.5	%			5,413,886				31.9	%			32.9	%			14,447,032				38.6	%			11,459,480				32.4	%			26.1	%
General and administrative expenses			305,068				1.8	%			202,547				1.2	%			50.6	%			827,751				2.2	%			684,342				1.9	%			21.0	%
Production (BOE):
Oil			221,829								188,397								17.7	%			464,359								394,220								17.8	%
Natural gas			76,402								56,538								35.1	%			146,670								115,802								26.7	%
Natural gas liquids			70,995								52,833								34.4	%			132,761								106,762								24.4	%
Total			369,226								297,768								24.0	%			743,790								616,784								20.6	%
Average sales price per unit:
Oil (per Bbl)		$	61.90							$	79.96								-22.6	%		$	65.93							$	77.68								-15.1	%
Natural gas (per Mcf)			2.16								1.09								98.2	%			3.05								1.74								75.3	%
Natural gas liquids (per Bbl)			25.66								29.39								-12.7	%			30.93								33.29								-7.1	%
Combined (per BOE)			44.81								57.05								-21.4	%			50.29								57.37								-12.3	%
Average unit cost per BOE:
Production expenses			16.44								16.66								-1.3	%			16.15								16.41								-1.6	%
Production taxes			2.95								4.61								-36.0	%			3.47								4.49								-22.7	%
Depreciation, depletion, amortization and accretion			19.49								18.18								7.2	%			19.42								18.58								4.5	%
Capital expenditures		$	1,476,114							$	6,924,273											$	2,032,047							$	12,103,886

Oil, natural gas and NGL revenues

For the three months ended June 30, 2025, revenues from oil, natural gas and NGL sales were $16.5 million. Revenues for the sale of crude oil were $13.7 million, which resulted in a realized price of $61.90 per barrel. Revenues for the sale of natural gas were $1.0 million, which resulted in a realized price of $2.16 per Mcf. Revenues for the sale of NGLs were $1.8 million, which resulted in a realized price of $25.66 per BOE of sold production. For the three months ended June 30, 2024, revenues from oil, natural gas and NGL sales were $17.0 million. Revenues for the sale of crude oil were $15.1 million, which resulted in a realized price of $79.96 per barrel. Revenues for the sale of natural gas were $0.4 million, which resulted in a realized price of $1.09 per Mcf. Revenues for the sale of NGLs were $1.6 million, which resulted in a realized price of $29.39 per BOE of sold production.

For the six months ended June 30, 2025, revenues from oil, natural gas and NGL sales were $37.4 million. Revenues for the sale of crude oil were $30.6 million, which resulted in a realized price of $65.93 per barrel. Revenues for the sale of natural gas were $2.7 million, which resulted in a realized price of $3.05 per Mcf. Revenues for the sale of NGLs were $4.1 million, which resulted in a realized price of $30.93 per BOE of sold production. For the six months ended June 30, 2024, revenues from oil, natural gas and NGL sales were $35.4 million. Revenues for the sale of crude oil were $30.6 million, which resulted in a realized price of $77.68 per barrel. Revenues for the sale of natural gas were $1.2 million, which resulted in a realized price of $1.74 per Mcf. Revenues for the sale of NGLs were $3.6 million, which resulted in a realized price of $33.29 per BOE of sold production.

Compared to the three and six months ended June 30, 2024, the Partnership's sold production volumes for the three and six months ended June 30, 2025 increased substantially due to the completion of 15 new wells during the summer of 2024. Sold production for the Sanish Field Assets was approximately 4,100 BOE per day for the three and six months ended June 30, 2025. Adverse weather conditions in North Dakota during a multi-day stretch in mid-January 2024 led to suspended production throughout the Bakken, and many of these suspended wells did not return to production during the first half of 2024. As a result, sold production was approximately 3,300 BOE per day and 3,400 BOE per day for the three and six months ended June 30, 2024, respectively.

The Partnership's sold production volumes helped offset the impact of lower oil market prices during the three and six months ended June 30, 2025. However, supply constraints and heightened demand due to cold winter temperatures led to higher natural gas prices during the first quarter of 2025, contributing to higher Partnership natural gas revenue for the first half of 2025 compared to the first half 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.

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 for the second quarter of 2025 held flat compared to the first quarter of 2025 (approximately $2 per barrel of oil), but increased by approximately $0.60 in comparison to the first half of 2024. Higher oil differentials reduce 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 June 30, 2025 and 2024, production expenses were $6.1 million and $5.0 million, respectively, and production expenses per BOE of sold production were $16.44 and $16.66, respectively. For the six months ended June 30, 2025 and 2024, production expenses were $12.0 million and $10.1 million, respectively, and production expenses per BOE of sold production were $16.15 and $16.41, respectively. Increased sold production volumes for natural gas and NGLs contributed to higher gathering and processing expenses during the first half of 2025, but the decrease in production expenses per BOE from 2024 to 2025 is primarily due to higher 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 natural gas are regulated and set by North Dakota tax authorities. Taxes on the sale of natural gas and NGL products are less than taxes levied on the sale of oil. Therefore, production taxes as a percentage of revenue may fluctuate dependent upon the ratio of sales of natural gas and NGLs to total sales. Production taxes for the three months ended June 30, 2025 and 2024 were $1.1 million (7% of revenue) and $1.4 million (8% of revenue), respectively. Production taxes for the six months ended June 30, 2025 and 2024 were $2.6 million (7% of revenue) and $2.8 million (8% of revenue), respectively. Oil production comprised approximately 60% of the Partnership's sold production volumes for the quarter ended June 30, 2025, compared to 63% for the quarter ended June 30, 2024.

General and administrative expenses

The principal components of general and administrative expense are accounting, legal and consulting fees. General and administrative expenses for the three months ended June 30, 2025 and 2024 were $0.3 million and $0.2 million, respectively. General and administrative expenses for the six months ended June 30, 2025 and 2024 were $0.8 million and $0.7 million, respectively. Higher legal and professional fees have contributed to the increase in general and administrative expenses in 2025.

Depreciation, depletion, amortization and accretion ("DD&A")

DD&A of capitalized drilling and development costs of producing oil, natural gas and NGL properties are computed using the unit-of-production method on a field basis based on total estimated proved developed oil, natural gas and NGL reserves. Costs of acquiring proved properties are depleted using the unit-of-production method on a field basis based on total estimated proved developed and undeveloped reserves. DD&A for the three months ended June 30, 2025 and 2024 was $7.2 million and $5.4 million, and DD&A per BOE of sold production was $19.49 and $18.18, respectively. DD&A for the six months ended June 30, 2025 and 2024 was $14.4 million and $11.5 million, and DD&A per BOE of sold production was $19.42 and $18.58, respectively. The increase in DD&A expense per BOE of production in the first half of 2025 is primarily due to the decrease of the Partnership's estimated proved reserves during the most recent reserves analyses (as of December 31, 2024 and June 30, 2025) resulting from changes in the future drill schedule and well production performance and forecasts.

Interest expense, net

Interest expense, net, for the three months ended June 30, 2025 and 2024 was $28,000 in both periods. Interest expense, net, for the six months ended June 30, 2025 and 2024 was $95,000 and $78,000, respectively. The Partnership had little to no outstanding balance on its BF Credit Facility during the first six months of 2024 and 2025, so the expense recorded during these three- and six-month periods primarily 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; 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 and six months ended June 30, 2025 and 2024.

		Three Months Ended June 30, 2025				Three Months Ended June 30, 2024				Six Months Ended June 30, 2025				Six Months Ended June 30, 2024
Net income		$	1,858,829			$	5,009,717			$	7,440,756			$	10,280,353
Interest expense, net			27,735				27,735				95,158				78,227
Depreciation, depletion, amortization and accretion			7,194,457				5,413,886				14,447,032				11,459,480
Exploration expenses			-				-				-				-
Adjusted EBITDAX		$	9,081,021			$	10,451,338			$	21,982,946			$	21,818,060

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 $5.9 million in cash on hand and $20 million in availability under the BF Credit Facility at June 30, 2025. The Partnership generated approximately $26.8 million and $53.7 million in cash flow from operating activities for the six months ended June 30, 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.

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 and six months ended June 30, 2025, the Partnership paid distributions of $0.35 per common unit and $0.70 per common unit, or $6.6 million and $13.3 million, respectively. 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 June 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 June 30, 2025, was paid on July 3, 2025 to the common unit holders on record as of June 30, 2025.

For the three and six months ended June 30, 2024, the Partnership paid distributions of $0.35 per common unit and $0.75 per common unit, or $6.6 million and $14.2 million, respectively.

The Partnership accumulates unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are required to be paid before final Payout occurs. The unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.239365 per common unit, or approximately $42 million, at June 30, 2025.

Oil and Natural Gas Properties

The Partnership incurred approximately $2.0 million and $12.1 million in capital expenditures for the six months ended June 30, 2025 and 2024, respectively. During the second and third quarters 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 $27 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 July 2025, the Partnership paid approximately $2.3 million, or $0.12 per outstanding common unit, in distributions to its holders of common units.

In July 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 July 2025. The distribution of approximately $2.1 million was paid on August 5, 2025 to common unit holders on record as of July 31, 2025.