Annual Report for Fiscal Year Ending 12-31, 2025 (Form 10-K)

Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with Item 8 - the Consolidated Financial Statements and Notes thereto, the introduction of Part I regarding "Forward-Looking Statements," and Item 1A - Risk Factors appearing elsewhere in this Annual Report on Form 10-K.

Overview

Energy 11, L.P. (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, and all decisions regarding the management of the Partnership are made by the Board of Directors of the General Partner and its officers.

The Partnership was formed to acquire and develop oil and natural gas properties located onshore in the United States. On December 18, 2015, the Partnership completed its first purchase in the Sanish field, acquiring an approximate 11% non-operated working interest in the Sanish Field Assets for approximately $159.6 million. On January 11, 2017, the Partnership closed on its second purchase in the Sanish field, acquiring an additional approximate 11% non-operated working interest in the Sanish Field Assets for approximately $128.5 million. On March 31, 2017, the Partnership closed on its third purchase in the Sanish field, acquiring an additional approximate average 10.5% non-operated working interest in 82 of the Partnership's then 216 existing producing wells and 150 of the Partnership's then 253 future development locations in the Sanish Field Assets for approximately $52.4 million.

The Partnership has drilled and completed 101 new wells since the beginning of 2018; the Partnership's estimated share of capital expenditures for the drilling and completion of these 101 wells totaled approximately $148 million. The Partnership incurred approximately $3.3 million in capital expenditures during the twelve months ended December 31, 2025. See additional detail in "Oil and Natural Gas Properties" below.

As a result of these acquisitions and completed drilling during the period of ownership, as of December 31, 2025, the Partnership owns 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"), one of the largest producers in the basin, operates substantially all of the Sanish Field Assets.

Current Price Environment

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

The Partnership's oil and natural gas revenues are heavily weighted to oil, so any material change to market pricing for oil has a more significant impact to the Partnership's operational performance. While full-year 2025 oil prices averaged in the mid $60s per barrel, market prices trended downward throughout the year. Oil prices closed in mid-December 2025 at approximately $55 per barrel, the lowest level since the first quarter of 2021. Factors negatively weighing down oil prices in 2025 include (i) continued 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 starting in May 2025 (which continued through year-end); and (iii) global economic growth projections and the impact on global oil consumption. Oil prices had rebounded to above $60 per barrel in the first quarter of 2026 on the heels of higher seasonal demand and global supply restraint. In late February and early March 2026, military conflict involving the United States, Israel and Iran escalated in the Middle East, increasing geopolitical uncertainty in global energy markets. Concerns over disruptions to oil production and shipping routes in the region are anticipated to contribute to market price volatility for an undeterminable period of time.

Natural gas prices benefited from a tighter domestic market, as lower production growth, stronger LNG exports and declining storage inventories led to higher average prices in 2025 over 2024.

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 years ended December 31, 2025 and 2024.

		Year Ended December 31,								Percent
		2025				2024				Change
Average market closing prices (1)
Oil (per Bbl)		$	64.78			$	75.76				-14.5	%
Natural gas (per Mcf)		$	3.52			$	2.37				48.5	%

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

As specified by the SEC, the prices for oil, natural gas and NGL used to calculate the Partnership's reserves are based on the unweighted arithmetic average prices as of the first day of each of the twelve months during the years ended December 31, 2025 and 2024. The average realized oil, natural gas and NGL prices, including the effect of price differential adjustments, used in computing the Partnership's reserves as of December 31, 2025 were $63.99 per barrel of oil, $2.33 per MMcf of natural gas and $29.40 per barrel of NGL. The average realized oil, natural gas and NGL prices, including the effect of price differential adjustments, used in computing the Partnership's reserves as of December 31, 2024 were $74.72 per barrel of oil, $1.57 per MMcf of natural gas and $9.06 per barrel of NGL. See "Note 8. Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)" in Part II, Item 8. Financial Statements and Supplementary Data" of this Form 10-K for more information on the oil, natural gas and NGL prices used in computing the Partnership's reserves as of December 31, 2025 and 2024.

Results of Operations for Years 2025 and 2024

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

The following is a summary of the results from operations, including production, of the Partnership's non-operated working interest for the years ended December 31, 2025 and 2024.

		Year Ended Ended December 31,
		2025				Percent of Revenue				2024				Percent of Revenue				Percent Change
Total revenues		$	66,282,748				100.0	%		$	85,806,754				100.0	%			-22.8	%
Production expenses			23,318,978				35.2	%			21,981,337				25.6	%			6.1	%
Production taxes			4,565,154				6.9	%			6,836,284				8.0	%			-33.2	%
Depreciation, depletion, amortization and accretion			28,030,927				42.3	%			28,970,690				33.8	%			-3.2	%
General and administrative expenses			1,360,321				2.1	%			1,167,232				1.4	%			16.5	%
Sold production (BOE):
Oil			844,717								1,010,751								-16.4	%
Natural gas			294,667								257,067								14.6	%
Natural gas liquids			276,311								265,272								4.2	%
Total			1,415,695								1,533,090								-7.7	%
Average sales price per unit:
Oil (per Bbl)		$	63.85							$	73.96								-13.7	%
Natural gas (per Mcf)			2.60								1.56								66.7	%
Natural gas liquids (per Bbl)			28.04								32.58								-13.9	%
Combined (per BOE)			46.82								55.97								-16.3	%
Average unit cost per BOE:
Production expenses			16.47								14.34								14.9	%
Production taxes			3.22								4.46								-27.8	%
Depreciation, depletion, amortization and accretion			19.80								18.90								4.8	%
Capital expenditures		$	3,308,449							$	30,512,123

Oil, natural gas and NGL revenues

For the years ended December 31, 2025 and 2024, revenues for oil, natural gas and NGL sales were $66.3 million and $85.8 million, respectively. Revenues for the sale of oil were $53.9 million and $74.8 million, which resulted in realized prices of $63.85 and $73.96 per barrel, respectively. Revenues for the sale of natural gas were $4.6 million and $2.4 million, which resulted in realized prices of $2.60 and $1.56 per Mcf, respectively. Revenues for the sale of NGL were $7.8 million and $8.6 million, which resulted in realized prices of $28.04 and $32.58 per barrel of oil equivalent ("BOE") of production, respectively. Average realized prices in the fourth quarter of 2025 were approximately $57.83 per barrel of oil, $2.52 per Mcf of natural gas and $24.25 per BOE of NGL, compared to fourth quarter of 2024 realized prices of approximately $69.35 per barrel of oil, $1.43 per Mcf of natural gas and $31.88 per BOE of NGL.

The Partnership's sold oil production in 2024 benefited from the boost in production upon the completion and turning to sales of 15 new wells during the summer of 2024. The production from the new wells contributed to sold production for the Sanish Field Assets of approximately 5,200 BOE per day and 4,200 BOE per day for the quarter and year ended December 31, 2024. With no new completions in 2025, sold oil production declined steadily throughout the year as natural production decline is expected as wells age. However, improved technology and infrastructure at the operator level contributed to higher capture rates of natural gas in 2025, which led to increased natural gas and NGL production. Sold production for the Sanish Field Assets of approximately 3,500 BOE per day and 3,900 BOE per day for the quarter and year ended December 31, 2025, respectively.

The downward pressure on oil market prices during 2025 continued to negatively impact the Partnership's revenues compared to the year ended December 31, 2024. Supply constraints and heightened demand did have a positive effect on natural gas prices for the year ended December 31, 2025, which resulted in higher natural gas and NGL revenue and helped offset lower oil prices. The Partnership's realized sales prices for NGLs are influenced by the components extracted, including ethane, propane and butane and natural gasoline, among others, and the respective market pricing for each component.

If the operators of the Sanish Field Assets are unable to produce, process and sell oil and natural gas at economical prices, these operators may curtail daily production, shut-in producing wells or seek other cost-cutting measures, and could continue so long as producing is uneconomical. Consequently, any of these measures could significantly impact the Partnership's oil, natural gas and NGL production. Further, production is dependent on the investment in existing wells and the development of new wells. See further discussion of the Partnership's investment in new wells in "Liquidity and Capital Resources" below.

Oil differentials

The realized prices per barrel of oil above are based upon the NYMEX benchmark price less a cost to distribute the oil, or the differential. Oil price differentials primarily represent the transportation costs in moving produced oil at the wellhead to a refinery and are based on the availability of pipeline, rail and other transportation methods out of the Sanish field. Oil price differentials to the NYMEX benchmark price vary by operator based upon operator-specific contracts. On average, the Partnership's realized oil differential has increased by approximately $0.50 per barrel of oil during 2025 in comparison to 2024, which contributed to lower 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 and treatment of natural gas.

For the years ended December 31, 2025 and 2024, production expenses were $23.3 million and $22.0 million, respectively, and production expenses per BOE of sold production were $16.47 and $14.34, respectively. Production expenses for the fourth quarters of 2025 and 2024 were $5.1 million and $6.1 million, respectively, and production expenses per BOE of sold production were $16.10 and $12.81, respectively. Production expenses per BOE of sold production have increased in 2025 as a result of (i) increased sold production volumes for natural gas and NGLs contributing to higher gathering and processing expenses; (ii) increased LOE and workover activity to service and maintain well productivity; and (iii) lower sold production volumes, which decreases the production base over which fixed operating costs are spread.

Production taxes

Taxes on the production and extraction of oil and 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 years ended December 31, 2025 and 2024 were $4.6 million (6.9% of revenue) and $6.8 million (8.0% of revenue), respectively. Production taxes for the fourth quarters of 2025 and 2024 were $0.9 million (6.7% of revenue) and $2.0 million (8.0% of revenue), respectively. Oil production comprised approximately 60% and 66%, respectively, of the Partnership's sold production volumes for the years ended December 31, 2025 and 2024, and approximately 57% and 66%, respectively, for the three-month periods ended December 31, 2025 and 2024.

General and administrative expenses

General and administrative costs for the years ended December 31, 2025 and 2024 were $1.4 million and $1.2 million, respectively. The principal components of general and administrative expense are accounting, legal and consulting fees. 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 years ended December 31, 2025 and 2024 was $28.0 million and $29.0 million, and DD&A per BOE of sold production was $19.80 and $18.90, respectively. DD&A for the fourth quarters of 2025 and 2024 was $6.4 million and $9.0 million, and DD&A per BOE of sold production was $20.16 and $18.81, respectively. The increase in DD&A expense per BOE of production for the year ended December 31, 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, 2025 and June 30, 2025) resulting from well production performance and future forecasts.

Interest expense, net

Interest expense, net for the years ended December 31, 2025 and 2024 was $152,000 and $180,000, respectively. The Partnership carried little to no outstanding credit balance on the BF Credit Facility during 2025 and 2024, so in addition to interest expense on the BF Credit Facility, the expense during these periods also includes amortization of capitalized loan costs and non-use fees under the BF Loan Agreement.

See more information on the Partnership's credit facility in "Note 4. Debt" in Part II, Item 8 - Financial Statements and Supplementary Data appearing elsewhere in this Annual Report on Form 10-K.

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 Company'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 years ended December 31, 2025 and 2024.

		Year Ended				Year Ended
		December 31, 2025				December 31, 2024
Net income		$	8,855,771			$	26,670,865
Interest expense, net			151,597				180,346
Depreciation, depletion, amortization and accretion			28,030,927				28,970,690
Exploration expenses			-				-
Adjusted EBITDAX		$	37,038,295			$	55,821,901

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 $6.9 million of cash on-hand at December 31, 2025, and the Partnership generated approximately $43.7 million and $53.7 million in cash flow from operating activities for the years ended December 31, 2025 and 2024, respectively. Effective March 1, 2026, the Partnership extended the maturity of its BF Credit Facility to March 1, 2027 and currently has $10 million of availability under the BF Credit Facility (see "Subsequent Events" below).

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 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 Partnership was in compliance with all applicable covenants for the year ended December 31, 2025. 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 on the Partnership's BF Credit Facility in "Note 4 - Debt" in Part II, Item 8 - Financial Statements and Supplementary Data appearing elsewhere in this Annual Report on Form 10-K.

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 "Distributions" below.

Distributions

See the definition and discussion of "Payout" in "Note 5. Capital Contribution and Partners' Equity" in Part II, Item 8 - Financial Statements and Supplementary Data.

For the year ended December 31, 2025, the Partnership paid distributions of $1.40 per common unit, or $26.6 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 December 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 December 31, 2025, was paid on January 6, 2026 to the common unit holders on record as of December 31, 2025.

For the year ended December 31, 2024, the Partnership paid distributions of $1.45 per common unit, or $27.5 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 December 31, 2025, the unpaid Payout Accrual, for the period from March 2020 through November 2021, totaled $2.239365 per common unit, or approximately $42 million.

The General Partner monitors monthly Partnership distributions in conjunction with the Partnership's projected cash requirements for operations and capital expenditures for new wells. There can be no assurance as to the classification or duration of distributions at the current distribution rate. As discussed above, if distributions are not paid or are reduced, the difference to the current distribution rate of $1.40 per common unit will be deferred and is required to be paid before final Payout occurs.

Oil and Natural Gas Properties

The Partnership incurred approximately $3.3 million and $30.5 million in capital expenditures for the years ended December 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 $28 million.

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 flows from operations or there is no availability under the BF 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.

Oil, Natural Gas and NGL Reserves

The Partnership continually updates its proved undeveloped reserves ("PUD") during its semi-annual review based on current market conditions and future capital investment information provided by operators of the Sanish Field Assets as these factors may change the planned timing of drilling and completing PUD reserve locations within the SEC five-year window. See "Note 8. Supplementary Information on Oil, Natural Gas and Natural Gas Liquid Reserves (Unaudited)" in Part II, Item 8 - Financial Statements and Supplementary Data for complete information on the Partnership's reserves as of December 31, 2025 and 2024.

Transactions with Related Parties

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

See further discussion in "Note 7. Related Parties" in Part II, Item 8 - Financial Statements and Supplementary Data and in Part III, Item 13 - Certain Relationships and Related Transactions, and Director Independence, appearing elsewhere in this Annual Report on Form 10-K.

Critical Accounting Policies and Estimates

The discussion and analysis of the Partnership's financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these consolidated financial statements requires the Partnership to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. Certain of the Partnership's accounting policies involve estimates and assumptions to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. The Partnership bases these estimates and assumptions on historical experience and on various other information and assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as additional information is obtained, as more experience is acquired, as the Partnership's operating environment changes and as new events occur.

The Partnership's critical accounting policies are important to the portrayal of both its financial condition and results of operations and require the Partnership to make difficult, subjective or complex assumptions or estimates about matters that are uncertain. The Partnership would report different amounts in its consolidated financial statements, which could be material, if the Partnership used different assumptions or estimates. The Partnership believes that the following are the critical accounting policies used in the preparation of its consolidated financial statements.

Oil and Natural Gas Properties

The Partnership accounts for its oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized but charged to expense if and when the well is determined not to have found reserves in commercial quantities.

No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit-of-production amortization rate. Sales proceeds are credited to the carrying value of the properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when the Partnership is entering a new exploratory area in hopes of finding an oil and natural gas field that will be the focus of future developmental drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial, which will result in additional exploration expenses when incurred.

Impairment

The Partnership assesses its proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of the properties exceeds the sum of the estimated undiscounted future net cash flows, the Partnership recognizes an impairment expense equal to the difference between the carrying value and the fair value of the properties, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management's outlook of future commodity prices. The underlying commodity prices used in the determination of the Partnership's estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

Estimates of Oil, Natural Gas and Natural Gas Liquids Reserves

The Partnership's estimates of proved reserves are based on the quantities of oil, natural gas and natural gas liquids which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimate. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production, both of which provide accurate forecasts. Non-producing reserve estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. These methods provide accurate forecasts due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, the Partnership must estimate the amount and timing of future operating costs, severance taxes, development costs and workover costs, all of which may vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of the Partnership's reserves. Independent reserve engineers prepare the Partnership's reserve estimates at the end of each year.

Despite the inherent imprecision in these engineering estimates, the Partnership's reserves are used throughout the Partnership's financial statements. For example, since the Partnership uses the units-of-production method to amortize the costs of its oil and natural gas properties, the quantity of reserves could significantly impact its depreciation, depletion and amortization expense. The Partnership's reserves are also the basis of the Partnership's supplemental oil and natural gas disclosures.

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 Oil, natural gas and natural gas liquids revenue 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.

Subsequent Events

In January 2026, the General Partner of the Partnership declared a monthly cash distribution to its holders of common units of $0.11 per outstanding common unit for the month of January 2026. The distribution of approximately $2.1 million was paid on February 4, 2026 to common unit holders on record as of January 31, 2026.

In February 2026, the General Partner of the Partnership declared a monthly cash distribution to its holders of common units of $0.12 per outstanding common unit for the month of February 2026. The distribution of approximately $2.3 million was paid on March 4, 2026 to common unit holders on record as of February 28, 2026.

In February 2026, the Partnership and its lender entered in an amendment ("Seventh Amendment") to the BF Loan Agreement, effective March 1, 2026 ("Effective Date"), that renewed and extended the BF Credit Facility for one additional year to March 1, 2027. As of the Effective Date, the borrowing base of the BF Credit Facility is $10 million and the incremental borrowing fee decreased from 50 basis points to 25 basis points. The Partnership paid a loan fee to the Lender of $25,000. All associated loan costs with the Seventh Amendment were expensed as of the Effective Date.