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 Resources 12, L.P. (the "Partnership") was formed as a Delaware limited partnership. The initial capitalization of the Partnership of $1,000 occurred on December 30, 2016. The Partnership began offering common units of limited partner interest (the "common units") on a best-efforts basis on May 17, 2017, the date the Partnership's initial Registration Statement on Form S-1 (File No. 333-216891) was declared effective by the Securities and Exchange Commission. The Partnership completed its best-efforts offering on October 24, 2019. Total common units sold were approximately 11.0 million for gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 million.

The general partner is Energy Resources 12 GP, LLC (the "General Partner"). 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 has no officers, directors or employees.

The Partnership was formed to acquire primarily oil and natural gas properties located onshore in the United States. On February 1, 2018, the Partnership completed its first purchase ("Acquisition No. 1") in the Williston Basin of North Dakota, acquiring, at closing, non-operated working interests in producing wells and in-process wells, along with additional future development locations, predominantly in McKenzie, Dunn, McLean and Mountrail counties of North Dakota (collectively, the "Bakken Assets"), for $87.5 million, subject to customary adjustments. On August 31, 2018, the Partnership closed on its second asset purchase ("Acquisition No. 2"), acquiring an additional non-operated working interest in the Bakken Assets for $82.5 million, subject to customary adjustments. Prior to these acquisitions, the Partnership owned no oil and natural gas assets. The Partnership utilized proceeds from its best-efforts offering and available financing to close on the acquisitions.

As a result of these acquisitions and completed drilling during the period of ownership, as of December 31, 2025, the Partnership's ownership of the Bakken Assets consisted of an approximate 5.3% non-operated working interest in 452 producing wells, an estimated approximate 7.1% non-operated working interest in 12 wells in various stages of the drilling and completion process and additional possible future development locations.

The Bakken Assets are operated by multiple third-party operators, including Devon Energy Corporation, Marathon Oil, EOG Resources, Continental Resources and Chord Energy.

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 $64.22 per barrel of oil, $2.22 per MMcf of natural gas and $18.41 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 $75.33 per barrel of oil, $1.43 per MMcf of natural gas and $0.49 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 quarterly 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 table is a summary of the results from operations, including production, of the Partnership's non-operated working interest in the Bakken Assets for the years ended December 31, 2025 and 2024.

		Year Ended December 31,
		2025				Percent of Revenue				2024				Percent of Revenue				Percent Change
Total revenues		$	26,074,406				100.0	%		$	36,118,140				100.0	%			-27.8	%
Production expenses			14,305,240				54.9	%			17,670,082				48.9	%			-19.0	%
Production taxes			1,784,385				6.8	%			2,923,118				8.1	%			-39.0	%
Depreciation, depletion, amortization and accretion			15,673,314				60.1	%			17,823,407				49.3	%			-12.1	%
General and administrative expenses			2,222,707				8.5	%			2,198,954				6.1	%			1.1	%
Sold production (BOE):
Oil			329,265								421,815								-21.9	%
Natural gas			161,553								176,373								-8.4	%
Natural gas liquids			148,241								156,667								-5.4	%
Total			639,059								754,855								-15.3	%
Average sales price per unit:
Oil (per Bbl)		$	64.25							$	74.02								-13.2	%
Natural gas (per Mcf)			2.32								1.45								60.0	%
Natural gas liquids (per Bbl)			18.01								21.45								-16.0	%
Combined (per BOE)			40.80								47.85								-14.7	%
Average unit cost per BOE:
Production expenses			22.38								23.41								-4.4	%
Production taxes			2.79								3.87								-28.0	%
Depreciation, depletion, amortization and accretion			24.53								23.61								3.9	%
Capital expenditures		$	3,881,838							$	2,826,249

Oil, natural gas and NGL revenues

For the years ended December 31, 2025 and 2024, revenues for oil, natural gas and NGL sales were $26.1 million and $36.1 million, respectively. Revenues for the sale of crude oil were $21.2 million and $31.2 million, respectively, which resulted in realized prices of $64.25 and $74.02 per barrel, respectively. Revenues for the sale of natural gas were $2.3 million and $1.5 million, respectively, which resulted in realized prices of $2.32 and $1.45 per Mcf, respectively. Revenues for the sale of NGLs were $2.7 million and $3.4 million, respectively, which resulted in realized prices of $18.01 and $21.45 per BOE, respectively. Average realized prices in the fourth quarter of 2025 were approximately $61.45 per barrel of oil, $2.28 per Mcf of natural gas and $14.88 per BOE of NGL, compared to the fourth quarter of 2024 prices of approximately $67.50 per barrel of oil, $1.76 per Mcf of natural gas and $21.74 per BOE of NGL.

The Partnership's results for 2025 were negatively impacted by the natural decline of aging wells, with sold production for the Bakken Assets totaling approximately 1,700 BOE per day and 1,800 BOE per day for the quarter and year ended December 31, 2025. The Partnership turned 20 new wells to sales during the second and third quarters of 2024, which contributed to sold production for the Bakken Assets of approximately 2,000 BOE per day and 2,100 BOE per day for the quarter and year ended December 31, 2024. The Partnership anticipates production to see a boost in the first half of 2026 due to the anticipated completion of the 12 wells currently in various stages of the drilling and completion process. Production volumes per day fluctuate due to the timing of well completions; new wells often have high levels of production immediately following completion.

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 throughout 2025, which resulted in higher natural gas revenues 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 Bakken Assets are unable to produce, process and sell oil and natural gas at economical prices, the operators may curtail daily production, shut-in producing wells or seek other cost-cutting measures. Consequently, any of these measures could significantly impact the Partnership's oil, natural gas and NGL production, and there can be no assurance regarding how they will produce if and when they are brought back on-line. Further, production is dependent on the investment in existing wells and the development of new wells. See further discussion on the Partnership's investment in new wells in "Liquidity and Capital Resources" below.

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 Bakken. Oil price differentials to the NYMEX benchmark price vary by operator based upon operator-specific contracts. On a weighted average basis by operator, the Partnership's realized oil price differentials were approximately $0.70 per barrel of oil higher during the year ended December 31, 2025, in comparison to year ended December 31, 2024, 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 pipelines servicing the region are suspended at a future date, the disruption of transporting the Partnership's production out of North Dakota could negatively impact the Partnership's 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 $14.3 million and $17.7 million, and production expenses per BOE of sold production were $22.38 and $23.41, respectively. Production expenses for the fourth quarters of 2025 and 2024 were $3.8 million and $4.1 million, respectively, and production expenses per BOE of production were $24.11 and $22.83, respectively. The Partnership's production expenses during 2024 were substantially higher than those in 2025 due to (i) additional marketing expenses required on the sale of natural gas at low market prices, and (ii) more workover activity to ensure production from wells is maximized. However, lower production volumes in fourth quarter of 2025 reduced the base over which fixed costs are spread, which led to higher production expenses per BOE for the three months ended December 31, 2025 compared to the same period of 2024.

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 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 NGL to total sales. Production taxes for the years ended December 31, 2025 and 2024 were $1.8 million (6.8% of revenue) and $2.9 million (8.1% of revenue), respectively. Production taxes for the fourth quarters of 2025 and 2024 were $0.4 million (6.0% of revenue) and $0.6 million (8.0% of revenue), respectively. Oil production comprised approximately 52% and 56%, respectively, of the Partnership's sold production volumes in the years ended December 31, 2025 and 2024, and approximately 48% and 57%, 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 $2.2 million in both periods. The principal components of general and administrative expense are accounting, legal, advisory, consulting and management fees.

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. The Partnership's DD&A for the years ended December 31, 2025 and 2024 was $15.7 million and $17.8 million, respectively, and DD&A per BOE of production was $24.53 and $23.61, respectively. DD&A for the fourth quarters of 2025 and 2024 was $3.2 million and $4.1 million, respectively, and DD&A per BOE of production was $20.63 and $23.00, respectively.

The increase in DD&A expense per BOE of production for the year ended December 31, 2025, compared to 2024, is primarily due to incremental increases to the depletion rate through the first nine months of 2025 based on usage of the Partnership's proved developed reserves. However, an increase in proved undeveloped reserves resulting from adjustments to future drill schedule (see new wells discussed below Oil and Natural Gas Properties) made in the December 31, 2025 reserve analysis reduced the fourth quarter depletion rate and resulted in a decrease in DD&A expense per BOE for the quarter ended December 31, 2025, compared to 2024.

Interest expense, net

Interest expense, net for the years ended December 31, 2025 and 2024 was approximately $511,000 and $259,000, respectively. The primary component of interest expense is interest expense on the BancFirst Credit Facility ("Credit Facility").

Supplemental Non-GAAP Measure

The Partnership uses "Adjusted EBITDAX", defined as loss 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 loss		$	(8,422,367	)		$	(4,756,820	)
Interest expense, net			511,127				259,399
Depreciation, depletion, amortization and accretion			15,673,314				17,823,407
Exploration expenses			-				-
Adjusted EBITDAX		$	7,762,074			$	13,325,986

Liquidity and Capital Resources

The Partnership's principal sources of liquidity are cash on-hand, cash flow generated from the Bakken Assets and availability under the Partnership's Credit Facility. At the time of filing this Form 10-K, the Partnership had approximately $0.8 million in cash on-hand. The Partnership generated approximately $8.1 million and $13.4 million in cash flow from operating activities for the year ended December 31, 2025 and 2024, respectively. The Partnership has approximately $4.2 million in availability under the Credit Facility at both December 31, 2025 and as of the filing of this Form 10-K.

The Partnership anticipates that cash on-hand, cash flow from operations availability under the Credit Facility will be adequate to meet its liquidity requirements for at least the next 12 months, including completing the outstanding capital expenditures discussed below. As discussed in Note 4. Debt in Part II, Item 8 - Financial Statements and Supplementary Data, the Partnership was not in compliance with its debt service coverage ratio as defined within the BF Loan Agreement at December 31, 2024, March 31, 2025 and June 30, 2025. The Lender waived this covenant calculation for each of those quarters. In August 2025, the Partnership and its Lender entered into an amendment to the Loan Agreement, that among other things, renewed and extended the Credit Facility for an additional year to March 1, 2027, and amended the definition of the debt service coverage ratio. Under the amended Loan Agreement, the debt service coverage ratio is a quarterly calculation (started with the quarter ended September 30, 2025), as opposed to a trailing 12-month calculation. The Partnership was in compliance with its financial covenants for the quarters ended September 30, 2025 and December 31, 2025.

If the Partnership is not in compliance with its covenants in future periods, the Partnership cannot provide any assurance or guarantee that covenant compliance waivers will be granted in future periods. If the Partnership is not able to obtain waivers, either (a) the Credit Facility may not be available for the Partnership's use or (b) an outstanding balance under the Credit Facility may become due on demand at that time.

Future growth is dependent on the Partnership's ability to add reserves in excess of production. The Partnership intends to seek opportunities to invest in its existing production wells via capital expenditures and/or drill new wells on existing leasehold sites when cash flow is available. The Partnership faces the challenge of natural production volume declines, so as reservoirs are depleted, oil and natural gas production from Partnership wells will decrease. Although the Partnership anticipates its cash on-hand, cash flow from operations and availability under the Credit Facility to be adequate to fund its cash requirements, if market prices for oil and natural gas decline and/or production from Partnership wells is not replenished through the completion of new well investments, 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 fund distributions to its limited partners and/or participate in future drilling programs as proposed by the operators of the Bakken Assets.

Partners' Equity

The Partnership completed its best-efforts offering of common units on October 24, 2019. As of the conclusion of the offering, the Partnership had completed the sale of approximately 11.0 million common units for total gross proceeds of $218.0 million and proceeds net of offering costs of $204.3 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 also has Dealer Manager Incentive Fees (defined below) where the Dealer Manager could receive distributions up to an additional 4% of gross proceeds of the common units sold in the Partnership's best-efforts offering as outlined in the prospectus for that offering based on the performance of the Partnership. Based on the common units sold through the conclusion of the offering, the Dealer Manager Incentive Fees are approximately $8.7 million, subject to Payout (defined 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 declared and paid distributions of $0.641082 per common unit, or $7.1 million. For the year ended December 31, 2024, the Partnership declared and paid distributions of $1.282163 per common unit, or $14.1 million.

Under the amended Loan Agreement, the Partnership is not permitted to make distributions to limited partners if paying said distribution(s) would create an event of default under the Loan Agreement. In July 2025, the General Partner elected to suspend distributions to Partnership limited partners. 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 July 2025 to December 2025, totaled $0.662216 per common unit, or approximately $7.3 million.

Oil and Natural Gas Properties

Future Investment

The Partnership incurred approximately $3.9 million and $2.8 million, respectively, in capital expenditures for the years ended December 31, 2025 and 2024. In October and November 2025, the Partnership elected to participate in the drilling and completion of 12 new wells, including six of which the Partnership has an average working interest of approximately 14%. The Partnership's share of the estimated capital expenditures for these 12 wells is approximately $9 million. Drilling began on these wells during the fourth quarter of 2025, and approximately $1.5 million in capital costs had been incurred as of December 31, 2025. The Partnership anticipates its operators will complete these wells during the first half of 2026, and therefore, the remaining capital costs are estimated to be incurred through the second quarter of 2026. In addition to the estimated capital expenditures for in-process wells, the Partnership anticipates that it may be obligated to invest up to an additional $40 million in drilling capital expenditures from 2026 through 2030 to participate in new well development in the Bakken Assets without becoming subject to non-consent penalties under the joint operating agreements or North Dakota statutes governing the Bakken Assets.

Since the Partnership is not the operator of any of its oil and natural gas properties, it is difficult to predict levels of future participation in the drilling and completion of new wells, the timing of such activities and their associated capital expenditures. This makes capital expenditures for drilling and completion projects difficult to forecast for 2026. Current estimated capital expenditures could be significantly different from amounts actually invested.

As described above, the Partnership's liquidity is currently dependent upon cash on-hand, cash from operations and availability under the Credit Facility. If the Partnership is not able to generate sufficient cash flow from operations or there is no availability under the 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 and would be subject to a non-consent penalty.

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 Bakken 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 6. 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. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. 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 our 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 Accounts receivable and other current assets 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 March 2026, the Partnership and its Lender entered into an amendment ("Second Amendment") to the Loan Agreement that implemented a risk management program to manage the commodity price risk of the Partnership's future oil and gas production under certain conditions. Under the Second Amendment, the Partnership must hedge at least 50% of its rolling 12-month projected future production if the Partnership's utilization of the Credit Facility is greater than 20% but less than or equal to 30% of PV-9 (defined as the net present value, discounted at 9% per annum) of the Partnership's proved developed producing reserves, as calculated by the Lender during the Lender's scheduled redeterminations. Further, the Partnership must hedge at least 50% of its rolling 24-month projected future production if the Partnership's utilization of the Credit Facility is greater than 30% of PV-9. The Partnership is not required to enter into future hedging transactions if the Partnership maintains a Credit Facility utilization rate of less than or equal to 20% of the Partnership's PV-9.

All other terms and conditions of the Loan Agreement and its subsequent amendments remain in effect.

In March 2026, the Partnership entered into costless collar derivative contracts to mitigate the commodity price risk for a portion of the Partnership's expected oil production for the period from April 2026 to December 2026. Costless collar derivative contracts establish floor and ceiling prices on future anticipated production, and the Partnership did not pay or receive a premium when entering the contracts. The contracts will be settled monthly. Total production covered under the contracts is 90,000 barrels of oil, with established floor and ceiling prices $75.00 and $94.35, respectively.