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 properties may not be successful or that its 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 and acquisition 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

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 gas properties located onshore in the United States. On February 1, 2018, the Partnership completed its first asset purchase 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 approximately $90.5 million. On August 31, 2018, the Partnership closed on its second asset purchase, acquiring an additional non-operated working interest in the Bakken Assets for approximately $81.3 million. 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 June 30, 2025, the Partnership's ownership of the Bakken Assets consisted of an approximate 5% non-operated working interest in 450 producing wells, an estimated 5% non-operated working interest in two wells in various stages of the drilling and completion process and additional possible future development locations.

The Bakken Assets are operated by 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 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 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 is a summary of the results from operations, including production, of the Partnership's non-operated working interest in the Bakken Assets 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		$	6,402,017				100.0	%		$	9,085,649				100.0	%			-29.5	%		$	14,279,170				100.0	%		$	17,768,409				100.0	%			-19.6	%
Production expenses			3,271,318				51.1	%			4,769,531				52.5	%			-31.4	%			7,145,603				50.0	%			9,085,958				51.1	%			-21.4	%
Production taxes			470,285				7.3	%			873,381				9.6	%			-46.2	%			1,028,732				7.2	%			1,545,922				8.7	%			-33.5	%
Depreciation, depletion, amortization and accretion			4,350,181				68.0	%			4,350,248				47.9	%			0.0	%			8,126,382				56.9	%			8,464,510				47.6	%			-4.0	%
General and administrative expenses			533,466				8.3	%			479,000				5.3	%			11.4	%			1,176,666				8.2	%			1,176,686				6.6	%			0.0	%
Sold production (BOE):
Oil			84,675								97,659								-13.3	%			176,541								199,445								-11.5	%
Natural gas			41,898								40,833								2.6	%			77,557								85,185								-9.0	%
Natural gas liquids			39,008								35,978								8.4	%			69,636								75,199								-7.4	%
Total			165,581								174,470								-5.1	%			323,734								359,829								-10.0	%
Average sales price per unit:
Oil (per Bbl)		$	61.89							$	80.10								-22.7	%		$	65.50							$	76.95								-14.9	%
Natural gas (per Mcf)			1.97								0.76								159.2	%			2.75								1.48								85.8	%
Natural gas liquids (per Bbl)			17.10								18.60								-8.1	%			20.65								22.14								-6.7	%
Combined (per BOE)			38.66								52.08								-25.8	%			44.11								49.38								-10.7	%
Average unit cost per BOE:
Production expenses			19.76								27.34								-27.7	%			22.07								25.25								-12.6	%
Production taxes			2.84								5.01								-43.3	%			3.18								4.30								-26.0	%
Depreciation, depletion, amortization and accretion			26.27								24.93								5.4	%			25.10								23.52								6.7	%
Capital expenditures		$	741,329							$	1,170,700											$	1,430,720							$	1,704,954

Oil, natural gas and NGL revenues

For the three months ended June 30, 2025, revenues for oil, natural gas and NGL sales were $6.4 million. Revenues for the sale of crude oil were $5.2 million, which resulted in a realized price of $61.89 per barrel. Revenues for the sale of natural gas were $0.5 million, which resulted in a realized price of $1.97 per Mcf. Revenues for the sale of NGLs were approximately $0.7 million, which resulted in a realized price of $17.10 per BOE of production. For the three months ended June 30, 2024, revenues for oil, natural gas and NGL sales were $9.1 million. Revenues for the sale of crude oil were $8.2 million, which resulted in a realized price of $80.10 per barrel. Revenues for the sale of natural gas were $0.2 million, which resulted in a realized price of $0.76 per Mcf. Revenues for the sale of NGLs were approximately $0.7 million, which resulted in a realized price of $18.60 per BOE of production.

For the six months ended June 30, 2025, revenues for oil, natural gas and NGL sales were $14.3 million. Revenues for the sale of crude oil were $11.6 million, which resulted in a realized price of $65.50 per barrel. Revenues for the sale of natural gas were $1.3 million, which resulted in a realized price of $2.75 per Mcf. Revenues for the sale of NGLs were approximately $1.4 million, which resulted in a realized price of $20.65 per BOE of production. For the six months ended June 30, 2024, revenues for oil, natural gas and NGL sales were $17.8 million. Revenues for the sale of crude oil were $15.3 million, which resulted in a realized price of $76.95 per barrel. Revenues for the sale of natural gas were $0.8 million, which resulted in a realized price of $1.48 per Mcf. Revenues for the sale of NGLs were approximately $1.7 million, which resulted in a realized price of $22.14 per BOE of production.

Production volumes per day fluctuate due to the timing of well completions; new wells often have high levels of production immediately following completion, then decline to more consistent levels as the wells age. The Partnership's results for the three and six months ended June 30, 2025 were negatively impacted by this natural decline of aging wells; sold production for the Bakken Assets was approximately 1,800 BOE per day for the three and six months ended June 30, 2025. Sold production for the Bakken Assets was approximately 1,900 BOE per day and 2,000 BOE per day for the three and six months ended June 30, 2024.

The Partnership's results for the three and six months ended June 30, 2025 were also negatively impacted by lower market prices for oil. However, supply constraints and heightened demand due to cold winter temperatures led to sustained higher natural gas prices during the first quarter of 2025, contributing to higher Partnership natural gas revenue compared to the first half of 2024.

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 average, the Partnership's realized oil price differentials during the second quarter of 2025 decreased in comparison to the first quarter of 2025; lower differentials increase 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 contracts in effect for the extraction, transportation and treatment of oil and natural gas.

Production expenses for the three months ended June 30, 2025 and 2024 were $3.3 million and $4.8 million, and production expenses per BOE were $19.76 and $27.34, respectively. Production expenses for the six months ended June 30, 2025 and 2024 were $7.1 million and $9.1 million, and production expenses per BOE were $22.07 and $25.25, respectively. The Partnership's production expenses during the first half of 2024 were substantially higher than the same period of 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.

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 $0.5 million (7% of revenue) and $0.9 million (10% of revenue), respectively. Production taxes for the six months ended June 30, 2025 and 2024 were $1.0 million (7% of revenue) and $1.5 million (9% of revenue), respectively. Oil production comprised approximately 51% and 55% of the Partnership's sold production volumes in the three and six months ended June 30, 2025, respectively, compared to 56% and 55% for the three and six months ended June 30, 2024.

General and administrative expenses

The principal components of general and administrative expense are accounting, legal, advisory and consulting fees. General and administrative costs for the three months ended June 30, 2025 and 2024 were $0.5 million in both periods. General and administrative costs for the three months ended June 30, 2025 and 2024 were $1.2 million in both periods.

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

DD&A of capitalized drilling and development costs of producing oil, natural gas and NGL properties are computed using the unit-of-production method on a field basis based on total estimated proved developed oil, natural gas and NGL reserves. Costs of acquiring proved properties are depleted using the unit-of-production method on a field basis based on total estimated proved developed and undeveloped reserves. The Partnership's DD&A for the three months ended June 30, 2025 and 2024 was $4.4 million in both periods, and DD&A per BOE of production was $26.27 and $24.93, respectively. The Partnership's DD&A for the six months ended June 30, 2025 and 2024 was $8.1 million and $8.5 million, respectively, and DD&A per BOE of production was $25.10 and $23.52, 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 approximately $122,000 and $41,000, respectively. Interest expense, net for the six months ended June 30, 2025 and 2024 was approximately $238,000 and $36,000, respectively. The primary component of interest expense is interest expense on the Credit Facility.

Supplemental Non-GAAP Measure

The Partnership uses "Adjusted EBITDAX", defined as earnings (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 an alternative 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 term exactly as the Partnership defines such term, 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 loss 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 loss		$	(2,345,352	)		$	(1,427,564	)		$	(3,435,946	)		$	(2,541,031	)
Interest expense, net			122,119				41,053				237,733				36,364
Depreciation, depletion, amortization and accretion			4,350,181				4,350,248				8,126,382				8,464,510
Exploration expenses			-				-				-				-
Adjusted EBITDAX		$	2,126,948			$	2,963,737			$	4,928,169			$	5,959,843

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 I, Item 1 of this Form 10-Q.

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. As of August 1, 2025, the Partnership had approximately $0.6 million in cash on-hand. The Partnership generated approximately $5.6 million and $13.4 million in cash flow from operating activities for the six months ended June 30, 2025 and the year ended December 31, 2024, respectively. The Partnership has an outstanding balance on the Credit Facility of $6.4 million at June 30, 2025, leaving $3.6 million in availability under the Credit Facility.

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 I, Item 1 of this Form 10-Q, the Partnership was not in compliance with its debt service coverage ratio as defined within the Loan Agreement at December 31, 2024, March 31, 2025 and June 30, 2025. The Lender waived this covenant calculation for each of those quarters, and the Partnership was in compliance with its other covenants at June 30, 2025.

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 will now be a quarterly calculation starting with the quarter ended September 30, 2025, as opposed to a trailing 12-month calculation. 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 Managing Dealer, the Managing Dealer received a total of 6% in selling commissions and a marketing expense allowance based on gross proceeds of the common units sold. The Managing Dealer also has Dealer Manager Incentive Fees (defined below) where the Managing Dealer 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 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 (as defined in "Note 6. Capital Contribution and Partners' Equity" in Part 1, Item 1 of this Form 10-Q).

Distributions

For the three months ended June 30, 2025 and 2024, the Partnership paid distributions of $0.320541 per common unit, or $3.5 million, in both periods. For the six months ended June 30, 2025 and 2024, the Partnership paid distributions $0.641082 per common unit, or $7.1 million, in both periods.

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. Distributions to limited partners were suspended by the General Partner in July 2025; therefore, the Partnership will accumulate all unpaid distributions based on an annualized return of seven percent (7%), and all accumulated unpaid distributions are to be paid before final Payout occurs, as defined above.

Oil and Natural Gas Properties

The Partnership incurred approximately $1.4 million and $1.7 million in capital expenditures during the six months ended June 30, 2025 and 2024, respectively. The Partnership has two wells in various stages of the drilling and completion process, and the Partnership estimates its share of capital expenditures to finish these wells is less than $1 million. In addition to the estimated capital expenditures to fully fund the in-process wells, the Partnership anticipates that it may be obligated to invest up to an additional $20 to $30 million in drilling capital expenditures from 2025 through 2029 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 the remainder of 2025. Current estimated capital expenditures could be significantly different from amounts actually invested.

The Partnership expects to fund overhead costs and capital additions related to the drilling and completion of wells primarily from cash on hand, cash generated by its producing wells and/or availability under its revolving credit facility. 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.

Subsequent Events

In July 2025, the Board of Directors of the General Partner elected to suspend distributions to Partnership limited partners. The Partnership will accumulate unpaid distributions at an annualized return of seven percent (7%), and all accumulated distributions are required to be paid before final Payout occurs, as defined in the Partnership's limited partnership agreement.

The Partnership and its Lender entered into an amendment ("First Amendment") to the Loan Agreement, effective August 8, 2025 ("Effective Date"), that renewed and extended the Credit Facility for an additional year to March 1, 2027 ("Revised Maturity Date"). Key terms and conditions of the First Amendment include:

●

As of the Effective Date, the borrowing base of the Credit Facility was, and remains, $10,000,000.

●

The Partnership paid a loan renewal fee to the Lender associated with the First Amendment of $50,000.

●

The Debt Service Coverage Ratio has been amended to be a quarter-based calculation, as opposed to a trailing 12-month calculation that was previously in effect, and will be effective starting with the quarter ended September 30, 2025.

●

A negative covenant has been added that restricts the Partnership's ability to make future distributions to its limited partners if that said distribution would create an event of default under the Loan Agreement.

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