Quarterly Report for Quarter Ending September 30, 2026 (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 Iranian-Israeli-American and Russian-Ukrainian conflicts and/or other 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, 2025 (the "2025 Form 10-K") 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 or 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 (this "Form 10-Q"), as well as the information contained in the 2025 Form 10-K.

Overview

Energy Resources 12, L.P. (together with its wholly-owned subsidiary, 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 September 30, 2026, the Partnership's ownership of the Bakken Assets consisted of an approximate 5% non-operated working interest in 454 producing wells and additional possible future development locations.

The Bakken Assets are operated by several third-party operators on behalf of working interest owners like the Partnership.

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 WTI oil prices averaged in the mid $60s per barrel, oil prices declined throughout 2025, with the average spot price decreasing from approximately $79 per barrel in January 2025 to approximately $59 per barrel in December 2025. Oil prices increased modestly through February 2026, then 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 and contributing to rapid increases in market oil prices. Average WTI spot prices increased to approximately $91 per barrel in March 2026 and continued to increase in April and May, averaging at or above $100 per barrel each month. Oil prices subsequently declined in June 2026, and into July 2026, as expectations of a resolution between the United States and Iran contributed to increased shipping traffic through the Strait of Hormuz, which eased concerns of disrupted oil production and trade flows. However, renewed military activity, attacks on oil tankers and key oil infrastructure, and restrictions of Iranian oil exports led to renewed strains on the global oil supply during the third quarter. Average WTI oil prices exceeded $97 per barrel in September 2026 and further increased to $110 per barrel on October 19, 2026.

Natural gas prices experienced a seasonal increase during the first quarter of 2026. Specifically, bitter cold temperatures persisted throughout the United States in January 2026, contributing to monthly average Henry Hub spot prices exceeding $7.50 per MMBtu. Since mid-February 2026, natural gas prices have declined to a more consistent level of approximately $3.00 per MMBtu due to improved weather conditions and the recovery of production and storage levels.

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 nine months ended September 30, 2026 and 2025.

		Three Months Ended September 30,								Percent				Nine Months Ended September 30,								Percent
		2026				2025				Change				2026				2025				Change
Average market closing prices (1)
Oil (per Bbl)		$	87.12			$	65.78				32.4	%		$	85.25			$	67.31				26.7	%
Natural gas (per Mcf)		$	2.87			$	3.03				-5.3	%		$	3.49			$	3.45				1.2	%

(1)	Based on average NYMEX WTI and Henry Hub daily spot prices reported by the EIA.

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 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 nine months ended September 30, 2026 and 2025.

		Three Months Ended September 30,																				Nine Months Ended September 30,
		2026				Percent of Revenue				2025				Percent of Revenue				Percent Change				2026				Percent of Revenue				2025				Percent of Revenue				Percent Change
Total revenues		$	8,927,553				100.0	%		$	6,009,983				100.0	%			48.5	%		$	22,152,350				100.0	%		$	20,289,153				100.0	%			9.2	%
Production expenses			3,352,223				37.5	%			3,389,088				56.4	%			-1.1	%			10,228,685				46.2	%			10,534,691				51.9	%			-2.9	%
Production taxes			681,122				7.6	%			407,333				6.8	%			67.2	%			1,574,897				7.1	%			1,436,065				7.1	%			9.7	%
Depreciation, depletion, amortization and accretion			3,332,533				37.3	%			4,320,609				71.9	%			-22.9	%			8,758,108				39.5	%			12,446,991				61.3	%			-29.6	%
General and administrative expenses			563,043				6.3	%			498,651				8.3	%			12.9	%			1,673,156				7.6	%			1,675,317				8.3	%			-0.1	%
Sold production (BOE):
Oil			87,348								77,384								12.9	%			212,809								253,926								-16.2	%
Natural gas			34,335								42,514								-19.2	%			103,651								120,071								-13.7	%
Natural gas liquids			31,236								39,044								-20.0	%			93,589								108,680								-13.9	%
Total			152,919								158,942								-3.8	%			410,049								482,677								-15.0	%
Average sales price per unit:
Oil (per Bbl)		$	90.18							$	64.13								40.6	%		$	86.17							$	65.08								32.4	%
Natural gas (per Mcf)			2.00								1.58								26.6	%			3.03								2.33								30.0	%
Natural gas liquids (per Bbl)			20.45								16.49								24.0	%			20.65								19.15								7.8	%
Combined (per BOE)			58.38								37.81								54.4	%			54.02								42.03								28.5	%
Average unit cost per BOE:
Production expenses			21.92								21.32								2.8	%			24.95								21.83								14.3	%
Production taxes			4.45								2.56								73.8	%			3.84								2.98								28.9	%
Depreciation, depletion, amortization and accretion			21.79								27.18								-19.8	%			21.36								25.79								-17.2	%
Capital expenditures		$	2,993,690							$	143,960											$	6,144,507							$	1,574,461

Oil, natural gas and NGL revenues

For the three months ended September 30, 2026, revenues for oil, natural gas and NGL sales were $8.9 million. Revenues for the sale of crude oil were $7.9 million, which resulted in a realized price of $90.18 per Bbl. Revenues for the sale of natural gas were $0.4 million, which resulted in a realized price of $2.00 per Mcf. Revenues for the sale of NGLs were approximately $0.6 million, which resulted in a realized price of $20.45 per Bbl. For the three months ended September 30, 2025, revenues for oil, natural gas and NGL sales were $6.0 million. Revenues for the sale of crude oil were $5.0 million, which resulted in a realized price of $64.13 per Bbl. Revenues for the sale of natural gas were $0.4 million, which resulted in a realized price of $1.58 per Mcf. Revenues for the sale of NGLs were approximately $0.6 million, which resulted in a realized price of $16.49 per Bbl.

For the nine months ended September 30, 2026, revenues for oil, natural gas and NGL sales were $22.2 million. Revenues for the sale of crude oil were $18.3 million, which resulted in a realized price of $86.17 per Bbl. Revenues for the sale of natural gas were $1.9 million, which resulted in a realized price of $3.03 per Mcf. Revenues for the sale of NGLs were approximately $1.9 million, which resulted in a realized price of $20.65 per Bbl. For the nine months ended September 30, 2025, revenues for oil, natural gas and NGL sales were $20.3 million. Revenues for the sale of crude oil were $16.5 million, which resulted in a realized price of $65.08 per Bbl. Revenues for the sale of natural gas were $1.7 million, which resulted in a realized price of $2.33 per Mcf. Revenues for the sale of NGLs were approximately $2.1 million, which resulted in a realized price of $19.15 per Bbl.

Through July 2026, the Partnership's sold production volumes had been negatively impacted by the natural decline of aging wells, with sold production for the Bakken Assets totaling approximately 1,300 BOE per day in July. Six new wells were completed and turned to sales at the beginning of September 2026, increasing the Partnership's daily production to approximately 2,300 BOE per day for the month. Production volumes per day fluctuate due to the timing of well completions; new wells often have high levels of production immediately following completion, so the Partnership anticipates a boost in sold production volumes in the fourth quarter of 2026 and into 2027. The Partnership's sold production for the three and nine months ended September 30, 2026 was approximately 1,700 BOE per day and 1,500 BOE per day, respectively. The Partnership's sold production for the Bakken Assets for the three and nine months ended September 30, 2025 was approximately 1,700 BOE per day and 1,800 BOE per day, respectively.

As noted above, the geopolitical unrest in the Middle East and the related impacts to transportation routes and global supplies have directly contributed to higher market prices for oil throughout 2026, in comparison to 2025. The higher oil market prices correspondingly led to increased realized sales prices for the Partnership's sold production, which helped to offset the natural decline in well production during the three and nine months ended September 30, 2026. The Partnership's natural gas differentials have marginally improved in 2026, compared to 2025, which has contributed to higher realized sales prices for the three and nine months ended September 30, 2026.

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 oil price differentials during 2026 have improved significantly due to favorable local market sales prices compared to the industry benchmarks; lower differentials to benchmarks 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 and/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 September 30, 2026 and 2025 were $3.4 million in both periods, and production expenses per BOE were $21.92 and $21.32, respectively. Production expenses for the nine months ended September 30, 2026 and 2025 were $10.2 million and $10.5 million, and production expenses per BOE were $24.95 and $21.83, respectively. Production expenses per BOE of sold production have increased in 2026 primarily as a result of 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 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 September 30, 2026 and 2025 were $0.7 million (7.6% of revenue) and $0.4 million (6.8% of revenue), respectively. Production taxes for the nine months ended September 30, 2026 and 2025 were $1.6 million (7.1% of revenue) and $1.4 million (7.1% of revenue), respectively. Oil production comprised approximately 57% and 52% of the Partnership's sold production volumes in the three and nine months ended September 30, 2026, respectively, compared to 49% and 53% for the three and nine months ended September 30, 2025.

General and administrative expenses

The principal components of general and administrative expense are accounting, legal, advisory and consulting fees along with insurance and reporting expenses. General and administrative costs for the three months ended September 30, 2026 and 2025 were $0.6 million and $0.5 million, respectively. General and administrative costs for the nine months ended September 30, 2026 and 2025 were $1.7 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 September 30, 2026 and 2025 was $3.3 million and $4.3 million, respectively, and DD&A per BOE of production was $21.79 and $27.18, respectively. The Partnership's DD&A for the nine months ended September 30, 2026 and 2025 was $8.8 million and $12.4 million, respectively, and DD&A per BOE of production was $21.36 and $25.79, respectively. An increase in proved undeveloped reserves resulting from adjustments to the future drill schedule (see new wells discussed below under Oil and Natural Gas Properties) made in the December 31, 2025 reserve analysis reduced the depletion rate (starting in the fourth quarter of 2025) and thus resulted in a decrease in DD&A expense per BOE for the three and nine months ended September 30, 2026, compared to the same periods of 2025.

Loss on derivatives

Participation in the oil and natural gas industry exposes the Partnership to risks associated with potentially volatile changes in energy commodity prices, and therefore, the Partnership's future earnings are subject to these risks. Therefore, the Partnership periodically utilizes derivative contracts to manage the commodity price risk on the Partnership's future production it will produce and sell and to reduce the effect of volatility in commodity price changes to provide a base level of cash flow from operations. 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. The Partnership generally uses costless collar derivative contracts, which establish floor and ceiling prices on future anticipated production.

The Partnership did not designate its derivative instruments as hedges for accounting purposes and did not enter into such instruments for speculative trading purposes. As a result, when derivatives do not qualify or are not designated as a hedge, the changes in the fair value are recognized on the Partnership's consolidated statements of operations as a gain or loss on derivative instruments. The following table presents the settlement losses of matured derivative instruments and non-cash mark-to-market losses for the periods presented.

		Three Months Ended September 30, 2026				Nine Months Ended September 30, 2026
Settlement loss on matured derivatives		$	(13,370	)		$	(92,110	)
Loss on mark-to-market of derivatives			(549,716	)			(64,504	)
Loss on derivatives		$	(563,086	)		$	(156,614	)

The Partnership's oil production contracts that expired during the three months ended September 30, 2026 represented approximately 30,000 barrels of oil. The Partnership realized a loss of approximately $13,000 on the settlement of those contracts, equating to an approximate loss of $0.45 per barrel, on its hedged oil production, and an approximate loss of $0.15 per barrel of total sold oil production for the third quarter of 2026. The Partnership's oil production contracts that expired during the nine months ended September 30, 2026 represented approximately 60,000 barrels of oil. The Partnership realized a loss of approximately $92,000 on the settlement of those contracts, equating to an approximate loss of $1.54 per barrel, on its hedged oil production, and an approximate loss of $0.43 per barrel of total sold year-to-date oil production for 2026.

The mark-to-market (non-cash, unrealized) loss recorded for the three and nine months ended September 30, 2026 represents the change in fair value of the Partnership's derivative instruments held at period-end. Unrealized gains and losses do not represent actual settlements or payments made to or from the counterparty.

The table below summarizes the Partnership's outstanding derivative contracts (costless collars - purchased put options and written call options) on the Partnership's future oil production.

Interest expense, net

Interest expense, net for the three months ended September 30, 2026 and 2025 was approximately $124,000 and $146,000, respectively. Interest expense, net for the nine months ended September 30, 2026 and 2025 was approximately $374,000 and $384,000, respectively. The primary components of Interest expense, net include interest expense on the outstanding balance of the Credit Facility, amortized loan costs and non-use fees.

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; (iv) exploration expenses; and (v) (gain)/loss on the mark-to-market of derivative instruments, 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 income (loss) to Adjusted EBITDAX for the three and nine months ended September 30, 2026 and 2025.

		Three Months Ended September 30, 2026				Three Months Ended September 30, 2025				Nine Months Ended September 30, 2026				Nine Months Ended September 30, 2025
Net income (loss)		$	311,318			$	(2,751,496	)		$	(612,718	)		$	(6,187,442	)
Interest expense, net			124,228				145,798				373,608				383,531
Depreciation, depletion, amortization and accretion			3,332,533				4,320,609				8,758,108				12,446,991
Exploration expenses			-				-				-				-
Non-cash loss on mark-to-market of derivatives			549,716				-				64,504				-
Adjusted EBITDAX		$	4,317,795			$	1,714,911			$	8,583,502			$	6,643,080

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 9. 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. After making capital payments on the six wells recently completed, the Partnership had approximately $0.7 million in cash on hand as of November 1, 2026. The Partnership generated approximately $5.9 million and $8.1 million in net cash flow from operating activities for the nine months ended September 30, 2026 and the year ended December 31, 2025, respectively. The Partnership has approximately $4.2 million in availability under the Credit Facility at September 30, 2026 and as of the filing date of this Form 10-Q. In November 2026, the Partnership and its lender amended the Loan Agreement that renewed and extended the Credit Facility for two additional years to March 1, 2029.

The Partnership anticipates that cash on hand, cash flow from operations and 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.

The Partnership was in compliance with its financial covenants at September 30, 2026. 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 8. Capital Contribution and Partners' Equity" in Part I, Item 1 of this Form 10-Q).

Distributions

See the definition and discussion of "Payout" in Note 8. Capital Contribution and Partners' Equity in Part I, Item 1 of this Form 10-Q.

Under the amended Loan Agreement discussed in Note 4. Debt in Part I, Item 1 of this Form 10-Q, 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 suspended 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 September 30, 2026, the unpaid Payout Accrual, for the period from July 2025 to September 2026, totaled approximately $1.62 per common unit, or approximately $18 million.

For the nine months ended September 30, 2025, the Partnership paid distributions of $0.641082 per common unit, or $7.1 million.

Oil and Natural Gas Properties

The Partnership incurred approximately $6.1 million and $1.6 million in capital expenditures during the nine months ended September 30, 2026 and 2025, respectively. 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 during the third quarter of 2026, six wells were completed and turned to sales. Approximately $7.7 million in capital costs had been incurred as of September 30, 2026. The Partnership anticipates its operators will complete the other six wells during the fourth quarter, and the remainder of completion capital costs are estimated to be incurred through the first quarter of 2027. In addition to the estimated capital expenditures to fully fund the in-process and recently-elected wells, the Partnership anticipates that it may be obligated to invest up to an additional $20 to $30 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 the remainder of 2026 and into 2027. 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.

Critical Accounting Estimates

There have been no material changes to the Partnership's critical accounting estimates from those disclosed in Item 7, "Management's Discussion and Analysis of Financial Condition and Results of Operations," of the 2025 Form 10-K.

Subsequent Events

In November 2026, the Partnership and its lender entered into the third amendment to the Loan Agreement that renewed and extended the Credit Facility for two additional years to March 1, 2029. The borrowing base of the Credit Facility remains $10 million, and the Partnership paid a renewal fee to the Lender of $50,000.