The Bakken-focused partnership’s financial strain led to covenant waivers, new hedging arrangements, and a halt to investor payouts in 2025.

March 26, 2026

Energy Resources 12, L.P., a Delaware limited partnership holding non-operated working interests in the Bakken shale formation of North Dakota, reported a sharply worse financial performance for fiscal year 2025, with revenues declining nearly 28%, net losses widening, and the partnership suspending distributions to its limited partners midway through the year.

The results stand in contrast to the partnership’s sister entity, Energy 11, L.P., which reported a revenue decline of about 23% and net income of roughly $8.9 million for the same period. Energy Resources 12’s challenges appear more pronounced, reflecting its smaller scale, higher relative cost structure, and growing reliance on debt financing.

Revenue and Production Under Pressure

Total revenues for 2025 fell to approximately $26.1 million, down from $36.1 million in 2024 — a decline of 27.8%. The drop was driven by both lower commodity prices and reduced production volumes. Total sold production declined 15.3% to roughly 639,000 barrels of oil equivalent, with oil volumes falling 21.9% to about 329,000 barrels. Natural gas and natural gas liquids volumes also declined, falling 8.4% and 5.4%, respectively.

Average realized oil prices dropped 13.2% to $64.25 per barrel, while NGL prices fell 16.0% to $18.01 per BOE. Natural gas was the lone bright spot, with realized prices jumping 60% to $2.32 per Mcf, driven by tighter domestic supply and stronger LNG exports. However, natural gas revenues represented only a small fraction of the Partnership’s total income and were insufficient to offset the steep decline in oil revenue.

The Partnership attributed the production decline primarily to the natural aging of existing wells. While 20 new wells were turned to sales during 2024, only 5 wells were completed in 2025, limiting the offset to natural decline rates. Daily sold production for the Bakken Assets averaged approximately 1,800 BOE per day for the full year and just 1,700 BOE per day in the fourth quarter.

Widening Losses and Cost Challenges

The Partnership recorded a net loss of approximately $8.4 million for 2025, compared to a net loss of roughly $4.8 million in 2024. On a per-unit basis, the loss widened to $0.76 from $0.43.

While production expenses declined in absolute terms to $14.3 million from $17.7 million, they remained elevated on a per-BOE basis at $22.38, only modestly below the prior year’s $23.41. Production expenses as a percentage of revenue rose sharply to 54.9% from 48.9%, reflecting the difficulty of covering fixed costs with shrinking production volumes.

Depreciation, depletion, amortization and accretion totaled $15.7 million, down from $17.8 million, but the per-BOE rate increased to $24.53 from $23.61 as the depletion base was impacted by reserve adjustments. General and administrative expenses held essentially flat at approximately $2.2 million, which includes an annual management fee of roughly $1.1 million paid to the General Partner. Interest expense nearly doubled to approximately $511,000 from $259,000, reflecting higher utilization of the Partnership’s revolving credit facility.

Distributions Suspended, Covenant Issues Addressed

In July 2025, the General Partner elected to suspend distributions to limited partners. Prior to the suspension, the Partnership had paid $0.641082 per common unit during 2025, compared to $1.282163 per unit in 2024. As of December 31, 2025, the unpaid Payout Accrual — distributions that accumulate at a 7% annual rate — totaled approximately $0.66 per common unit, or about $7.3 million.

The distribution suspension was tied to covenant compliance issues under the Partnership’s credit facility with BancFirst. The Partnership was not in compliance with its debt service coverage ratio at December 31, 2024, March 31, 2025, and June 30, 2025. The lender waived those covenant calculations, and in August 2025 the parties amended the loan agreement to extend the facility to March 2027 and revise the coverage ratio to a quarterly calculation rather than a trailing 12-month basis. Under the amended terms, distributions are not permitted if paying them would create a default. The Partnership returned to covenant compliance for the third and fourth quarters of 2025.

At year-end, the outstanding balance on the credit facility stood at $5.8 million, up from $4.6 million at the end of 2024, with approximately $4.2 million of additional availability. The interest rate was 7.25%.

New Drilling and Hedging Initiatives

Despite its financial pressures, the Partnership committed to new development activity. In late 2025, it elected to participate in 12 new wells, including six in which it holds an average working interest of approximately 14%. The Partnership’s share of estimated capital expenditures for these wells is roughly $9 million, with about $1.5 million incurred by year-end and the remainder expected through mid-2026. Management anticipates the wells will be completed in the first half of 2026 and provide a boost to production volumes.

Looking further ahead, the Partnership estimates it may need to invest up to $40 million from 2026 through 2030 to participate in development programs without triggering non-consent penalties under its joint operating agreements.

In March 2026, the Partnership entered into costless collar derivative contracts covering 90,000 barrels of oil for the period from April through December 2026, with floor and ceiling prices of $75.00 and $94.35 per barrel, respectively. This hedging activity was prompted by a new amendment to the loan agreement that implemented a risk management program requiring hedging at certain credit facility utilization thresholds.

Reserves and Valuation

Total proved reserves stood at approximately 8.8 million BOE as of December 31, 2025, relatively stable compared to 8.7 million BOE at year-end 2024. Proved undeveloped reserves increased to about 4.9 million BOE, representing roughly 56% of total proved reserves, driven by positive revisions from changes in the future drill schedule.

The standardized measure of discounted future net cash flows declined to approximately $61.4 million from $80.8 million, reflecting the impact of lower commodity prices on projected cash flows. The estimated per-unit fair value was $8.26, based on a valuation range of $7.08 to $9.52 per common unit.

Outlook

Energy Resources 12 faces a challenging environment of declining production, depressed oil prices, and constrained liquidity. Cash flow from operations fell to approximately $8.1 million from $13.4 million, while the Partnership ended the year with just $1.5 million in cash. Management indicated it believes available resources are adequate for the next 12 months but acknowledged that sustained low prices or inability to replenish production could further stress the Partnership’s financial position.

The Partnership continues to be managed by Energy Resources 12 GP, LLC, controlled by CEO Glade M. Knight and CFO David S. McKenney, who also lead the General Partner of the affiliated Energy 11 partnership. Energy Resources 12 has no employees, approximately 11 million common units outstanding held by roughly 3,600 limited partners, and no public trading market for its units.