Mideast conflict pushed oil above $100 per barrel in March, but lower volumes and a continued distribution suspension weighed on the Bakken partnership.

May 13, 2026

Energy Resources 12, L.P., a Delaware limited partnership with non-operated working interests in North Dakota’s Bakken shale formation, reported a wider net loss for the first quarter of 2026 as production declines outpaced the benefits of a sharp late-quarter spike in oil prices triggered by escalating Middle East conflict.

The Partnership posted a net loss of approximately $1.4 million for the three months ended March 31, 2026, compared to a loss of $1.1 million in the same period of 2025. Total revenues fell 23.3% to $6.0 million from $7.9 million, even as average realized oil prices ticked higher. The results extend a difficult stretch for the Partnership, which suspended distributions to limited partners in July 2025 and posted a wider full-year loss in 2025 amid covenant compliance challenges.

Production Declines Continue to Pressure Results

Total sold production fell 19.5% year over year to roughly 127,000 barrels of oil equivalent. Oil volumes, which represent the largest share of revenue, declined 30.9% to about 63,500 barrels. Natural gas and natural gas liquids production dropped 5.4% and 2.0%, respectively. The Partnership attributed the production decline primarily to natural decline of aging wells, with daily sold production averaging approximately 1,400 BOE compared to 1,800 BOE in the year-ago quarter.

Management indicated production is expected to rebound in the second half of 2026 as 12 new wells currently in various stages of drilling and completion are turned to sales. The Partnership elected to participate in these wells during October and November 2025, with its share of estimated capital expenditures totaling approximately $9 million. About $3.0 million in capital costs had been incurred by quarter-end, and operators are expected to complete the wells in the second quarter with production beginning in the third quarter.

Geopolitical Tensions Drive Oil Price Surge

While average realized oil prices rose only modestly to $70.27 per barrel from $68.83 in the prior-year quarter, the late-quarter price environment shifted dramatically. Oil prices opened 2026 near $60 per barrel and moved up modestly through February. However, escalation of military conflict involving the United States, Israel, and Iran in late February and early March 2026 sent prices soaring, with average market prices exceeding $90 per barrel in March and closing prices topping $100 per barrel on March 30 — the highest level since July 2022.

As a result, the Partnership realized oil sales at nearly $90 per barrel during March alone. Management noted that elevated prices have continued into the second quarter, helping offset natural production declines. The Partnership also benefited from improved oil price differentials, which strengthened by approximately $1.00 per barrel compared to the prior-year quarter.

Natural gas prices also climbed sharply, benefiting from a bitter cold winter that pushed monthly average market prices above $7.50 per MMBtu in January 2026. The Partnership’s realized natural gas price jumped 53.0% to $5.60 per Mcf from $3.66 in the prior-year period, boosting natural gas revenue to $1.1 million from $0.8 million.

NGL prices moved in the opposite direction, declining 41.2% to $14.79 per BOE, which reduced NGL revenue to roughly $0.4 million from $0.8 million.

Cost Pressures and Operating Metrics

While absolute production expenses fell to $3.5 million from $3.9 million, they rose sharply on a per-BOE basis to $27.89 from $24.50 — an increase of 13.8% — reflecting the difficulty of spreading fixed operating costs over a smaller production base. Production expenses as a percentage of revenue rose to 58.8% from 49.2%, illustrating the margin pressure created by declining volumes.

Depreciation, depletion, amortization and accretion totaled $2.7 million, down from $3.8 million, with per-BOE rates declining 10.2% to $21.44. The lower DD&A rate reflected an increase in proved undeveloped reserves recognized in the December 31, 2025 reserve analysis, which reduced the depletion rate starting in the fourth quarter of 2025.

Production taxes fell to $0.4 million from $0.6 million, reflecting both lower revenue and a shift in product mix, as oil production accounted for approximately 50% of total volumes compared to 58% in the year-ago quarter.

General and administrative expenses held steady at approximately $0.6 million, including the quarterly management fee of roughly $273,000 paid to the General Partner.

Adjusted EBITDAX, a non-GAAP measure, fell to $1.5 million from $2.8 million.

Hedging Program Implemented

In March 2026, the Partnership entered into costless collar derivative contracts covering a portion of its expected oil production. The contracts cover 90,000 barrels of oil for the period from April through December 2026, with a floor price of $75.00 and a ceiling price of $94.35 per barrel. The contracts settle monthly and required no premium payment.

The hedging activity follows a March 2026 amendment to the Partnership’s credit facility that established a risk management framework. Under the amended terms, the Partnership is not required to hedge if its credit facility utilization remains at or below 20% of the Partnership’s PV-9 — the net present value of proved developed producing reserves discounted at 9% per annum. Higher utilization rates trigger mandatory hedging requirements of at least 50% of rolling 12-month or 24-month projected production. The Partnership reported it was not subject to mandatory hedging requirements as of quarter-end, meaning the March collar contracts were entered into at the Partnership’s discretion.

Credit Facility and Liquidity

The outstanding balance on the BancFirst credit facility remained at $5.8 million, with the interest rate at 7.25%. The facility was reclassified as a current liability due to its March 1, 2027 maturity date now falling within 12 months. The Partnership had approximately $4.2 million of remaining availability under the facility.

Cash on hand declined to $854,000 at quarter-end from $1.5 million at year-end 2025, and stood at approximately $600,000 as of May 1, 2026. Cash flow from operating activities was approximately $1.6 million for the quarter, down from $3.4 million in the prior-year period. The Partnership was in compliance with all financial covenants at March 31, 2026, after previously requiring waivers from its lender in early 2025.

Distribution Suspension Continues

The Partnership made no distributions to limited partners during the first quarter of 2026, continuing the suspension that began in July 2025. By comparison, the Partnership paid $0.32 per common unit, or approximately $3.5 million, during the first quarter of 2025.

The unpaid Payout Accrual — distributions that accumulate at a 7% annual rate and must be paid before final Payout occurs — totaled approximately $0.98 per common unit, or about $10.8 million in aggregate, covering the period from July 2025 through March 2026. Under the amended loan agreement, distributions are not permitted if they would create a default under the credit facility.

Outlook

Looking ahead, the Partnership expects production to receive a boost in the second half of 2026 as the 12 new wells come online. Management anticipates that an additional $20 to $30 million in drilling capital expenditures may be required from 2026 through 2030 to fully participate in development of the Bakken Assets without triggering non-consent penalties — a notably lower estimate than the $40 million figure cited in the Partnership’s 2025 annual report.

With approximately 11 million common units outstanding and no public trading market, Energy Resources 12 continues to be managed by Energy Resources 12 GP, LLC, controlled by Chief Executive Officer Glade M. Knight and Chief Financial Officer David S. McKenney.