Mach Natural Resources LP (MNR) Earnings

Management highlights

### Core Strategic Pillars - Disciplined execution: Only acquires cash-flowing assets at a PDP PV10 ratio of 1 or lower, and does not pay a premium for leasehold, PUDs, midstream assets, or infrastructure. - Disciplined reinvestment: Maintains a reinvestment rate of less than 50% of operating cash flow, with quarter-to-quarter flexibility to adjust capex based on realized cash flow and commodity prices. - Maintain financial strength: Current projected year-end 2026 leverage is 1.4x debt/EBITDA, above the long-term target of 1.0x. The company is committed to returning to the 1.0x target by the end of 2027 via multiple avenues: accretive equity-financed asset purchases, the existing $100 million at-the-market equity program, and potential partial distribution cuts to fund debt paydown. - Maximize distributions to unit holders: All business decisions are driven by this priority. The company has returned $6.67 per unit to holders since 2024, with a 15% distribution yield (four times the peer average) that is supported by operational discipline, not excessive leverage. ### Acquisition and Asset Portfolio Updates - The company has built a portfolio of nearly 3 million acres held by production, with a 50+ year expected cash flow stream, acquired via value-focused purchases including the high-return 2020 Alta Mesa bankruptcy acquisition. As capital has chased MidCon assets, the company expanded into the San Juan Basin and Permian's Central Basin Platform, acquiring Sabinol's oil assets at ~$62 per barrel and ICAV's natural gas assets at below PDP PV10, both with less than 10% base decline and substantial remaining drilling inventory. - The company maintains a flexible drilling program, able to pivot quickly between oil and natural gas focused activity based on commodity prices. Post the Iran conflict, it shifted from 100% natural gas drilling to crude-heavy drilling to capitalize on higher relative returns. ### Key Play Highlights - **Oswego Limestone (Oklahoma):** The current capex workhorse, with more than 250 wells drilled since 2021, an 87% rate of return at $75/bbl oil, and low well costs of $3.3 million for ~160,000 barrels of oil recoverable per well. One rig will operate here consistently through 2027. - **Mancos Shale (San Juan Basin):** A high-potential emerging natural gas play where Mock is the second largest acreage owner and producer. The play currently produces over 500 million cubic feet of gas per day, with well performance that rivals the Haynesville and Marcellus, existing mature pipeline infrastructure, and upcoming additional takeaway capacity to premium West Coast and LNG markets. Well costs have been reduced from ~$20 million to ~$13 million per completed 3-mile lateral, and only 5 net wells per year are required to maintain current production flat, with upside to grow to over 500 million cubic feet per day at 10 wells per year. - 2026 drilling activity: Completion of Mancos wells is deferred to 2027 to stay under the 50% capex target; three rigs are active in Oklahoma, with Ardmore Basin wells to be completed by Q3 2026 end, and Red Fork drilling deferred to Q1 2027.

Guidance

- The company maintains it will hit the 1.0x debt/EBITDA leverage target by the end of 2027, down from the projected 1.4x at the end of 2026. - Full-year 2026 development capex is expected to remain at ~50% of full-year operating cash flow, consistent with the company's core strategic target, with limited quarter-to-quarter lumpiness expected. - 2027 overall production is expected to remain flat, as the 50% reinvestment rate is targeted to maintain base production rather than deliver material growth. A gradual shift from oil-focused activity to natural gas activity is expected starting in the second half of 2027 if natural gas prices rebound as expected, with no final 2027 capex program finalized as of Q2 2026. - No formal commodity or production guidance is provided for 2027 given the company's flexible, price-driven operational model.

Segment performance

Total Q2 2026 oil and gas revenues reached $360 million. Production for the quarter was 149,000 BOE per day, broken out as 15% oil, 69% natural gas, and 16% NGLs. Revenue contribution by product segment is as follows: Oil contributed 54% of total oil and gas revenue, with an average realized price of $95.40 per barrel. Natural gas contributed 30% of total oil and gas revenue, with an average realized price of $1.93 per mcf. NGLs contributed 16% of total oil and gas revenue, with an average realized price of $28.99 per barrel. Total company revenues including hedges and midstream activities hit $406 million, with adjusted EBITDA of $182 million, operating cash flow of $154 million, and development capex of $97 million. Year-to-date development capex has held at 50% of year-to-date operating cash flow, meeting the company's target. Cash available for distribution was $60 million, resulting in a 36 cent per unit distribution.

Risks & headwinds

- Near-term natural gas prices and San Juan Basin basis risk: Current weak natural gas prices have justified delaying Mancos Shale capex, and San Juan basis is currently 20 cents below hub prices, creating near-term uncertainty for natural gas project returns. While long-term demand growth is expected, a strong El Nino winter could keep prices depressed in the near term. - Competition for discounted assets: Increased capital flows from private equity and other institutions have made it harder to acquire distressed cash-flowing assets at the discounted prices the company's model relies on, reducing near-term acquisition opportunities. - Leverage risk: Current leverage is above the company's target 1.0x debt/EBITDA, leaving less balance sheet capacity to acquire assets during future market downturns, which is a core part of the company's long-term strategy. - Operational flexibility creates forecasting uncertainty: The company's ability to quickly shift drilling focus between assets and commodities makes it hard for investors to model future capex and production, as plans can change monthly based on commodity prices.

Analyst Q&A

• Q: The analyst asks to confirm near-term drilling focus is on the Oswego, requests details on activity levels and Oswego economics, and asks how it competes with other well-known oily plays. /

  A: Management confirms Oswego is the ongoing near-term focus, with one rig to operate there consistently through 2027. Only three remaining high-return Sycamore locations will be completed by Q3 2026, with Red Fork drilling deferred to 2027 depending on prices. The Oswego delivers an 85% rate of return at $75 oil, so it competes very effectively with other major oily plays.

• Q: The analyst asks what natural gas price is needed to trigger Mancos completion activity, and asks about the opportunity for the new BMW play in the Central Basin Platform near Mock's acreage. /

  A: Management notes that to compete with current oil-focused returns, natural gas prices need to rebound, which is not expected before next summer at the earliest, with long-term natural gas demand expected to outpace supply. Management states it is not aware of the BMW play near its acreage, and has no plans to pursue frontier exploration activity that fits this play.

• Q: The analyst asks whether management will change existing plans (such as cutting distributions) to accelerate deleveraging to reach the 1.0x target faster, and asks about the Clear Fork drilling opportunity. /

  A: Management confirms that deleveraging to 1.0x by the end of 2027 remains a top priority. The ATM program and potential distribution cuts are available tools, but there are currently few attractive acquisitions that can be bought with equity to reduce leverage organically. Clear Fork has 7 potential horizontal locations within an existing water flood with a 53% rate of return, which is lower than the Oswego's 80%+ return, so drilling is deferred to 2027 and will only proceed if operating cash flow is sufficient to stay under the 50% reinvestment cap.

• Q: The analyst asks what is driving the large 35% reduction in Mancos Shale well costs, and whether oil production will grow in 2027 if the current oil-focused drilling program continues. /

  A: Management explains that cost reductions come from optimized drilling and completion design (lower frac sand volumes, wet sand instead of dry sand, improved drilling techniques that reduce rig days, and new vendor contracts), with larger savings coming from completion costs. Overall 2027 production is expected to remain flat, as the 50% reinvestment rate is structured to maintain base production rather than deliver material net growth.

• Q: The analyst asks if management is considering asset sales, farmouts, or carries to accelerate deleveraging given current leverage is above target. /

  A: Management declines to pursue non-core asset sales, noting that nearly all of the company's current high-return plays were acquired as non-core acreage from prior owners, and selling acreage would risk giving up future high-return opportunities. Management prefers cutting distributions slightly if needed to accelerate deleveraging, as this is more efficient than selling cash-flowing assets.