Mach Natural Resources LP Q2 FY2024 earnings call

Key Pillars - Maintain financial strength: Aim for long-term debt-to-EBITDA ratio of 1 times or less. - Disciplined execution: Acquire cash flowing assets at a discount to PDP PV-10 that are accretive to distribution. - Disciplined reinvestment rate: Maintain reinvestment rate of less than 50% of operating cash flow. - Maximize cash distributions: Target peer-leading distributions. ### Second Quarter Results - Averaged 89.3 MBOE per day of production, exceeding high end of guidance. - Drilling program performing in line with estimates. - Achieved successful expense and cost control; lease operating expenses of $5.72 per barrel of oil equivalent were below low end of guidance. - Divested $38 million of Western Anadarko acreage. - Used $21 million of cash to pay down existing debt. - Declared a quarterly cash distribution of $0.90 per unit. - Drilling program has 2 rigs running; adjusted CapEx guidance down by 15% due to reducing Oswego rig count. - Adjusted lease operating expense guidance down by 3% per BOE. - Improved drilling efficiencies with lower costs per well, e.g., deeper condensate window wells cost $7.6 million per well vs. projected $8.6 million, and Oswego total cycle time per well reduced to 10.1 days at $2.6 million per location. - Extended average lateral length from 5,400 feet to 6,000 feet, lowering overall cost by $32 per lateral foot. - Plan to expand to other basins outside the Mid-Con as it has become highly sought after.

In the second quarter, Mach averaged 89.3 MBOE per day of production. Production composition was 23% oil, 53% natural gas, and 24% NGLs. Total oil and gas revenues were $232 million. The revenue contribution was 65% from oil, 15% from gas, and 20% from NGLs.

CapEx - Reduced CapEx guidance by 15% due to reducing the Oswego rig count. ### Operating Expenses - Adjusted lease operating expense guidance down by 3% per BOE. ### Drilling - Expected drilling cadence of 12 gross wells and 14 gross operated wells in line with second quarter performance. - Drilling costs improved with efficiencies, e.g., deeper wells in condensate window cost $7.6 million per well vs. initial projection of $8.6 million. - Oswego total cycle time per well reduced to 10.1 days at $2.6 million per location.

Factors - Market volatility could impact actual results vs. forward-looking statements. - Project execution risks, such as delays in well completions or higher-than-expected costs.

Q: Charles Meade asked about dropping the rig in the Oswego.

A: Tom Ward said it was to stay under 50% CapEx to operating cash flow.

Q: John Freeman asked about divestiture and gas flexibility.

A: Tom Ward said they have a large acreage position and are rate-of-return driven, watching wells in proven areas and looking to increase operating cash flow.

Q: Michael Scialla asked about guidance change.

A: Kevin White said it was due to activity level changes, including a rig late in the first quarter in the Oswego and delays in deeper wells.

Q: Michael Scialla asked about outside basin opportunities.

A: Tom Ward said they are looking for cash flowing assets at a discount to PDP PV-10, considering areas like second-tier Eagle Ford, Permian, or California (due to regulatory environment).

Q: Geoff Jay asked about refracs.

A: Tom Ward said he has had no luck with refracs on their acreage.

Q: Unidentified Analyst asked about 2025-2026 competition.

A: Tom Ward said consolidation could lead to opportunities in back-end areas as others zag, and they aim to zig into those areas.