Kimbell Royalty Partners, LP Q4 FY2025 earnings call

• Began 2025 with $230 million acquisition of mineral and royalty interests beneath a historic Navy ranch in the Midland Basin. - In second quarter, redeemed 50% of the Series A cumulative convertible preferred units. - Fourth quarter production grew organically from third quarter and exceeded guidance midpoint. - Declared Q4 2025 distribution of 37 cents per common unit, up 6% from Q3 2025. - Pre-developed reserves increased ~8% in 2025 to nearly 73 million VOE. - Active rig count strong with 85 rigs drilling, representing 16% market share of US land rigs. - Line of site wells above maintenance well count. - 2025 acquisition of mineral and royalty interests beneath a historic Navy ranch strengthened Permian Basin position. - In second quarter, redeemed 50% of Series A cumulative convertible preferred units to simplify capital structure. - Fourth quarter production growth and exceeded guidance midpoint. - Declared Q4 distribution of 37 cents per common unit, up 6% from Q3. - Full year 2025 return of $1.60 per common unit through distributions, all return of capital. - Pre-developed reserves increased 8% in 2025 to nearly 73 million VOE. - Active rig count at 85 rigs, 16% market share of US land rigs. - Line of site wells above maintenance well count. - 2025 acquisition of Navy ranch acreage in Midland Basin. - Second quarter redemption of 50% of Series A cumulative convertible preferred units. - Fourth quarter production growth and exceeded guidance midpoint. - Q4 distribution of 37 cents per common unit, up 6% from Q3. - Full year 2025 distribution of $1.60 per common unit, all return of capital. - Pre-developed reserves increased 8% in 2025 to nearly 73 million VOE. - Active rig count at 85 rigs, 16% market share of US land rigs. - Line of site wells above maintenance well count.

Fourth quarter oil, natural gas, and NGL revenues totaled $76 million. Fourth quarter general and administrative expenses were $10.4 million, with $6.2 million being cash G&A expense or $2.63 per BOE within guidance range. Full year 2025 cash G&A expense was $2.51 per BOE. Fourth quarter consolidated adjusted EBITDA was $64.8 million. Production run rate was 25,627 BOE per day in fourth quarter, exceeded midpoint of guidance. Pre-developed reserves increased approximately 8% in 2025 to nearly 73 million VOE. Active rig count was 85 rigs drilling across acreage, representing 16% market share of US land rigs. Q4 2025 distribution was 37 cents per common unit, up 6% from Q3 2025. For the year, $1.60 per common unit was returned through quarterly distributions, all classified as return of capital and 100% free of dividend income taxes.

• 2026 production guidance midpoint remains unchanged from 2025 at 25,500 BOE per day. - Announced financial and operational guidance ranges for 2026. - Production guidance midpoint unchanged from 2025. - Confident about prospects for continued development in 2026 due to number of rigs drilling on acreage and line-of-sight wells exceeding maintenance well count.

Q: Regarding 2026 guidance, speak to expected production cadence from 4Q25 levels.

A: Relatively stable, difficult to predict as don't control development, but assume relatively stable development cadence over 2026.

Q: About competitive landscape for M&A after 2025 industry consolidation, how characterize outside of Permian now less competition?

A: Two advantages - can target $100 million to $500 million size range deals and focus at every basin across country. Example of Longpoint acquisition successful, MidCon area bullish with gas and NGL price improvements and recent consolidation in Oklahoma.

Q: Net line-of-sight maintenance well assumption increased to 6.8 from 6.5, walk through what drove change?

A: Simple explanation, determined once a year, last year in first quarter acquired Boren, 100% high upside, unconventional, horizontal properties, which led to modest increase in maintenance level.

Q: Net debt down $30 million in last six months, how thinking about addressing mezzanine equity?

A: There is a minimum threshold for redemption, probably anticipate redeeming some portion in latter half of year, be opportunistic, weigh balance between cash interest expense on RBL and what's paid on mezzanine.

Q: On realizations, how to think about natural gas realizations as percent of Henry Hub, NGL realizations as percent of WTI, differentials for crude this year?

A: Oil differential flat at 2% between Q3 and Q4. Natural gas 18% in Q3, 24% in Q4. NGLs flat quarter over quarter. Natural gas differentials seasonal, higher in Q4 and Q1, lower in Q2 and Q3. Waha and takeaway capacity build-out expected to improve long-term natural gas differentials.

Q: About WAHOP price inflection in 27 and exposure, impact on company?

A: Over 85% of gas production outside Waha, but WAHOP price inflection in 27 expected to be a catalyst for improving differentials. Excited about continued development of different benches, especially Woodford-Barnett area, with operators showing increased interest, which is a tailwind for business.

Q: Is activity more about improving production or revenue tailwind on lease bonus side first, rough idea?

A: More on production side, almost all acreage is leased, will get some lease bonus impact, with acreage in areas prospective for Woodford-Barnett, and operators showing increased interest in developing the area.