Range Resources Corporation Q4 FY2025 earnings call

• Operations: Continued steady progress, with safe and efficient execution, strong well results, free cash flow, and good safety performance. Drilling and completion efficiencies improved, and supply chain RFP resulted in stable pricing for 2026. - Marketing: U.S. energy exports set records, with LNG, ethane, and LPG exports showing growth. Successfully navigated winter storm Fern by redirecting LNG feed gas and coordinating production/sales plans. Executed long-term sales agreement for gas to a Midwest power plant and supports prospective projects in power generation and data center space. - Go-forward plans: Over 500,000 lateral feet of growth-focused inventory, providing flexibility for future development. 2026 capital budget $650 million to $700 million, with plans for maintenance, growth, land, and emissions reduction.

In the fourth quarter, Range had all-in capital of $183 million and produced 2.3 Bcf equivalent per day. For full year 2025, capital investment was $674 million, with production at approximately 2.24 Bcf equivalent per day. Drilling in the fourth quarter involved 2 horizontal rigs, drilling ~225,000 horizontal feet across 15 laterals. Completions in the fourth quarter were ~1,200 frac stages, with 2025 totals near 3,800 total stages. Marketing saw U.S. energy exports set new records in Q4 2025, with LNG exports averaging over 17 Bcf per day, waterborne ethane exports at 622,000 barrels per day, and LPG exports expected to benefit from new U.S. export terminal capacity in 2026. Revenue contribution: ~90% from outside Appalachia due to advantaged transportation and sales contracts.

• 2026 production expected to be 2.35 to 2.4 Bcfe per day, with first quarter production down vs Q4 2025, then stepping up in second half due to midyear gathering and processing expansions. - 2027 production could be 2.6 Bcfe per day with less than $600 million in annual drilling and completion capital. - 2026 capital plan: ~$500 million maintenance D&C, $120 million to $140 million D&C growth, $15 million to $35 million land, $15 million to $25 million for software and production facility upgrades.

• Weather-related volatility in gas markets, which could impact production and pricing. - Uncertainty around future service costs and their impact on well costs and capital efficiency. - Potential for changes in market demand and pricing that could affect production and sales plans. - Counterparty risks associated with confidential terms of certain agreements.

Q: Could you give a little more color on the cadence of production you're expecting in 2026?

A: Q1 expected to be ~2.2 Bcf equivalent per day, with midyear processing capacity coming online and year-end production forecasted at ~2.5 Bcf equivalent per day.

Q: Can you give us a little bit of color on what kind of premium you were able to capture in the power contract?

A: Confidential terms of the arrangement, but it's scalable and part of many potential opportunities.

Q: What signposts or criteria will drive the decision on production beyond 2027?

A: Primarily generating free cash flow, commodity pricing, transport capacity, and demand.

Q: At what point would you expect structural in-basin demand growth to begin compressing Appalachian basis differentials?

A: Driven by portfolio of transportation options, marketing team optimization, and ability to capture market runs.

Q: What would cause you not to bring on DUC production if gas prices were softer?

A: Flexibility to take advantage of commodity price signals, with timing of infrastructure and well turn-in lines considered.

Q: Why not let more float on the cash market given strong balance sheet?

A: Utilize multidisciplinary team to balance commitment to Bidweek based on weather, macro perspective, and operational maintenance.

Q: Where do you view service costs over the coming years?

A: Low to mid-single-digit relief, with multiyear agreements and operational efficiencies affecting costs.

Q: Is there potential to grow volumes in the supply agreement?

A: Yes, facility has scalability and counterparty is open to additional projects.

Q: How to allocate capital across liquids versus dry gas acreage?

A: Dry gas has inventory, infrastructure debottlenecking and utilization of existing capacity considered.

Q: Compare in-basin demand and supply outlook today vs when growth plan was initiated?

A: Took on market share using existing capacity, with future growth dependent on demand materializing.

Q: Why is guidance for differentials similar year-over-year?

A: Starts with market indications, guide is ~$0.05 better year-over-year, and realizations improve through marketing team's experience.

Q: Thoughts on return of capital allocation between buybacks, dividends, and balance sheet?

A: Favor buybacks for now, slowly grow dividend, with focus on total shareholder return.

Q: Assumptions on op cost in free cash flow forecast?

A: Flat, but team can ring out more efficiencies.