RANGE RESOURCES CORP Q4 FY2024 earnings call

Key Points

• 2024 Operations: Ran 2 rigs and 1 completion crew, with capital investments of $654 million. Production was above guidance at ~2.18 Bcfe/day due to strong well performance and infrastructure optimization. Drilling set new efficiency records with over 800,000 feet of lateral footage drilled, and completions saw efficiency gains with 3,300 stages completed.
• 2025 Plans: Project to run 2 drilling rigs and 1 frac crew program, with an all-in capital budget of $650 to $690 million. This includes ~$530 million in maintenance capital, $70 to $100 million in drilling/completion capital, up to $30 million for targeted acreage, and $20 to $30 million for emissions upgrades. Production expected to grow to ~2.2 Bcfe/day in 2025.
• Three-Year Outlook: Plan to add ~400 million cubic foot equivalent of daily production over three years, reaching ~2.6 Bcfe/day in 2027. Reinvestment rate expected to remain well below 50% at $3.75 gas price, with breakeven improving to ~$2 for NYMEX. Maintained 30-plus years of high-quality Marcellus inventory.

In 2024, Range Resources had production of approximately 2.18 Bcfe equivalent per day. The production makeup was diversified with 70% gas and 30% liquids. The value of the Liquids business was highlighted with the highest NGL premiums in company history in 2024, driven by marketing ethane, propane, and butane into international markets. The aggregate unhedged price realization was a $0.49 premium over Henry Natural Gas.

Forward-Looking Statements

• 2025 Capital Budget: $650 to $690 million all-in capital budget, with production expected to grow to ~2.2 Bcfe/day.
• Three-Year Growth: Projected production to reach ~2.6 Bcfe/day in 2027 with a capital budget of $650 to $700 million. Reinvestment rate at $3.75 gas price well below 50%, with margin improvement to ~$2 breakeven.
• Tax Benefits: Federal NOL carryforwards of $1.4 billion and Pennsylvania state NOLs of ~$770 million expected to reduce after-tax cash flows by over $300 million over the next two years.

Risks

• Industry Cyclicality: Potential for oversupply in the global LNG market and cyclical nature of commodity prices could impact results.
• Demand Dependence: Growth plans are heavily dependent on demand growth materializing in end markets such as LNG, power, and reindustrialization, which may not occur as expected.

Q: Just taking a look at your three-year outlook and your plans to grow into 2027, can you give us a little bit of sense on the thought process?

A: Good morning, Scott. I think when you start to look at 2025, a lot of things, you know, you've heard us say in the past and Mark touched on this morning, inform our approach for not only this year but then what that looks like for 2026 and 2027. And I think we really wanted to see some clear line of sight on some of those demand growth opportunities and also have a home for the production. We know that that is a critical part of the overall equation because it feeds to the top line, and that is our cash flow and our cash flow goals that we're going to have over the next several years.

Q: And did you look at that growth in the 2027. Just can you give me your thoughts on do you hedge some of that to, you know, mitigate some, you know, potential weakness in price?

A: I think the answer to your question is kind of yes to all of the above. One of the hallmarks of our program is flexibility. We built into it through diversity of the outlets. Fundamentally, I think it's important to keep in mind the structural hedge that's hedges that are built into our business. By the nature of our production, with 70% gas, 30% liquid, the uplift and the resilience, you know, combine that with where the balance sheet is, the need to hedge is simply greatly reduced. What we do hedge, that philosophical approach to providing some level of insurance for a steadiness for technology. To preserve the optionality of being a bit countercyclical. In order to create really outsized value, that's the fundamental guiding principle there.

Q: Morning. Maybe starting out with the new gas takeaway agreement. So I was wondering if you could frame those relative to your current agreements and what you might see on the cost side over time as you start utilizing those.

A: Good morning. I think when you look at the transport that we've been able to acquire, it's going to look and feel a lot like what you've seen from our current portfolio. So in a lot of ways, Jake, the percentages really don't move significantly or really materially versus what you've heard us talk about in the past where essentially 80% of our gas gets out of basin and on total, 50% gets down to the Gulf. So it's a little bit more weighted in the direction of the Midwest, but there's a significant exposure in this transportation that gets us to the Gulf, which we really like. From a cost perspective, it's going to be right in line with what you've seen us in prior cycles on GPT reporting. So really no change from a cost structure there. But inherently, from a total perspective, we would expect to see some relief as we talked about with prepared remarks over the course of time as we efficient use of that infrastructure and also some portions of our contracts in the past that have some cost roll-up over the course of time. So there's still an opportunity for us in the near term to see GT and T look really consistent. And in the future, continue to see it actually roll off as well.

Q: Hey. Good morning, guys. Just wanted to start off, and one of your peers made a meaningful distinction this quarter on the difference between maybe an attractive gas strip price versus what they were actually seeing on the supply-demand side. So just wondering, you know, first, if this decision was made using one or the other?

A: Yeah. I'll start this morning on that question. Bertrand, thanks for joining the call. I think there's, I'll just say, commodity price alone really wasn't the driver in this conversation as we started to formulate a three-year plan. I think we touched on a couple of aspects in the prepared remarks, but really it was around our free cash flow goals and objectives over the balance of the next three years coupled with the demand that we see we have line of sight on and the transport that it gets us to, again, those known end markets.

Q: Hey. Good morning. Appreciate the details on the multiyear production and CapEx plan. I wonder if you could help us bridge the gap between the production point 2 Bcf a day in 2025 and 2.6 in 2027. Will the production ramp up at a measured pace in 2026 or will it be kind of a steeper growth in the back half of the year?

A: Yeah. I think if you start to look at the production profile in 2025, I'll start there. You know, it'll look pretty similar character-wise to what you've seen in the past where the front half of the year can be activity-driven. You're gonna see some turn-in lines start to then materialize through the back half of the year into, I'll just say, adding that incremental production. So it'll be higher in the back half of the year, a little flatter in the front half of the year. But some of the infrastructure that is in process of being constructed and will get commissioned, some of that gets commissioned in late spring. And some of it's going to be in the fall time period. So as you can imagine, that compression and gathering support for this growth profile will then start to materially move our production profile in that back half of the year and then provide momentum as we start to look into 2026, 2027.

Q: Hey. Good morning all, and congrats on a strong year-end. For my first question, you noted that you secured additional transport processing and export capacity to support your planned production profile. Is the right way to think about growth beyond that 2.6 Bcf e a day level post-2027 requiring additional transport capacity or incremental in-basin demand to support it?

A: Yeah. Good question this morning, John. Thanks for joining us. I think when you start to think about what's beyond 2027, I think in a lot of ways, we can be patient. And that's really what's happened over the balance of the last couple of years. And there could be opportunities for us to take on that goes underutilized by others in the future as well. It's hard to have line of sight on what the volume of that could look like today. But I think when you start to really look at what inventory exhaustion and the role that could play for basin producers, and the competition for capital allocation within their given portfolios versus Range.

Q: Good morning, everybody. Obviously, you're pretty bullish on both net gas and NGL demand growth. If one or the other weren't to materialize, like you think, can you talk to your ability to shift the production mix to respond?

A: Yeah. I think if you look at how we balance the activity over the last several years from a well mix standpoint, it could look really similar to on the go forward. So we've typically been somewhere in the 70% to 80% on the processable gas side. And then ultimately, you know, 20% to 30% on the dry gas side. But we've always left some flexibility within the program to allocate capital from one side of our asset base to the other. So we think that affords us some good optionality. But the other part of this is we also can be flexible in how we utilize in-basin gas. To basically utilize the transport that we've committed to coupled with the processing and again still harvesting that NGL uplift.

Q: Hey. Thanks so much, Dennis, Mark. Continue. Guess the first question is just around the NGL side. We spend a lot of time talking about dry gas. But one of the hallmarks of your 2024 realization was just how good your differential was in NGLs. I think it's $2.33. So how do you think about that premium as we work our way through 2025?

A: Yeah. Thanks, Neil. This is Alan. Good question. We like talking about NGLs, or at least I do. Premium last year really was fantastic, and I think it goes back to just, you know, our activity in the international markets that started way back in 2016 when we were part of the first-ever export of ethane for the Bayonne. Did US. The contracts internationally, some of them are priced on international indices. Some of them are just priced on premiums to domestic indices. And they really do make a difference in our returns. And as you saw last year, overall dock capacity in the US on ethane as well as LPG was relatively tight. So when supply demand of anything gets tight, value, if it goes up, and the value at the dock went up as a result of that.

Q: Good morning. I want to ask about the implied improvement in the capital efficiency that's shown in the three-year outlook. If I look at what you guys are saying on 2027 maintenance capital, it's $570 million to maintain 2.6 Bcf per day. And then in 2025, you're doing that at $500 million for 2.2. So wondering if there is any implied, like, improvement in well cost or drivers behind this better capital efficiency long-term versus today.

A: Yeah. Good morning, Betty. I would tell你 what's really embedded in that outlook of capital spend as you start to get to that $570 million in the 2027 time period is it really is on the back of our continued efficiencies of our operation. But all in extending lateral lengths. Again, we've touched on that a lot, but it's on the back of our ability with our contiguous acreage position to extend laterals, some of the incremental land PIN date. That we've talked about on a very low level to pick up those open parcels that'll allow us to extend the lateral lengths. I think you saw that this past year where our average drilled lateral length was 14,000 feet as an example. So it's going to be supported by that. But also the other part of this is just the ability to continue to reutilize infrastructure again, drilling those long laterals in our low base decline. You start to look at how the field continues to perform over the course of time, our assets really do have a unique base decline profile versus some other basins and some other in our basin. It allows us to continue to capitalize on that with a strong foundation.