California Resources Corporation (CRC) Q1 2026 Earnings Report, Transcript and Summary

Good day, and welcome to the California Resources Corporation First Quarter 2026 Conference Call. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Daniel Juck, Vice President of Investor Relations. Please go ahead.

Good morning, and welcome to CRC's First Quarter 2026 Conference Call. Following prepared comments, members of our leadership team will be available to take your questions. I hope you have had a chance to review our earnings release and supplemental slides. We have also provided information reconciling non-GAAP financial measures to comparable GAAP measures on our website in our earnings release. Today we'll be making forward-looking statements based on current expectations. Actual results may differ due to factors described in our earnings release and SEC filings. [Operator Instructions] I will now turn the call over to Francisco.

Thanks, Dani. Good morning, everyone. We're off to a solid start in 2026 with unprecedented energy market volatility creating meaningful tailwinds and opportunities for our business. Before getting into the quarter, let me share a few thoughts on the macro environment and why CRC's business is well positioned to create value through the cycle. Events across the Middle East have reminded the world of the importance of oil and energy security. Global supply chains have shown to be vulnerable and countries have been forced to seek reliable, diversified sources of energy. While the United States has been relatively insulated due to our strong domestic production, California faces a unique and precarious position. Today over 60% of the oil consumed in California comes from foreign sources. In recent weeks, our state's inventories have been reduced by more than 20% as oil destined for California has been diverted to Asia at substantial premiums. The importance of in-state production has never been more critical, both to ensure supply and preserve affordability. As the Golden State's largest producer, CRC is positioned to be this solution. Delivering local barrels that shorten the supply chain, lower transportation costs and associated emissions, and helping keep gasoline affordable for Californians. CRC has a deep, primarily Brent-linked, high-quality inventory of oil development opportunities, and recent legislative efforts to improve permitting are proceeding as expected. Our recent mergers were well timed with transactions priced well below today's strip, and set a strong foundation for future growth. We're now deploying capital into these assets to drive disciplined long-term value. California is starting to recognize that local production is essential to affordability, reliability and the state's climate objectives. And CRC is ready to support all 3. Today we're moving decisively to accelerate development. We are increasing drilling cadence this summer by 3 rigs: 2 in California and 1 in Utah. This will allow us to return to our long-term production maintenance capital program ahead of schedule and accelerate high-return projects to unlock value. In California, we're drilling new wells and adding capital-efficient workovers that will translate quickly into production. And in Utah, our highly contiguous acreage position provides meaningful upside that we have only begun to capture. Let me spend a moment on the Uinta acreage because this opportunity is compelling. Since 2020, production in the basin is up 100%, reflecting both improved results at the well level and expanded more mature regional infrastructure. Recently drilled CRC and offset wells have substantially derisked our acreage, and we're planning to perform additional appraisal work. With over 200 gross Uteland Butte locations already in the portfolio and additional benches under consideration, we have considerable running room to support a scalable growth platform. Our planned acceleration in activity to 7 rigs will meaningfully enhance our financial outlook. For the full year, we are now targeting approximately 1% entry-to-exit gross production growth, and raising our adjusted EBITDAX guidance by over 40%, outpacing the expected rise in Brent. We're also increasing our Berry merger synergy target, which Clio will cover in detail in a moment. Our carbon management business, CTV, is on the cusp of a historic milestone. We completed the construction and commissioning of California's first commercial-scale carbon capture and store project at our Elk Hills cryogenic gas plant, and we expect to receive final notice of the termination from the EPA any day now. That approval will clear the way to first CO2 injection, marking the first time in California's history that carbon emissions are permanently stored. It will also place CRC among a small group of U.S. oil and gas companies with active CCS operations. Put simply, this is a defining moment, not just for CRC, but for California's ability to deliver on its climate objectives while preserving energy reliability and affordability. We expect carbon capture at our Elk Hills cryogenic gas plant to be the first of many more projects to come. Our storage reservoirs sit within reach of approximately 17 gigawatts of baseload power generation across California that we believe has the potential to be retrofitted for CCS. And we have submitted over 350 million metric tons of carbon storage capacity to the EPA, with additional reservoirs tracking or draft permits through 2026. Our data center conversations continue to gain momentum. As previously announced, a top-tier national data center developer is investing several million dollars to accelerate early-stage site readiness and permitting at Elk Hills, a clear vote of confidence in the opportunity. As AI transitions from training to inference and other states face mounting power constraints, tech's appetite for scaled clean power in California is growing. CRC is uniquely positioned to meet that demand. We can permit, deliver firm gas supply, offer available land adjacent to existing infrastructure and [ pair it ] all with CCS. Power is the binding constraint for AI growth, and we are one of the few platforms that can solve it. On the Reliable and Clean Power Procurement Program, or RCPPP, we expect the next major update in the second half of 2026. Natural gas with CCS is not yet eligible, but support is building and [ 3 of 5 ] CPUC commissioners have publicly endorsed inclusion. California already offers some of the highest stackable CCS incentives globally. RCPPP eligibility would make the economics even more compelling. Our enhanced 2026 outlook reflects the positive impact of these developments as well as the continued execution of our strategy. With that, I will turn it over to Clio to walk through our first quarter results and updated 2026 guidance. Clio?

Thank you, Francisco, and good morning. We delivered a strong first quarter with adjusted EBITDAX of $304 million, approximately 17% above the midpoint of our guidance, and we are raising our full year guidance. The combination of disciplined execution, higher oil prices and accelerated activity has improved our outlook for 2026. In the first quarter, operating cash flow before changes in working capital was $247 million, ahead of our expectations and reflecting the stronger Brent backdrop relative to our previous guidance. Net production averaged 154,000 BOE per day, with oil at 81% of the mix and realizations at 96% of Brent pre-hedged, in line with plan. Adjusting for PSC effects, underlying production was in line with our quarterly guide. G&A for the quarter was above guidance due to the timing of legal expenses and a higher cash settled equity compensation, reflecting share price appreciation. G&A is already trending down with further reductions driven by Berry synergies, which we expect to capture in 2026. Total capital deployed in the quarter was $131 million, at the high end of guidance. The increase in spend was by design as we pulled forward pre-spud timing on development wells and accelerated facility spend to support the activity ramp Francisco outlined. Even with that accelerated capital deployment, free cash flow before changes in working capital was $116 million, a strong start to the year. In March, we priced a $350 million add-on to our 2034 notes. We upsized from $250 million with a book more than 5x oversubscribed and used the proceeds to redeem our 2029 notes. This extends our weighted average maturity to approximately 6 years, lowers our interest expense and further strengthens the balance sheet. Net debt ended the quarter at $1.3 billion, with net leverage at 1.1x last 12 months EBITDAX. We returned $46 million to shareholders during the quarter, including $36 million in dividends and $10 million in share repurchases, bringing cumulative returns since mid-2021 to more than $1.6 billion, a track record that reflects the consistency and the durability of this business. Current conditions across domestic energy markets arguably provide the most constructive backdrop for our business and the industry than we have seen in quite some time. For the second quarter, we expect net production of 149,000 BOE per day, reflecting the impact of PSC effects at higher prices and a planned short maintenance window at our Elk Hills power plant. We expect capital deployment of approximately $130 million, reflecting increased drilling activity in June, G&A of $95 million, and adjusted EBITDAX of $390 million, assuming an average Brent price of $105 per barrel. As usual, we provide both quarterly and full year sensitivities to Brent to help frame the impact of commodity price volatility. For the full year, we are raising our outlook across the board. We now expect 2026 exit gross production of 175,000 BOE per day, roughly 1% entry-to-exit growth and building momentum into 2027. To deliver this growth, we are increasing full year midpoint of total capital guidance to $540 million. [ D&C ] and workover capital is $100 million above our prior plan, reflecting a second half ramp to a peak of 7 rigs. Partially offsetting this increase is a reduction to facilities capital of $10 million, reflecting ongoing field level facilities rationalization. Allow me to pull all of this together in one important comparison. We previously forecasted that our maintenance capital framework to hold production flat required 7 rigs and approximately $485 million of D&C and workover capital. This year, and given our portfolio's flexibility, we are expecting to deliver entry-to-exit growth with an average of 5 rigs and D&C and workover capital utilization of less than $400 million. Fewer rigs, less capital, and we are now growing. The return profile on our full year 2026 capital program is compelling. At current strip prices, we expect a multiple of approximately 4.5x on invested capital, up from 3.8x previously. And IRR is approaching 70%, roughly 40% higher than our prior estimate. We now expect full year free cash flow before changes in working capital to exceed $800 million. Turning to Barry merger-related synergies. We have already implemented over 80% of our original target and are now raising that target by 12% or an additional $10 million. That's driven by field consolidation and contractor-to-crude conversion across the combined footprint. Our cumulative synergy and structural cost reduction target through 2028 now stands at upwards of $460 million. We expect full year adjusted EBITDAX at a midpoint of $1.45 billion, assuming an average Brent price of $91 per barrel. This increase reflects both higher commodity prices and underlying margin expansion. Brent is up approximately 38% while our EBITDAX outlook has increased by approximately 42%, with a positive difference driven by high-return drilling, structural cost discipline and incremental synergies, all supporting higher cash flow per share. That gap between commodity upside and EBITDAX upside reflects the value of our integrated strategy compounding, and it is the kind of outperformance we can sustain through the cycle. Cash flow per share growth, high-return reinvestment, a derisked balance sheet and structural margin expansion, that is 2026 in a nutshell. With that, I'll turn it back to you, Francisco.

Thanks, Clio. Before we open the line for questions, let me share a few closing thoughts. CRC remains a different kind of energy company. And this distinction could not be more evident. Our integrated strategy is delivering on 3 fronts at once: a low-decline conventional business accelerating into a stronger price environment, California's first commercial-scale CCS project on the doorstep of CO2 injection, and a power and data center opportunity gaining traction. The path forward is clear. We're scaling activity across California and delineating the Uinta. We're converting structural margin expansion into cash flow growth. We're returning capital through a durable dividend and opportunistic buybacks. And we're advancing our leading carbon management platform. Our priorities are unchanged: develop our resource base responsibly, unlock the full value of our portfolio, maintain a premier balance sheet, and allocate capital with discipline. That is how we create durable long-term shareholder value. Operator, we're ready for questions.

[Operator Instructions] The first question comes from Scott Hanold with RBC Capital Markets.

Looks like you have it all coming together. You got the permit reform, you identified the inventory, now you've got the price. So this growth path, I think, looks pretty attractive. But I was wondering if you could walk us through the 2026 program as it is now, just give us a sense of when the rigs are coming on and how that translates into when the production actually shows up throughout the year. And if you can give a little bit of context too on the permits, whether or not you've got the permits in hand to execute it at this point.

Scott, thanks for the question. Yes, we came into the year looking to reestablish the permitting process, showcase the inventory and then the highly capital-efficient program. We think the updated 2026 guide reflects the progress on all these objectives. Let me explain. So we're going to be drilling a total of about 357 new wells and side tracks for the year. Happy to report that we have all permits for all 7 rigs now on hand and are working on our 2027 plan. Not only that are permits flowing, but the process overall is getting better. So with the permitting process being squared away, that allows us to focus back on more dynamic capital allocation. And that's where we see an advantage versus maybe the shale peers in the rest of the country. We have a lot of flexibility to deploy capital and have very short time to market. So time to markets are very quick, from spud to production is roughly 30 days on average, although we can beat that number. And we don't have the same level of service intensity or competition for equipment and crews. So we can try to connect to a window of price opportunity and deliver incremental production that way. So we're lining the incremental rigs to be ready in the summer and start producing in the -- early in the second half of the year. So then that allows us to focus on the overall picture, which is returning production to maintenance. We talked about and showcased that we have significant running room, 24 years of inventory. Our wells are performing extremely well. We're beating the [ tight ] curve. And you can see that in the numbers that Clio highlighted. Our entry production is 174,000 BOEs per day. Our exit is estimated at the midpoint to be 175,000 BOEs per day at the midpoint of the guide, and that's on a gross production basis. Why do I mention gross production and not net? Because that's a cleaner measure of reservoir performance. Gross is unaffected by PSC cost recovery variability. We have the contract in Long Beach where it's subject to PSC mechanics. So you look at growth in terms of being able to measure that efficiency. So now you can also back out the PSC effects from net production and you get to the same shape; you're staying flat to slight growth. But the really exciting thing that we're seeing come through as our team is executing is that we're staying flat with less rigs. So the improvement on capital efficiency has been significant. So let me turn it to Clio to highlight the capital efficiency and the returns of the program as well.

Scott, really on the efficiency point, the comparison here is really compelling. So on how much our program has improved relative to what we outlined just last quarter. We had talked about the 7-rig program with about $485 million of D&C and workover capital. That will be needed to hold production flat next year, so in 2027. And today what we're outlining is we're delivering that flat to modest growth with roughly 5 rigs throughout the year and under $400 million of D&C and workover capital. So that's a meaningful step up in the capital efficiency. We're getting more out of fewer rigs, less capital, and we're bringing that forward in time. And most importantly there, that improvement is also showing up in our returns profile. And so the program-level returns, you're looking at roughly 4.5x MOIC, nearly 70% IRR, that's meaningful further increase from our prior program, which was already highly attractive. I'll unpack that just a bit further. It's coming from a few places, 3 things really: well economics, cost structure and portfolio sequencing. So first, we're seeing better capital productivity at the well level, both in terms of cost and also early time performance. Second, we've structurally lowered our cost base and particularly on the field and facility side. And third, sequencing and timing here. We're simply deploying capital more efficiently across the year and across our broader portfolio. So this isn't just one lever. It's a multiple of improvements compounding at the same time. And as you think about our activity increase here, Scott, the key is that it's tightly price-gated. So we remain capital disciplined at current strip free cash flow before working cap. That is expected to come in above $800 million this year. And we're also anchored to long-term pricing rather than near-term thought. So at around $65 Brent, our 4-rig program was fully supportive and generates strong returns. And each incremental rig from there, that requires roughly $5 Brent increase and long-term pricing to maintain those returns. So what effectively does here is create a clear decision framework internally. Every step-up in activity has to meet our return threshold. So even in a stronger tape that we're seeing today, we're not chasing volumes. We're scaling only where returns justify it. And as you move towards 6 rigs in California, we're underwriting that again something closer to a $70 or $75 Brent long term, which is broadly where the strip sits today. And tying back to what Francisco was mentioning earlier, that framework, it's really enabled by the flexibility and program. We can adjust activity quickly without putting really the base at risk. So key takeaway here, Scott, is it isn't a change in strategy; it's stronger execution and better economics.

Yes. I appreciate all the color. That was very helpful. My follow-up question is, is on Uinta Basin. And then maybe if you could step back for us and talk about why invest in Uinta, and how do you look at the long-term strategy of that asset?

Yes, Scott. So we're still in the evaluation stage of Utah. We have 4 wells that we want to drill before the end of the year. We have -- when we acquired Berry, we booked about 200 locations in -- but as you look at the stacked acreage and the horizontal development and what offset operators are doing, there's a lot more running room to go. But ultimately, we're looking to unlock the best value. And the way to think about it going forward beyond the 4 rigs is we are considering full development, but we're also considering monetization. So I'd say we are not in a holding pattern anymore. We're going to make a decision coming up. But we see some compelling opportunities to delineate and advance the evolution and the understanding of that asset base. I wouldn't call it a core asset, our core is California, but we're still in that evaluation stage. We see the rest of the country struggling to find high-quality inventory. We think the Uinta will provide that. And the nice thing for us is we attributed very low value to Utah in the very acquisition. So that leaves us with meaningful upside to unlock that best value. So more to come. For now, 4 rigs. We're still evaluating. Sorry, 4 wells, not 4 rigs.

The next question comes from Betty Jiang with Barclays.

I want to start first on the upstream and maybe impact a bit on the capital efficiency improvement that you're seeing in '26 and how that's impacting 2027. 2026 guidance is a bit noisy just with the PSC effects, but you guys spoke to a lot of those investments is really showing up in the second half, and Uinta is not going to peak until first quarter of next year. So I'm wondering how much of the 2026 investment is going to show up in growth in 2027. And then just on the CapEx side as well, is it fair to say that if you are at 5 rigs this year growing on the lower CapEx, is maintenance CapEx now lower than the $485 million before?

Yes, Betty. And yes, it's early to guide and to start locking in 2027, but I get the logic behind your question. We are definitely seeing capital efficiencies improve and lower the maintenance capital. I think that is evident in the guide today. We do see longer term 7 rigs as the table stakes for the business. What that means is that is the view we have on the forward long-term baseline at mid-cycle pricing. Have, as Clio said, a lot of flexibility and we can adapt to market conditions, but from a planning perspective, we see 7 rigs as what we want to invest in given the quality and duration of our inventory. So in terms of the investment that we're making now, yes, the -- in conventional assets, you will see the shape of the wedge that peaks -- in this year, we invest, we peak next year, right? So a lot of the investment that we're making is not for 2026 [ expected ], it's really for the benefit of 2027. And having a view towards the long-term price curve and seeing -- and also with our strong hedge book, that gives us confidence to deploy capital thinking into 2027. Ultimately, 7-rig pace also yields a very resilient free cash flow profile. That allows us to have durable returns for shareholders. Ultimately, we'll have to look at a lot of elements as we start thinking about the rig deployment in 2027. So we have a great portfolio, a different mix of wells, different commodities that we can go after. I would not assume that we would -- seeing the split of 6 in California and 1 in Utah. That's still to be determined. But a total of 7 rigs is what we think is the long-term guide on baseline investment for the business.

Great. That's helpful. For my follow-up, I want to ask about the data center development. You spoke to you're working with a top-tier data center developer to find sites or develop sites in Elk Hills. Can you just speak to the scope of that partnership? Is it fair to think about the value accrued to CRC long term could be on multiple fronts from the value of surface acreage, gas supply, CCS, et cetera? And then just how are the conversations going in general to move the project forward?

Yes, Betty. So we're making really good progress. We have previously discussed the concept of land now, which means land that's permitted, it's powered, shovel-ready codeveloped and, ultimately, an adjacent to our Elk Hills facility. So we're getting the site ready and our data center partner is putting real capital behind the opportunity, investing several million dollars to accelerate the early-stage work. So we see a lot of people chasing headlines trying to talk about hyperscalers and data centers. We're really focused on project delivery and accelerating durable contracted cash flows. So it's a good way to think about it as we have an integrated view on data centers, from natural gas supply, which we have at Elk Hills, to land, which we have over 200,000 net acres of surface and a lot of it is around Elk Hills, to also being able to provide power and then decarbonize those electrons. We think it's a very compelling one-stop shop opportunity. And we're focused on the delivery. So you'll see more progress on the permitting, you'll see more progress on the advancement, and that's all coming together in a very nice way. We've developed a very strong core competency in being able to kind of navigate the California regulations. We've done it with oil and gas effectively, we've done it really well with carbon capture, and now we're going to do the same thing with data centers. So our partner is adding a lot of value in that design in anticipation of what hyperscalers need. So it's a real and exciting project we're developing. And we'll be ready to announce the specifics a little bit further along, but we're seeing really good progress.

The next question comes from Josh Silverstein with UBS.

Nice update on the Berry synergy front here. And I like that you guys give the 3 different bars there to help kind of break those out, where they're coming from. Can you just talk about how these are starting to trickle in through the course of this year? Will you start to see it in 2Q? Or is it later on this year where those benefits really start to show up?

Josh, so yes, the integration with Berry is going extremely well. At this point, we've captured about 80% of the targeted synergies. We increased our target by $10 million, primarily in OpEx, and trending really well towards the cumulative target of $460 million of annual synergies between [ Era ] and Berry. So the trajectory, the trend is all going very well. So why the rate in OpEx? I'll give you a couple of examples. Our team is doing a fantastic job in field consolidation. So what that means is we're merging overlapping water and oil treatment facilities and ultimately also consolidating supplier contracts by leveraging our CRC infrastructure and vendor relationships. So that's going really well, probably better than anticipated. We also have a big opportunity for automation. Both Era and CRC were much stronger in automation than Berry. So now we can integrate the legacy Berry fields into our operational control center, which creates the scale and the automation that we need in the operating model. I'll turn it to Clio talk about more of the specifics. But one thing to also note, I see a lot of oil companies talking about AI and how they're incorporating AI into operations. We're working on the same things and seen efficiencies, but those numbers -- those impacts are not quantified yet in our numbers, right? So there is some upside assuming technology advancement and implementation works, but everything else we're really doing is more physical movement and placement of facilities alongside with reductions in G&A. But I'll turn it to Clio to provide a little more context on the synergies.

Josh, I'll frame it from a broader financial perspective to start really on how those synergies benchmark and then look at your timing question and unpacking that. So on the benchmarking side, while the $10 million increase we announced today on the various synergies, that might look incremental in terms of absolute terms, it's actually quite significant relative to the size of the transaction. We're now roughly at 13% of deal value, which is well above what we typically see in the sector, where most of those transactions are in the mid-single digits, and more recently, we've seen deals trend even lower. So this is clearly a differentiated outcome. And importantly, it's consistent with what we delivered on Era. So we view this as a repeatable playbook for us. On the trajectory, we're largely through a lot of the action items. So we laid out last quarter that we had already delivered roughly $300 million of structural cost reduction and that ahead of schedule. This quarter, we've captured the 80% that Francisco was mentioning of our original Berry synergy targets. So we're well on our way. And the durability of the model is really proven on the synergy capture. And that is what gives us confidence in the path forward on the longer term and our ability to get close to that $0.5 billion of cost reduction. I'd say the remaining synergies that we're looking for are less about those onetime actions now and more about continuous improvement of the business, and you could expect those to come through more steadily over time. If you put it all together, it's really a sustained structural margin expansion story that's continuing to build. And you're already seeing that in our outlook where EBITDAX is growing ahead of the commodity price rise.

Got it. I was hoping to shift over towards the power business for you guys. And I wanted to see how you guys are thinking about the evolution of this business for you? Is it something that could grow? I know it's something being integrated with other parts of the business, but how are you thinking about this? And then maybe just kind of a broader overview of what you're seeing in the California markets.

Yes. California is fascinating. We keep seeing the same message. We just need more power in the state. And it needs to be clean, it needs to be reliable, it needs to be around the clock. And we're one of the very few companies that can go from molecules in the ground to electrons on the grid to carbon back on the ground. We think that's a big differentiator, and the geology and our expertise on subsurface is what makes it really difficult to replicate. If you then look at the interconnection queues in California, it just takes longer than anywhere else in the country. And so that puts a scarcity premium, capacity that's already tied to the grid. So having those assets, it's very meaningful. We have close to 1 gigawatt of power under our portfolio. But we're seeing some regulatory improvements. So the CPUC just started the procurement process of 6 gigawatts of new clean capacity by 2032. But what we really like to see is that 1.5 gigawatts of that is clean and firm. So that's the energy that we can provide, right, always on, dispatchable, zero emissions. So these are solar and batteries can fill that, it's gas, natural gas with CCS. So in terms of the dynamics that we're seeing, we see a resource adequacy payments that are compressed today because you have a lot of this intermittent supply solar and wind that's flowing in the market. But this new clean, firm requirement creates a structural demand for what we operate. So then the resource adequacy pricing is expected to follow and it's stronger over time. So ultimately, what we see in terms of power is the future natural gas with CCS. It's very California-specific solution. You might not be seeing that in other parts of the country. And you're expecting the CPUC to address it this year and moving forward. So we're well positioned either way, but we see a significant business opportunity as we think about California power dynamics.

The next question comes from Zach Parham with JPMorgan.

I wanted to ask on the buyback first. Buybacks were relatively smaller in 1Q at $10 million, and you bought back around $45 per share. So those buybacks were done mostly early in the quarter. The stock's moved quite a bit higher since, but so is the commodity, so you're going to still generate quite a bit of free cash flow this year. Can you just talk about how you're thinking about the buyback going forward?

Yes, Zach. So the first priority for this quarter was to get the activity production back to maintenance level. And the reason for that is that, that gets us to sustainable capital returns. And that duration is what we think the investor is really looking for. And you look at the track record, $1.6 billion of buybacks over the years. So very much a part of our portfolio to be able to distribute cash to shareholders. So we continue to be very focused on that. It's just a matter of sequencing. So getting production back on track is -- was paramount, but the framework hasn't really changed since we started, right? So we want to be the company that you can own through the cycle, and that means good returns, steady returns as we go forward. So we will have to make the next decision right now that we're able to invest into a business to keep production flat, then the next opportunity to either grow from their or buy back shares or increase the dividend or ultimately accumulate more cash for that is something that we're going to have to continue to look at as we start thinking about the setup in 2027. But maybe let me turn to Clio to recap that framework and provide a little more of the specifics.

Zach, the way I'd frame it is higher prices don't really change our framework, but they do shift the mix of where capital goes with a lot of more naturally flowing towards high-return reinvestment in the base business, with us continuing to build that long-term optionality. But importantly, we're doing that within the same disciplined framework that we've held. So we're still running a sub-40% reinvestment rate on the E&P side. The business continues to generate significant free cash flow. And with our leverage that's already low, the balance sheet isn't a constraint. It gives us the flexibility to lean into those opportunities while generating meaningful excess cash. And you asked about the buybacks, and I'll take a step back and saying shareholder returns more broadly, that remains a core part of our story. We've consistently grown the dividend over the past 4 years, and that yields around 2.5%, which we think is competitive both within the sector, but also more broadly. And we'll continue to approach buybacks in a disciplined and opportunistic way. We think that's been very effective. If you look since mid-2021, we've returned via buybacks about $1.2 billion, $1.6 billion in total as Francisco was mentioning. And we executed that at a meaningful discount to the intrinsic value. So we repurchased shares at an average price of about $43.50, and that's roughly 30%, 40% discount to where you've seen trading recently. And we've been able to also keep share count relatively flat even as our production has grown about 50% over that period of time. So you've seen us lean in and be opportunistic and be effective with that tool. But even as we lean into our E&P investment, we're not stepping away from returns, we're simply delivering more. And we're really not making a trade-off here. It's a dynamic allocation. Capital flows to the highest-return opportunity, while supporting our shareholder returns and also maintaining our long-term growth options.

A follow-up I wanted to ask on the cost side. As you add back some activity, are you seeing anything on the inflation side? I'm sure you're seeing higher diesel prices have some sort of impact. But anything else you would flag from an inflationary standpoint?

Good question. I'd say at this point on inflation, it remains modest and really manageable for us within the business. So we saw minimal pressure in the first quarter. But you're right, as oil prices have moved much higher, we're starting to see some impact, primarily in oil-linked inputs. But in terms of magnitude, we're estimating that's roughly $6 million to $8 million impact this year or $10 million on an annualized basis, so very manageable. If you look at what's driving that, about 1/3 -- well, actually 3/4 is fuel related, so driven by higher costs across our field operations and logistics. And the balance of that, so 25% to 1/3, is oil-based products where we're seeing moderate supplier increases there. But it's important to note that our team, we've done a significant amount of proactive work on the supply chain side, consolidating vendors, improving procurement, leveraging scale. And that really mitigates a lot of the exposure. So altogether, I'd say the level of inflation is modest so far and it's more than offset by the structural margin improvement we're delivering across the business.

The next question comes from Michael Furrow with Pickering.

I'd like to ask about risk management. Clearly it was a volatile quarter for pricing. It looks to probably continue in the second quarter. California market dynamics only add to volatility. When you look at the business today, the balance sheet is in a much healthier position than it's been previously. So does any of the market dynamic changes alter the company's hedging strategy moving forward?

Michael, so as I mentioned before, we want to build a company that the investors feel good about owning through the commodity cycle, the ups and downs of the cycle. So we see our hedging strategy as a great tool to deliver that and to ultimately lock in attractive economics so we can execute regardless of where prices go. I'll turn it to Clio for a little bit more details on the go-forward impact.

So our hedging and our hedging program, it's really about being able to deploy capital with confidence. So it's about having the confidence in our returns in our capital program and our ability to really deliver through the cycle. It allows us to lock in attractive floor economics and also commit to higher levels of activity participate in the upside. Last quarter, we shared what the business generates at around $65 Brent, and that underpins how we think about both capital allocation and hedging. We did put these hedges in place in a different forward curve environment that was delivered at the time, protecting the base business, the capital program and the dividend and while retaining a lot of upside participation. And if you look at our portfolio, that's how it's structured today. So in '26, roughly 2/3 of our volumes participate to the low to mid-80s Brent, and about 1/3 remains unhedged. So while we do have downside protection, we're not fully capped. Higher prices do translate into stronger margins and free cash flow across a meaningful portion of our portfolio. And if you look beyond '26, that exposure increases. So there's about 40% in '27 and roughly 80% in '28 of our volumes that are unhedged. I'd say stepping back, that visibility is what has allowed us to commit to the activity levels and to the returns we're outlining today. And the objective of that hedging program hasn't changed. It's about protecting the downside while maintaining meaningful exposure to the upside.

Staying on the topic, in the first quarter, volatility weighed on the post-hedge realized pricing, or at least [ versus ] our numbers, negatively affected our EBITDA expectations. But looking forward, is that same timing dynamic that was a headwind for the first quarter act as a tailwind for 2Q?

So what you're looking at there in terms of GAAP is we're really settling our hedges on a monthly basis. And if I look at the Street, I think most analysts are doing so on a quarter basis. So an average quarterly price will not reflect what happened, for example, in Q1 where you had January and February in high-60s and then March with the high 90s. So I believe that, that's what's driven most of the delta, if not all of the delta. If you do that average quarterly price versus the month-to-month, that yields, for example, a $30 million to $40 million delta in EBITDA loan for that order. So I do think that that's something that our IR team can work to make sure that we are closely calibrated.

And the last 2 questions today will come from Nate Pendleton with Texas Capital.

Congrats on the great update. Francisco, I wanted to go back to the RCPPP potential briefly. Could you provide a bit more detail about what the next steps are for that to be implemented and how that could impact demand for your CTV [ floor ] space and perhaps even your end-state natural gas volumes? And if I may add one more part to that, with the potential program, are you already having conversations with companies trying to get ahead of implementation?

Nate, so yes, we see RCPPP as being a game changer if it passes. It's a very unique front of the meter opportunity. It's the recalibration of a grid that has been struggling to keep up over reliance on solar, wind and batteries when you really need that firm capacity to come back into play, and a state that focuses on decarbonization and reducing the carbon footprint very few ways to go and nothing really tangible other than carbon capture. So we see this as an incredible opportunity. The policy rule-making is advancing. We saw, as I mentioned earlier, call for procurement, 1.5 gigawatts of firm and clean, which really limits the pool of opportunities that we think -- I said CCS is the most tangible one. But you look at -- you step back and you look at about -- California has about 40 gigawatts of power generated through natural gas-fired generation. I assume that not all of all them will be able to be retrofitted with CCS. So our view is about 17 -- call it, 15 to 20, 17 midpoint, gigawatts, would be good candidates for retrofit, right? So you can start scaling the magnitude of the program. So we will have the ability to participate primarily in the transport and storage of CO2. But we also have the input, which is natural gas and we can grow that and have a dedicated natural gas flow of low-methane emission, very high-caliber or natural gas going in, that ultimately all goes into the calculation around carbon intensity. So we can provide a very scalable, big offering. And then we've seen progress, as a reminder, the CO2 pipeline moratorium was lifted earlier this year. So that allows us to start thinking about that transport in a much more tangible way. And then you come back to our Elk Hills project, we're at the doorstep of getting that permit from the EPA. We look at the project management dashboard, there's no red left in that dashboard, right? We're done, commissioned, we sent the samples into the EPA. They have been checked and confirmed to be adequate. So we're just waiting for that final approval. I think that is the final signal to the market that CCS is here, that we were able to clear all permits and have been able to make it to commerciality, and we see demand follow. We are having conversations. We do see a lot of interest, as the CPUC considers CCS, we see a significant uptick in those conversations on how do we get the CO2 from the point source into reservoirs. So massive front-of-the-meter opportunity, very tailored towards a California solution, a unique business model and one we're extremely well positioned on.

Perfect. And then as my follow-up on the regulatory side, it seems you have been able to navigate the regulatory and permit process extremely well with the receipt of permits for the 2026 program and already working on '27. So can you comment on how your discussions with regulators have been to open up the permitting process? And could you share your views on the ongoing governor's rate given the potential impacts to the industry more broadly?

The governor's rate, okay. Yes. On the first topic, we -- it truly is an incredible team effort from our folks in State Capital in Sacramento to our permitting team in Bakersfield. And there's been incredible progress throughout. Our view towards California is different than other energy companies. We're working to establish partnerships, to provide solutions, to be innovating alongside with the state. And that's giving us an opportunity to work very constructively with regulators and the politicians. And ultimately, our track record really to deliver projects that no one else can really puts us into a place of -- or really good placement on a go-forward basis. So really proud of what the team has been able to do. And it is a core competency. It's something that we do exceptionally well, better than most, and ultimately creates an incredible market opportunity if we continue being really good at it. In terms of the governor's rate, June 2 is the [ jungle ] primary, so the top 2 candidates regardless of the party move on to a general election in November. Ultimately, it's a fascinating dynamic with a lot of candidates that could ultimately end up as governor, so fairly open. Our view is we can work with all candidates. We support some campaigns and candidates that have a little bit more in tune with rational energy policy. We really want to focus the politicians on protecting and creating local jobs. And ultimately, we can partner and solve the affordability crisis in the state. So exciting times to have an election, and we're watching it closely. And looking for leadership that will continue to collaborate and make the state better going forward.

This concludes our question-and-answer session. I would like to turn the conference back over to Francisco Leon, for any closing remarks.

Great. Thank you, everybody, for joining us today. We look forward to seeing many of you on the road at upcoming investor conferences in the coming weeks. So thank you, and have a great day.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.