CRC

Good day, and welcome to the California Resources Corporation First Quarter 2026 Conference Call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing star, then zero on your telephone keypad. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your telephone keypad. To withdraw your question, please press star then two. 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. As a reminder, please limit your questions to one primary and one follow-up as this will allow us to get more time for your questions. I'll now turn the call over to Francisco.

Thanks, Danny. 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 the 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. CRC is ready to support all three. Today, we're moving decisively to accelerate development. We are increasing drilling cadence this summer by three rigs, two in California and one 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. 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 de-risked 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 and activity to seven rigs will meaningfully enhance our financial outlook. For the full year, we're 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 storage project at our Elk Hills cryogenic gas plant, and we expect to receive final notice of determination 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 GW of base load power generation across California that we believe has the potential to be retrofitted for CCS. We have submitted over 350 million metric tons of carbon storage capacity to the EPA, with additional reservoirs tracking for 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, we are one of the few platforms that can solve it. On the Reliable and Clean Power Procurement Program, or RCPP, we expect the next major update in the second half of 2026. Natural gas with CCS is not yet eligible, support is building, three of five CPUC commissioners have publicly endorsed inclusion. California already offers some of the highest stackable CCS incentives globally. RCPP 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. Good morning. We delivered a strong first quarter with adjusted EBITDA 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-hedge 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 increased spend was by design as we pulled forward pre-spud timing on development wells and accelerated facilities 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 five times oversubscribed and used the proceeds to redeem our 2029 notes. This extends our weighted average maturity to approximately six 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 EBITDA. 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're 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 seven 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 seven 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 five 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 Berry merger-related synergies, we have already implemented over 80% of original target and are now raising that target by 12% or an additional $10 million. That's driven by field consolidation and contractor-to-crew 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. It is the kind of outperformance we can sustain through the cycle. Cash flow per share growth, high return reinvestment, a de-risked 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. This distinction could not be more evident. Our integrated strategy is delivering on three 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.

We will now begin the question-and-answer session. To ask a question, you may press star then one on your telephone keypad. If you're using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star then two. Please limit yourself to one primary and one follow-up. At this time, we will pause momentarily to assemble our roster. The first question comes from Scott Hanold with RBC Capital Markets. Please go ahead.

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

Hey, Scott. Thanks for the question. Yeah, 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. We're gonna be drilling a total of about 357 new wells and sidetracks for the year. Happy to report that we have all permits for all seven rigs now on hand and are working on our 2027 plan. Not only that, our permits flowing, but the process overall is getting better.

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. 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. We can try to connect to a window of price opportunity and deliver incremental production that way. We're lining the incremental rigs to be ready in the summer and start producing early in the second half of the year.

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 type 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.

You look at gross in terms of being able to measure that efficiency. 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. The really exciting thing that we're seeing come through as our team is executing, is that we're staying flat with less rigs. The improvement on capital efficiency has been significant. Let me turn it to Clio to highlight the capital efficiency and the returns of the program as well.

Thanks, Francisco, and hi, Scott. Really on the efficiency point, the comparison here is really compelling. On how much our program has improved relative to what we outlined just last quarter. We had talked about the seven-rig program with about $485 million of D&C and workover capital that would be needed to hold production flat next year, so in 2027. Today, what we're outlining is we're delivering that flat to modest growth with roughly five rigs throughout the year and under $400 million of D&C and workover capital. 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. Most importantly there, that improvement is also showing up in our returns profile.

At 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. Three things really. Well economics, cost structure, and portfolio sequencing. 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. Third, sequencing and timing here. We're simply deploying capital more efficiently across the year and across a broader portfolio. This isn't just one lever, it's a multiple of improvements compounding at the same time. As you think about our activity increase here, Scott, the key is that it's tightly price-gated.

We remain capital disciplined at current strip free cash flow before working cap. That is expected to come in above $800 million this year. We're also anchored to long-term pricing rather than near-term spot. At around 65 Brent, our four rig program was fully supportive and generates strong returns. Each incremental rig from there, that requires roughly $5 Brent increase in long-term pricing to maintain those returns. What effectively does here is create a clear decision framework internally. Every step up in activity has to meet our returns threshold. Even in a stronger tape that we're seeing today, we're not chasing volume. We're scaling only where returns justify it.

As you move towards six rigs in California, we're underwriting that against something closer to a $70 or $75 Brent long term, which is broadly where the strip sits today. Tying back to what Francisco was mentioning earlier, that framework, it's really enabled by the flexibility in the program. We can adjust activity quickly without putting really the base at risk. Key takeaway here, Scott, is it isn't a change in strategy, it's stronger execution and better economics.

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

Yeah, Scott. We're still in the evaluation stage of Utah. We have four wells that we wanna drill before the end of the year. We have, when we acquired Berry, we booked about 200 locations in. 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. Ultimately, we're looking to unlock the best value. The way to think about it going forward beyond the four rigs is we are considering full development, but we're also considering monetization. You know, I'd say we are not in the holding pattern anymore. We're gonna 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 that 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 that Uinta will provide that. The nice thing for us is we attributed very low value to Utah in the Berry acquisition, so that leaves us with meaningful upside to unlock that best value. More to come. For now, four rigs, we're still evaluating. Sorry, four wells, not four rigs.

The next question comes from Betty Jiang with Barclays. Please go ahead.

Hi, team. Thank you for taking my question. I want to start first on the upstream and maybe unpack a bit on the capital efficiency improvement and that you're seeing in 2026 and how that's impacting 2027. 2026 guidance is a bit noisy just with the PSC effects. 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. I'm wondering how much of the 2026 investment is going to show up in growth in 2027.

Then just on the CapEx side as well, is it fair to say that if you are at five rigs this year growing on a lower CapEx, is maintenance CapEx now lower than the $485 million before?

Yeah, Betty. Thanks for the question. It is early to guide and to start locking in 2027. 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, seven 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. However, as Clio said, a lot of flexibility, and we can adapt to market conditions. From a planning perspective, we see seven rigs as what we wanna invest in given the quality and duration of our inventory.

So in terms of the investment that we're making now, yes, in conventional assets, you will see the shape of the wedge that peaks. This year we invest, we peak next year, right? A lot of the investment that we're making is not for 2026 exit, it's really for the benefit of 2027. In having a view towards the long-term price curve and seeing, also with our strong hedge book, that gives us confidence to deploy capital thinking into 2027. Ultimately, seven 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.

We have a great portfolio, different mix of wells, different commodities that we can go after. I would not assume that we would retain the split of six in California and one in Utah. That's still to be determined. A total of seven rigs is what we think as the long-term guide on baseline investment for the business.

Great. That's helpful. For my follow-up, I wanna 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. Just how are the conversation going in general to move a project forward?

Yeah, Betty, thanks for the question. We're making really good progress. We have previously discussed the concept of land now, which means it's land that's permitted, it's powered, it's shovel-ready, co-developed and ultimately adjacent to our Elk Hills facility. 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. 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.

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, you know, 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. 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. You know, we've developed a very strong core competency in being able to navigate the California regulations. We've done it with oil and gas effectively.

We've done it really well with carbon capture. Now we're gonna do the same thing with data centers. Our partner is adding a lot of value in that design in anticipation of what hyperscalers need. It's a real and exciting project we're developing. You know, 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. Please go ahead.

Yeah, thanks. Hey, guys. Nice update on the Berry synergy front here. You know, I like that you guys give the three 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?

Hey, Josh. Yeah, 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 a cumulative target of $460 million of annual synergies between Aera and Berry. The trajectory, the trend is all going very well. Why the race in OpEx? I'll give you a couple of examples. Our team is doing a fantastic job in field consolidation. 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. That's going really well, probably better than anticipated. We also have a big opportunity for automation.

Both Aera and CRC were much stronger in automation than Berry, 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 to talk about more of the specifics, 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 same efficiencies, those impacts are not quantified yet in our numbers, right? There is some upside, assuming technology advancement and implementation works. Everything else we're really doing is more physical, movement and placement of facilities alongside with, reductions in D&A. I'll turn it to Clio to provide a little more context on the synergies.

Thanks, Francisco. 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. 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 the mid-single digits, and more recently, we've seen deals trend even lower. This is clearly a differentiated outcome, and importantly, it's consistent with what we delivered on Aera. We view this as a repeatable playbook for us. On the trajectory, we're largely through a lot of the action items.

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 target. 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 half a billion of cost reduction. I'd say the remaining synergies that we're looking for are less about those one-time actions now and more about continuous improvement of the business. 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 our EBITDA is growing ahead of the commodity price rise.

Got it. Thanks for that. I was hoping to shift over towards the power business for you guys, and 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 definitely being integrated with other parts of the business, but how are you thinking about this? Maybe just kind of a broader overview of what you're seeing in the California markets. Thanks.

Yeah. You know, California is fascinating in the, you know, 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. 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 in the geology, and their 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. That puts a scarcity premium on the capacity that's already tied to the grid. Having those assets, it's very meaningful.

We have close to 1 GW of power under our portfolio. We're seeing some regulatory improvement. The CPUC just started the procurement process of 6 GW of new clean capacity by 2032. What we really like to see is that 1.5 GW of that is clean and firm. That's the energy that we can provide, right? Always on, dispatchable, zero emissions. These are solar and batteries can fill that. It's gas, natural gas with CCS. You know, 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 flooding the market. This new clean, firm requirement re-creates a structural demand for what we operate.

The resource adequacy pricing is expected to follow and get stronger over time. Ultimately, what we see in terms of power is the future is 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. 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. Please go ahead.

Hey, thanks for taking my question. Wanted to ask on the buyback first. Buybacks were relatively smaller in 1Q at $10 million, and you bought back around $45 per share. Those buybacks were done mostly early in the quarter. The stock's moved quite a bit higher since, but so is the commodity. You're gonna 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?

Zach. You know, the first priority for this quarter was to get the activity production back to maintenance level. The reason for that is that that gets us to sustainable capital returns. That duration is what we think the investor is really looking for. You look at a track record, $1.6 billion of buybacks over the years. Very much a part of our portfolio to be able to distribute cash to shareholders. We continue to be very focused on that. It's just a matter of sequencing. Getting production back on track was paramount, but the framework hasn't really changed since we started, right?

We wanna be the company that you can own through the cycle, and that means good returns, steady returns, as we go forward. 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 there or buy back shares Or increase the dividend or ultimately accumulate more cash for debt is something that we're gonna have to continue to look at as we start thinking about the setup in 2027. Maybe let me turn to Clio to recap that framework and provide a little more of the specifics.

Thanks, Francisco, and hi, Zach. The way I'd frame it is higher prices don't really change our framework, 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. Importantly, we're doing that within the same discipline framework that we've held, we're still running a sub 40% reinvestment rate on the E&P side. The business continues to generate significant free cash flow. 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 a meaningful excess cash. You asked about the buybacks, I'll take a step back and say in shareholder returns more broadly, that remains a core part of our story.

We've consistently grown the dividend over the past four years, and that yields around 2.5%, which we think is competitive, both within the sector but also more broadly. 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. We executed that at a meaningful discount to the intrinsic value. We repurchased shares at an average price of about $43.50, and that's roughly 30%-40% discount to where we've been trading recently. We've been able to also keep share count relatively flat, even as our production has grown about 50% over that period of time.

You've seen us lean in and be opportunistic and be effective with that tool. Even as we lean into our E&P investment, we're not stepping away from returns, we're simply delivering more. We're really not making a trade-off here. It's a dynamic allocation, capital flow, so the highest return opportunity while supporting our shareholder returns and also maintaining our long-term growth options.

Thanks, Clio. 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 a inflationary standpoint?

Zach, good question. I'd say at this point on inflation, it remains modest and really manageable for us within the business. We saw minimal pressure in the first quarter. You're right, as oil prices have moved much higher, we're starting to see some impact primarily in oil-linked inputs. In terms of magnitude, we're estimating that's roughly $6 million-$8 million impact this year or $10 million on an annualized basis, very manageable. If you look at what's driving that, about a third, well, actually three-quarters is fuel-related, driven by higher costs across our field operations and logistics. The balance of that, 25% to a third is oil-based products, where we're seeing moderate supplier increases there.

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. 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. Please go ahead.

Hi, good afternoon. Thanks for taking our questions. I'd like to ask about risk management. Clearly it was a volatile quarter for pricing. It looks to probably continue into the second quarter. You know, California market dynamics only add to volatility. But when you look at the business today, you know, the balance sheet's in a much healthier position than it's been previously. Does any of the market dynamic changes alter the company's hedging strategy moving forward?

Hey, Michael. As I mentioned that 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. We see our hedging strategy as a great tool to deliver that and to ultimately lock in attractive economics, we can execute regardless of where prices go. I'll turn to Clio for a little bit more details on the go-forward game plan.

Our hedging program, it's really about being able to deploy capital with confidence. It's about having the confidence in our returns, in our capital program, in 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 and 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 deliberate at the time, protecting the base business, the capital program, and the dividend, and while retaining a lot of upside participation. If you look at our portfolio, that's how it's structured today. In 2026, roughly 2/3 of our volumes participate to the low to mid 80s Brent, and about a third remains unhedged. 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.

If you look beyond 2026, that exposure increases. There's about 40% in 2027 and roughly 80% in 2028 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. The objective of that hedging program hasn't changed. It's about protecting the downside while maintaining meaningful exposure to the upside.

Thanks for that. Staying on the topic, in the first quarter, volatility weighed on the post-hedge realized pricing and at least for our numbers, negatively affected our EBITDA expectations. Looking forward, does that same timing dynamic that was a headwind for the first quarter, act as a tailwind for 2Q?

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

The last two questions today will come from Nate Pendleton with Texas Capital. Please go ahead.

Good morning. 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 pore space and perhaps even your in-state natural gas volumes? 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?

Hey, Nate. Thanks so much for the question. Yeah, 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's been struggling to keep up, over reliance on solar, wind, and batteries when you really need that firm capacity to come back into play. A state that focuses on decarbonization and reducing that carbon footprint, very few ways to go, and nothing really tangible other than carbon capture. We see this as an incredible opportunity. The policy rulemaking is advancing. We saw, as I mentioned earlier, call for procurement 1.5 GW or firm and clean, which really limits the pool of opportunities.

We think, like I said, CCS is the most tangible one. You know, you step back and you look at California has about 40 GW of power generated through natural gas-fired generation. Assume that not all of them will be able to be retrofitted with CCS. Our view is about 17, call it 15-20, 17 midpoint gigawatts would be good candidates for retrofit, right? You can start scaling the magnitude of the program.

You know, 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, you know, methane emission, very high caliber or natural gas going in. That ultimately all goes into the calculation around carbon intensity. We can provide a very scalable, big offering. We've seen progress. As a reminder, the CO2 pipeline moratorium was lifted earlier this year. That allows us to start thinking about that transport in a much more tangible way. You come back to our Elk Hills project. You know, 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. We commissioned. We sent the samples into the EPA. They have been checked and confirmed to be adequate. 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 consider CCS, we see a significant uptick in those conversations on how do we get the CO2 from the point source into our reservoirs. 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. Thanks for that detail. Then as my follow-up on the regulatory side, it seems you've 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. Can you comment on how your discussions with regulators have been to open up the permitting process? Could you share your views on the ongoing governor's race, given the potential impacts to the industry more broadly?

The governor's race. Okay. Yeah, on the first topic, you know, we, it truly is an incredible team effort, from our folks in the State Capitol in Sacramento, to our permitting team in Bakersfield. There's been just 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. That's given us an opportunity to work very constructively with regulators and politicians. 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. Really proud of what the team has been able to do.

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 race, June 2nd is the jungle primary, the top two 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, fairly open. Our view is, you know, 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 wanna focus the politicians on protecting and creating local jobs.

Ultimately, we can partner and solve the affordability crisis in the state. 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. Thank you and have a great day.

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