California Resources Corp Aktie

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 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. And 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. 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 seven 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 storage project at our Elk Hills cryogenic gas plant, and we expect to receive final notice of the 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 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 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, 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-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 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 that 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 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 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-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, 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 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.

[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 seven 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 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. 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 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.

And 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. 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, three 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 spot.

So at around $65 Brent, our four rig program was fully supportive and generates strong returns. And each incremental rig from there 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 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.

And 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. 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 four 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 four 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, four rigs. We're still evaluating. Sorry, four wells, not four rigs.

The next question comes from Betty with Barclays.

I want to start first on the upstream and maybe unpack 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 five 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 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. Have, as Clio said, a lot of flexibility and we can adapt to market conditions, but from a planning perspective, we see seven 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 exit, 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 as 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 co-developed and, ultimately, 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 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?

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 Aera and Berry. So the trajectory, the trend is all going very well.

So why the raise 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 Aera 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 to 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 same 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 Aera. 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 one-time 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 definitely 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 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. 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 flooding 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 get 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 there 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.

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 we've been 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 game plan.

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 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 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, and at least for us, our numbers, negatively affected our EBITDA expectations. But looking forward, does 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 the 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 alone for that quarter. 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 two 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 pore space and perhaps even your in-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 race given the potential impacts to the industry more broadly?

The governor's race, 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 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 race, June 2 is the jungle primary, so 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, 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.

Good day, and welcome to the California Resources Corporation Fourth Quarter 2025 Conference Call. [Operator Instructions] Please note that 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 California Resources Corporation's fourth quarter and year-end 2025 conference call. Following prepared comments, members of our leadership team will be available to take your questions. By now, I hope you 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 and 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 allows us to get to more of your questions.

I'll now turn the call over to Francisco.

Thank you, Daniel, and good morning, everyone. I'll begin with our 2025 results, then highlight what different CRC today. Including our unique position in California's energy and decarbonization landscape and how that translates into long-term value creation. I'll then turn it over to Clio for the financials and 2026 guidance.

Let me start with the big picture. In 2025, we grew production for the third consecutive year, delivered record financial performance and return record capital to shareholders. Even as commodity prices declined 14% year-over-year. Our guidance shows further annual production growth in 2026. Our high-quality, low-decline conventional assets generate stable cash flow, supporting annual capital returns, while maintaining balance sheet strength. Since 2021, we have returned nearly $1.6 billion to shareholders, underscoring our commitment to long-term value creation.

Our capital priorities remain clear: invest in high-return opportunities, preserve financial strength and return excess cash to shareholders. We will continue to take a measured and disciplined approach to shareholder returns, maintain the flexibility to invest through the commodity cycles. As we enter 2026, CRC stronger and more resilient with a differentiated asset base and improved access to the full depth of our reserves, positioning us to grow cash flow per share.

Three factors define CRC today. First, our conventional reservoir base is a core strength. These assets are characterized by low natural declines, strong recovery factors and very predictable performance. That allows us to sustain production with less capital and lower risk than shale-focused peers. Our expanded 2P disclosure of nearly 1.2 billion Boe, highlights the depth and longevity of our inventory, supporting 20-plus years of development at current production levels.

Our assets are large scale, low decline, multi-stack sandstone reservoirs. Conventional systems where production is sustained through reservoir injection management and long-duration recovery, requiring low capital intensity without the need for the continuous high-intensity reinvestment. Notably, we see a similar recovery potential in our Belridge field compared to Elk Hills. But at an early stage of development, reinforcing the strong industrial logic behind the Aera merger. While many peers are looking to new basins and international opportunities to extend reserve life. Our deep inventory provides confidence in the long-term durability of our production and cash flows right here in California.

Second, regulatory progress has been meaningful. The resumption of new drill permitting and the steady flow of approvals through the system represent a step change from where we've been in recent years. We appreciate the efforts of state and local regulators to move this process forward. This progress positions us to stabilize production while supporting the state's objectives for energy affordability.

We now have the majority of the permits required to execute our 2026 capital program, which materially expands our flexibility to plan, sequence and high-grade capital across the portfolio. Importantly, it also allows us to adjust activity levels methodically as market conditions and returns dictate. We have returned to drilling new wells in 2026 and see ample potential across our long runway assets.

Third, our integrated strategy continues to differentiate CRC. We're investing in high-return oil and gas developments, while advancing our carbon management and power platforms in a capital-efficient and return-driven manner. Carbon TerraVault has moved from concept to execution. Construction is complete on California's first commercial scale CCS project at Elk Hills, and we're now in the commissioning and testing phase. We have successfully captured CO2 from our gas processing plant and are awaiting final EPA approval to commence injection.

We believe each step in the process materially derisked the platform. from engineering and construction to capture performance to regulatory clearance and positions us to transition into full operations. Importantly, the proximity of our permitted CO2 storage reservoirs to existing infrastructure across the street, provides a structural advantage as demands grow for reliable, low-carbon power solutions. We continue to advance discussions related to our power platform with multiple high-quality counterparties. The demand signal is evident, but these are large complex transactions in a market that is still maturing. As it evolves, commercial structures are improving, and our options continue to expand.

We have strong conviction in the value of our integrated power to CCS offering. We're not focused on speed. We're focused on getting the fundamentals right and securing the right agreement at the right time, one that appropriately aligns risk and returns and delivers durable long-term cash flow. As the market matures, we believe our differentiated position only strengthens.

So what does this all mean for CRC as we look ahead for the long-term? What defines us is durability of inventory and returns. We're investing in 2026 from a position of strength. With 2027 marking the point where we returned to a steady-state level of activity to sustain production. On a hedge basis, our corporate maintenance breakeven sits in the mid-50s WTI, providing resilience in the range-bound oil macro. This reflects the full enterprise, including upstream operations, Carbon TerraVault, power, base dividend interest, corporate needs and hedges.

For context, our upstream-only maintenance breakeven is in the low to mid-50s WTI among the more competitive levels across pure-play E&P tiers. This outlook is grounded in asset quality, inventory depth and structural cost discipline, not aggressive capital assumptions or optimistic pricing. Together, our reservoir base improved regulatory visibility and integrated strategy support resilient long-term value across cycles.

With that, I'll turn it over to Clio to walk through our financial results and 2026 guidance. Clio?

Thank you, Francisco, and good morning. The fourth quarter capped a record year for CRC. We delivered on our financial and operational targets, while further strengthening the durability of our business. In the fourth quarter, we generated adjusted EBITDAX of $251 million and free cash flow of $115 million, including 14 days of contribution from Berry. Net production averaged 137,000 barrels of oil equivalent per day with oil realizations at 97% of Brent before hedges.

For the full year, we generated nearly $1.25 billion of adjusted EBITDAX and $543 million of free cash flow, the highest level since 2021. Results were driven by strong base performance, structural cost reductions, realized synergies and higher-than-average resource adequacy payments from our power assets. Net production increased 25% year-over-year to 138,000 barrels of oil equivalent per day, reflecting consistent capital execution and value accretive transactions.

Fourth quarter capital spending totaled $120 million within guidance, bringing full year capital deployment to $322 million. Capital allocation remained returns-focused throughout the year. In a permitting constrained environment, we directed investments towards our highest drilling opportunities and returned excess free cash flow to shareholders. The dividend continues to anchor our returns framework, and we have grown it meaningfully since 2021.

In 2025, we returned approximately 94% of free cash flow to shareholders through dividends and share repurchases. Given the permitting constraints last year, repurchasing shares represented an attractive use of capital and enhance per share cash flow. The Board recently approved a $430 million increase to our share repurchase authorization and extended the program through 2027, bringing remaining capacity to approximately $600 million.

As we enter 2026, we began receiving new well permits, as a result, a greater share of our capital will be directed toward high-return reinvestment opportunities that support sustainable production and cash flow growth. This framework reinvesting at attractive returns, while maintaining a strong balance sheet and a durable dividend remains central to our capital allocation philosophy.

Turning to the balance sheet. We exited the year at 1x leverage with total liquidity of $1.4 billion. During the year, we completed a refinancing transaction associated with the Berry merger. Redeemed our 2026 senior notes, expanded lender commitments and received improved outlooks from the rating agencies. Collectively, these actions enhance financial flexibility and reduce our cost of capital.

Looking ahead to 2026, our guidance reflects a measured capital deployment ramp-up and resilient cash flow generation. At $65 Brent, we expect to generate approximately $1 billion of adjusted EBITDAX supported by lower costs and ongoing synergy capture. These efficiencies position us to sustain strong margins, despite lower commodity price assumptions and a softer resource adequacy market.

We expect capital spending at roughly $450 million. Drilling, completions and workover capital is projected at the $280 million to $300 million range, supporting a 4 rig program. Our development plan is grounded in decades of production history and consistent performance, and we retain flexibility to adjust activity levels as the year progresses.

Net production is expected to increase 12% year-over-year to 155,000 barrels of oil equivalent per day at midpoint of our guide, with oil representing roughly 81% of volumes. 2/3 of our expected oil production is hedged at $65 Brent, providing meaningful cash flow protection. We enter 2026 with a stronger balance sheet and expanded inventory of high-return projects and improved visibility into sustainable production and cash flow growth.

With that, I'll turn it back to Francisco for closing comments.

Thanks, Clio. As we look to 2026 and beyond, our priorities are clear. We're focused on responsibly developing our deep, high-quality resource base, lowering cost, maintaining our balance sheet and effectively allocating capital. We will continue to advance platforms that will shape CRC's future.

Carbon TerraVault and our power strategy are moving from concept to execution and are expected to contribute to a more durable, diversified cash flow profile over time. CRC plays an important role in California's energy future. Our locally produced oil and gas, combined with scalable carbon management and power solutions, position us to help meet the state's affordability needs, while advancing emission reduction goals. As California's demand for secure, lower carbon energy evolves, we see our integrated model as part of this solution.

Operator, we're now ready for questions.

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

I was hoping if you could provide some added context on your 2P inventory update and maybe talk to see how that -- talk to that relative to how you see permitting -- the permitting environment moving forward? And also speak to the duration of that inventory to hold your production flat.

Scott, thanks for the question. Really appreciate you leading with this question. Important that we convey in the potential of the business. And I have a few things to say. So we have a great foundation. That's well known. Conventional assets with low declines, repeatable inventory. We actually have really good rock that actually flows. It's an asset base that's been built to outperform through any cycle.

But really 3 things to highlight. The -- in terms of the runway, the inventory, as I said in my remarks, we have permits in hand to execute 2026. We're building line of sight into 2027. So now that permitting is back to normal cadence, that allows us to put the focus on the resource. And we grew our 1P reserves, 350% reserve replacement ratio on the back of the permits coming in, stronger-than-expected base decline and the Berry acquisition.

And if you look at the value of the 1P reserves alone, that's about $9 billion at SEC prices. But what really stands out is the running room beyond that. We said we have 23 years of inventory of 2P basis -- on a 2P basis in our disclosure. We operate about 4 of the largest oil fields in the U.S. You can add 3 more, so 7 have each well in place that exceeds 3 billion barrels of oil in place. And these are fields that have been producing for decades and have many, many decades ahead.

Recovery factors of 40% plus on waterfloods, 75% plus on steamfloods. And that just tells you some of that gives you a sense of how much resource remains to be captured. But on top of the resource, we also have very low subsurface risk that makes capital allocation very predictable. We have a lot of well control across all of our acreage. A lot of our production is about 2,000 feet deep, so very shallow. We have a lot of data that helps us derisk every dollar that we deploy. A lot of the activity that we have on new wells is infill drilling. So low geological risk. And as technology continues to help us improve our lower base decline, we have a very repeatable capital-efficient program that we can execute with confidence.

Finally, I would like to highlight, it's truly an opportunity set with stacked optionality and returns. We have thousands of feet of stacked pay across multiple producing horizons, 2 million acres of minerals, 89% on average working interest, which means really strong netbacks.

As I highlighted in my remarks, Belridge is probably the best example. We look at Belridge in terms of development as we saw Elk Hills about 20 years ago. So extremely long runway, low risk. And one of the highlights of Belridge is it's less than a 5% royalty burden. So amazing netbacks and really excited about the setup that we have for the company going forward.

I think you had a second question?

Yes, yes, absolutely. I appreciate the context. And as you -- and just staying on kind of a similar theme, if you step back and think about 2026 program, it looks like 4Q flattens. I'm just wondering, is that a good forward rate to utilize for that building the maintenance of '27? And also maybe a little bit about the capital efficiency. That appears to have improved as well. So any color there? And I don't know if it's the type of wells you're drilling or what other factors might have helped the capital efficiency.

Yes. We're extremely proud of the work the team has done to improve the capital efficiency. We've seen tremendous progress year-over-year and continue to work on it.

So I'll turn it to Clio to highlight -- to give some of the highlights around efficiency and the well mix.

Thanks, Francisco. Scott, yes, so on our '26 program, it's really designed to materially reduce our corporate decline to roughly 2%. So as you alluded, it really equates to 0.5% glide path quarter-over-quarter. That's effectively flat production throughout the year, while generating substantial free cash flow.

And so we're operating 4 rigs. We're deploying $280 million to $300 million of D&C and workover capital to support that production on a materially larger asset base. The program is intentionally weighted towards lower risk development. It's really focused on PUD inventory. And we've got roughly 2/3 of our activity on sidetracks and 1/3 on new wells. That's all supplemented by a very robust workover program. And the sequencing here is deliberate, more sidetracks and workovers in the first half, and then we transition into new wells as permit inventory builds here throughout the year.

So a couple of points. We're reinvesting less than 50% of cash flow. We're maintaining our leverage around 1x. You're really seeing a disciplined capital allocation at work here. And you were asking, Scott, around our capital efficiency. We will think about it through 2 lenses. So on project level returns, but also on corporate capital intensity.

If I start with our project level returns, our '26 program, it's highly competitive on a stand-alone basis at $9 per Boe of development cost. The program generates just shy of 4x multiple on invested capital. It generates mid-40% returns at $65 Brent and roughly a 3-year payout. The portfolio is also oil weighted. It's 90% oil weighted, which supports strong cash margins here and durable economics across the cycle. So those metrics reflect the quality of our inventory that Francisco was highlighting and also the structural improvements that we've captured over the past several years.

If you take a step back and look at the corporate level, the impact of the Berry integration here is clear. What's most notable is that we're delivering this very low decline on a materially larger portfolio without increasing our structural capital intensity. We absorbed here roughly 25,000 Boe per day of incremental production with Berry, while managing to hold the combined business at 2% decline with no increase in our capital and no increase in our rig count versus our early November guide, and that was built in a much smaller footprint without Berry.

So that's a meaningful demonstration of our improved capital efficiency and our integration synergies. We're generating the strong marginal returns on our new capital, and we're also lowering the capital required to sustain the broader base. And that combination really supports our durable free cash flow generation.

The next question comes from Betty Jiang with Barclays. .

Congrats on a very strong finish to 2025. Shifting gears a bit to the other growth opportunities in the portfolio, maybe starting with the CCS business. Can you speak to the remaining approval process needed to start injection at the cryogenic gas project?

And maybe more broadly, as the CCS, the carbon capture business is finally moving into execution, what are the key milestones you are targeting this year from a business development or permitting perspective?

Betty, thanks for the compliments. And yes, in terms of our CCS business, really good progress, and we are near the finish line to deliver a fully integrated end-to-end capture to storage solution. Construction is complete, commissioning and final approvals are underway. We have successfully captured our first CO2 from the plant to running it to the amine system. And we're working closely with the EPA through the final operational readiness and compliance steps.

We're excited. This first injection is really a big derisking of the CCS business model and really brings a lot of confidence to the business that we're building. As we wait for market adoption, and there's many moving parts to it, but it's coming quickly, being able to have decarbonized molecules and electrons in California is what we think wins the day. We have a state requirement under cap and invest to 2045 to decarbonize. So we're bringing a market solution that may be very different from whatever else is happening in the rest of the country.

We continue to see progress from our team in terms of permits. We just filed CTV [indiscernible] with the EPA. That's another 27 million tons of capacity. It's adjacent to CTV I. So it's bringing the hub concept into that Elk Hills area to accommodate higher growth, which we expect. 2026 will also be a year where we see a lot of the permits in the queue that we filed 2, 3 years ago starting to come in the form of draft permits coming forward.

So overall, really good progress, really exciting proof point to be able to decarbonize our gas processing plant, but there's a lot more to go and excited to share the news as it comes, but 2026 is a big year for us.

Great. Sounds great. And my follow-up is on the power to CCS opportunity. On Slide 11, Francisco, you alluded to the hub concept of you have multiple power plants that's sitting all on top of a growing carbon storage. The -- can you just expand on what are you seeing in the market on that front? What do we need to see from the market in terms of demand or other maturations to crystallize this opportunity for CRC?

Yes, Betty, it's clear now that the industry that's going to lead the efforts to decarbonize is the electricity sector, the utility sector. And in California, in particular, that's going to be a requirement in order to be able to build data centers, in order to be able to source incremental demand, we see it as being -- having to be decarbonized.

Now we missed out in California from the first wave of data center growth, which is more focused around training. Pretty obvious, we have high power prices here in California, so not the best place to site training data centers. But we're really excited about the second wave that's coming through inference and edge compute, where you really have to be close to the user.

So if you look at the map, Elk Hills power plant, CTV I, CTV VII now are right at that intersection of 2 of the most attractive use cases for content, for virtual gaming. So whether that's -- it's Los Angeles, Las Vegas, these are where we see this very high demand center. So it's a very compelling outlook as we look out into the next few years.

So the things that we've done to date, which some of them we highlighted, some of them are new is, first, we wanted to have this power now concept that allows a customer data center more than likely to be able to look at scale. And the scale comes initially from our Elk Hills power plant, but also from the partnership that we made with power plants around our site.

We've highlighted La Paloma, we've highlighted Sunrise, overall, 2 gigawatts of portfolio that ultimately you can scale the data center to. A more recent update is we've been advancing the -- what we call the Land Now concept, which is permitted and powered land. We're working closely with a leading data center developer. We're in early stages of design and permitting together. We think this is going to be the most compelling and exciting site in California to build a data center. So making good progress along those lines.

And as you have line of sight to permits, as you have line of sight into a data center build-out, the hyperscalers we're picking up more and more interest on people that want to establish a foothold into the California market.

The injection of CTV I is also an important milestone by being able to take CCS from a concept to a clean hourly matched energy offering in the PPA negotiation really becomes a differentiator with the rest of the state that's solely relying on renewables and batteries.

So putting all these things together, so power at scale, site design and permitting and a CCS derisked opportunity is what we ultimately think will be the best path to create durable contracted cash flows and ultimately a good way to unlock shareholder value. So we're making really good progress.

The next question comes from Zach Parham with JPMorgan.

First, just wanted to ask on cost reductions and your confidence in the Berry synergy capture. In the slide deck, you've got an interesting slide that shows incremental cost reductions going out to the 2027, 2028 time frame. Can you just give us a little bit more color on what's driving those continued cost reductions?

Thanks, Zach. Really appreciate the question. So we're applying the same integration playbook to Berry as we did with Aera. We're simplifying. We're standardizing and integrating the business. As we've announced, we have -- we're targeting about $80 million to $90 million of synergies. We were able to close the Berry merger earlier than expected. So we're right now in full execution mode.

The areas of focus are around field efficiencies, overhead redundancies, leverage on supply chain, but we also now have the ability to optimize well services through our C&J company. So that on top of the refinancing that we did last year, these are all very controllable, high confidence levers that we're going to be able to pull.

Ultimately, we still feel good about that $80 million to $90 million. But what's been really impressive to watch as you step back and that's the point of the slide is that we're on a glide path to about $0.5 billion of cumulative structural savings between our 2 deals.

So I'm going to let Clio go through some of the details, but the track record of this team, our operations team, in particular, has been outstanding in terms of achieving those synergies and getting to a lower cost structure for the future. But Clio, do you want to take it away?

Thanks, Francisco. Zach, yes, so our synergy and our cost reduction journey, if you look at that graph that we shared with you all, since 2023, we've delivered $300 million of structural cost reductions, and those are primarily driven by the Aera integration. That was around $235 million, and we achieved those ahead of schedule.

What's most important is that those savings are durable. They came from our field level operating improvements from the infrastructure rationalization exercise, our workforce consolidation, of course, the centralized procurement as well as our system integration. So these are really permanent changes to how we operate. They're not service cost deflation or temporary timing benefits here.

It's also worth noting that these savings were realized during a period of permitting constraints and industry cost inflation. So we've already been tested here. We've tested those in a challenging operating environment, which reinforces the durability point.

Scale matters in our business. We're now operating at a scale where procurement, infrastructure and field operations, those can be optimized in ways that were not available to us historically. And that industrial scale advantage it's really now embedded in our cost structure. So as a result of all these actions we took, our current run rate total operating expenses, those are $550 million lower than the pro forma premerger baseline. And that's not incremental optimization. That really is a structural reset of our cost base.

And Francisco mentioned the path. We're on that path. We're targeting $450 million of cumulative savings by year-end '28. And I'll add that that's a meaningful portion for CRC. That's getting close to 10% of our market cap in 5 years. So we are really well on our way to execute that target of $0.5 billion. And if you look at it, that's 80% already executed or action. So excited to see the new and improved CRC.

For my follow-up, I wanted to ask on how you're thinking about capital allocation over the longer term. You mentioned getting back to a steady state in 2027. But how do you think about maintenance versus potential production growth and balancing those versus free cash flow generation?

Yes, Zach. So we're certainly dealing with a lot of volatility in the commodity prices, and we want to have a disciplined outlook to growth. That's whether the markets are running hard or pulling back. We're really building this company that works well throughout the cycle, right? It's a commodity business. You'll have those ups and downs, but we -- predictable returns, predictable cash flows is what we're after.

So we're really trying to stay very flexible. And the way we're thinking about the year, we've been running 4 rigs since the beginning of the year. we're thinking about what incremental activity would be that ultimately gets us to from about a 2% year of -- entry to exit decline to more of a flat steady state, and that's going to require more activity. So we've been thinking about that incremental FIB rig. Certainly, there's a lot of things to think about what's happening in the geopolitics today, but we have a lot of flexibility to increase activity.

And that comes not only from the running room that we talked about, the inventory, the projects are there. We also control 100% of all of our fields we operate, all of them and we have all the services and rigs that we need for the year. So it's really a matter of timing and when can we get delivered those high returns for the investor. We invest to make high returns, not invest to keep production flat, right? So if we see high returns, it's the opportunity to lean in.

Maybe I'll let Clio talk about more of the go-forward plan in 2027 and beyond.

Yes. Thanks, Francisco. So when we look at beyond '26, we've outlined what a maintenance framework would look like. That's holding production flat at the '26 exit rate, and that would require 7 rigs and about $485 million of D&C and workover capital. So that's approximately 20% less capital than legacy CRC needed to sustain a similar production level and a real meaningful improvement there.

And at that activity level, our oil and gas breakeven is about $58 Brent, or $54 WTI. If you look at it on a fully burdened corporate basis, so that includes power, carbon management, corporate costs and the dividend, that corporate breakeven is roughly $60 Brent. And that's an important point. A $60 Brent breakeven reflects a structurally more resilient business, one that can sustain flat production, fund the dividend and preserve balance sheet strength. And of course, above that level, we generate incremental free cash flow.

One thing I'd like to add as well is operating within a maintenance framework, that doesn't mean static economics. We continue to see opportunities to structurally lower our breakeven over time through the Berry integration, through incremental capital efficiency gains and also through portfolio high grading. So as those improvements take hold, the capital required to hold that production flat should decline. And our objective really remains straightforward. It's durable cash flow, resilient margin and our sustainable returns through the cycle here. So we're excited about the breakeven progress.

The next question comes from Kalei Akamine with Bank of America.

My first question is on gas. So just kind of looking at the screen, very low natural gas in California is trending below hub. Wondering if low natural gas is a net benefit at the operating level, noting that you guys sell and consume natural gas. And as you prosecute this year's drilling program, wondering if there's going to be a gas production benefit that could emerge when that could help begin insulating operating costs, especially at the acquired assets?

Kalei, thanks for the question. So as a reminder, California is -- we think about it as an energy island, very regional market. You see sometimes the movements of gas price in California that are in the same direction as Henry Hub, but they're not really very well correlated. So ultimately, what you have to look at is the specific California dynamics.

First of all, we bring, we import a lot of our gas, a lot of it from Texas and the Rockies. So we're literally at the end of the pipe or price takers as a state. So then you look at what are the underground conditions and what's local demand, what's the storage, what's the capacity on the gas pipes moving gas West.

And right now, those storage levels, in particular, are very -- are elevated. They're high. The weather, there hasn't -- there's been kind of tempered weather for the last few weeks. So the build-out of hydro and battery continue to add and that puts pressure on natural gas. So that's why you're seeing a dip in those realizations.

But as a reminder, it's pretty obvious in days like today, but you have asymmetric risk. When demand exceeds the seasonal norms or where the infrastructure gets stretched or fails, California gas prices can spike dramatically, and that volatility tends to favor the producer.

So we've taken obviously a lot of steps in terms of our hedging strategy to protect our gross margins. But the setup where oil prices are increasing and gas prices are decreasing is favorable. That oil to -- gas-to-oil ratio ultimately means higher margins for our business, and we protect the consumption of that gas through hedging.

So right now, the focus is more on oil, but we will be looking at gas opportunities in the year. Part of our mix of projects this year has natural gas projects because this asymmetry in the market means that we need to be very well positioned when conditions shift, and we believe they will be shifting in the near term.

Got it. I appreciate that. My very quick follow-up is on Elk Hills power. That business receives a benefit from the state's resource adequacy program. Can you simply quantify the benefit for '26?

Yes. Resource adequacy, the capacity programs in the state, very highly, highly regulated from the procurement of power. So as the state started making their capacity requirements for 2026, they came in well below expectations. So pricing pullback. I think we've been signaling this since last November, where we can see where the contracts were heading.

We really had a period where we -- we had really big spikes and now we're seeing much more of a normalized level as historical -- much more historical in a lot of ways. So what we're seeing for this year is a $25 million to $50 million annually RA under current conditions. We're looking to, as we discussed, layer in contract the revenue to the PPA.

But we're well set up, right. Ultimately, there's a lot of things that could happen in a market like California. There could be plant retirements, demand that is beyond expectations, which is likely the case. You can have some reserve margin adjustment. We don't underwrite those scenarios in our base case, but they're real optionality over time.

It's going to be really interesting to watch. California grid is now very heavy on solar and wind that just have never been tested under stress conditions. If those resources underperform during extreme heat or there's a failure somewhere in the system, the value of reliable dispatchable capacity could shift quickly. So we're well positioned for the RA market if that were to happen.

The next question comes from Josh Silverstein with UBS.

I wanted to ask on the Uinta Basin. Now that you have it in-house, how are you thinking about the asset? Is it viewed as noncore or something you want to develop?

And then maybe just a little bit more details on it, higher or lower cost relative to the California operations and what inventory depth looks like?

Thanks, Josh. So yes, [ Ute ] came through our acquisition and merger with Berry, oil-weighted, a lot of stacked reservoir as well. We like the position. It's 100,000 contiguous net acreage. The Berry drilled 4 horizontals in the Uteland Butte that are all tracking around type curve, which gives us conviction around the repeatability and technical merit of the asset.

We also see some promising benches, the Castle Peak and the Wasatch to name 2 incremental areas of interest. So it's a nice asset. We see it strategically as a high-quality option. Right now, we're focusing on optimization, well designed ways where as we take control of the assets where we can improve the capital efficiency. Ultimately, though, it will have to -- in order for us to scale it, it has to compete with full cycle returns across the broader portfolio and against the California assets. And that's a really high bar.

As we mentioned, we see about 4x money on invested capital for California. So Uinta will have to compete for capital in that way. So we'll continue to evaluate it. We've only been operating it for a couple of months and whether that's scaling it through development or partnership, or other value-creating pads, we don't know yet, but we're keeping all options on the table. And ultimately, it's going to be returns and value creation that will guide the decision.

Got it. And then I also wanted to ask just on the Huntington Beach asset. Any update there in terms of how you guys are thinking about kind of optimizing the value of that?

Yes, 90 acres of Beach run property in one of the most expensive ZIP codes in California. So it's an asset that we continue to advance. It's exciting to own this asset in the portfolio, and we're executing our plan. A lot of the plugging and abandonment well it's been happening as we continue to produce, it's a cash flow positive asset. So we are effectively paying the P&A with that production.

We have made good progress in terms of working with the City of Huntington Beach, advancing the entitlements. We expect formal review in late 2026. And then that will be followed by approximately 2 years of review by the Coastal Commission. Once the entitlement is approved by the City and Coastal Commission, then we have -- we will do the site redevelopment and remediation. We expect to have about 80 wells, active wells remaining to plug at that stage. And we will look to -- ultimately, we're looking to optimize value.

And we see, if you look at comparables and the scarcity of land and high-quality development areas in the state, we see the -- some of the comparables going higher. So we like where we sit, and we will go through the process, obviously, look for ways to accelerate the process to the extent that we can. But we'll monetize it when we see the value, right? And right now, the value as we abandon and entitle shifts to the developer, we would like more of the value to accrue to our shareholders. So we're working diligently and putting things forward, but we see a lot of significant value creation opportunity in a few years related to this asset base.

I understand there is time for one last questioner. We have Nate Pendleton with Texas Capital.

Congrats on the strong quarter. Referencing Slide 10 and the potential storage of up to 1 billion tons of CO2 with the 350 submitted for CTV VII and more in the works. How do you think about the time line to develop the additional projects to reach that 1 billion ton marker? And then should we think about that total number representing total potential or just what the team has derisked at this point?

Nate, thanks for the question. Yes, our CTV business continues to be a really bright spot in terms of the way the state is progressing through their net 0 targets. And we're seeing not only we talked a lot about today about the data center opportunity and how that part of the business can unlock CTV.

The one area we didn't highlight today is through what we call what is called the RCPPP, which is the reliable and clean procurement of the state. There's advanced discussions happening and a lot of advocacy trying to add carbon capture into the mix for procurement. So whether it's data centers or the state making it a requirement, we think CCS will be the solution for the state, and that will bring the market forward.

So it's going to be important to watch both progress this year. We have 2 very, very large markets, one behind the meter, one in front of the meter that we're going to tap. And if that were all to come into fruition, we would -- that would fill up every single reservoir that we have.

So we continue to work on incremental capacity and bringing those permits forward. And that's been a core strength of our team is to advance those permits better than anyone else can in the state. So we're well situated for those market updates and for that market to unfold, and we think this is the year where it all comes together.

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

Thank you so much for joining us today. We really look forward to connecting with many of you in the coming weeks. Thanks, and have a great day.

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

Good day, and welcome to the California Resources Corporation Third Quarter 2025 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded.

I would now like to turn the conference over to Joanna Park, Vice President of Investor Relations and Treasurer. Please go ahead.

Good morning, and welcome to California Resources Corporation's third quarter 2025 conference call. Following prepared remarks, members of our leadership team will be available to take your questions. By now, 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 and in our earnings release. We will also discuss our pending Berry merger. We encourage you to read our Form S-4 filed on October 14, 2025, as it contains important information. Copies of this and other relevant documents are also available on our website and the SEC's website.

Today, we will 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 1 primary and 1 follow-up as this allows us to get to more of your questions.

I will now turn the call over to Francisco.

Good morning, everyone. CRC delivered another strong quarter, reinforcing the disciplined performance and strategic focus that set us apart as a different kind of energy company and also positioning us at the forefront of California's energy revival.

We have a lot of good news to share this morning. Here's how we're going to structure the call. First, we will open with a list of accomplishments and summarize important recent events. Next, Clio will discuss our third quarter results. Lastly, we will share some early thoughts around 2026.

Let's start with the highlights. California's energy and regulatory environment is improving in meaningful ways and CRC is well positioned. The recent passage of key legislation has created the most constructive framework we've seen in more than a decade, strengthening oil and gas permitting, authorizing CO2 pipelines and extending the Cap-and-Invest program through 2045.

Together, these laws help support reliable in-state production while encouraging investment in the state's rapidly rising energy demand. CRC's E&P, CCS and Power businesses can support California's need for energy security and clean energy solutions. Our E&P business continues to perform exceptionally well. Our teams are executing safely, and our assets are demonstrating strong production performance and low base declines.

With our successful Aera integration behind us, we can now move our annual base decline assumption to 8% to 13%, which is down from 10% to 15% previously. This significant change strengthens our cash flow generation, improves our capital intensity and enhances the value of our large PDP reserve base. CRC's conventional reservoirs are advantaged with significantly higher estimated ultimate recoveries, when compared to shale resource plays. As many of the Lower 48 producers are moving towards lower quality locations, we are well positioned with long duration, high-quality, low-decline reservoirs.

We believe that this will allow us to effectively replace reserves, maintain production with less capital and deliver consistent results through the cycle. Strong execution and smooth integration remain key strengths of our operating teams. We recently announced our merger agreement with Berry Corporation. Like Aera, this deal was well timed is progressing as planned and will add assets that are adjacent to our current positions, creating meaningful synergies that further enhance our leading operational scale in California.

Through Aera, we demonstrated our ability to effectively integrate assets, improve operating efficiencies and rapidly capture value. We plan to apply that same approach to Berry. Turning to our Carbon TerraVault business. Momentum continues to build. We are well ahead of the competition and close to making history at Elk Hills with our first CCS cash flows.

Our first carbon capture and sequestration project at our Elk Hills cryogenic gas plant is advancing with construction underway and first CO2 injection expected in early 2026, pending regulatory go ahead. This will be California's first commercial-scale CCS project and a critical step towards realizing the state's decarbonization goals.

Now that the CO2 pipeline moratorium has been lifted, our strategically positioned CTV reservoirs across the state have the potential to provide storage solutions for existing brownfield emitters that don't have the benefit of colocation, creating a true statewide framework for emissions reduction. We are also advancing our regulatory efforts in permitting inventory to expand our statewide storage network.

We currently have 7, Class VI permits under active review with the EPA and are preparing additional applications totaling 100 million metric tons across Central California. As we focus on the most attractive markets for CCS, one thing is clear, California's biggest opportunity lies in delivering clean, reliable power.

The California Public Utilities Commission estimates that incremental power capacity in the state will need to double by 2035 to meet demand. Later on, the projected investment in AI inference targeting major population centers, and it's clear that California is heading towards a substantial power shortfall. While renewable resources and scalable battery storage have a role, they will not be enough to satisfy demand.

California needs clean, reliable baseload power to enable data center growth, while ensuring a reliable grid. State leaders recognize this challenge and have proposed several pathways to address it. With CCS, CRC and CTV are well placed to be part of the solution. Google recently announced plans to deploy natural gas generation with carbon capture for their Illinois data centers.

Here in California, the Energy Commission recently issued a report highlighting that pairing natural gas generation with CCS is a practical and scalable path to the carbonized baseload power across the state's legacy assets. It's clear that leading innovators share this vision, and so do we. CRC and CTV have an unequal portfolio of assets located in the heart of the nation's largest economy.

We can readily pair existing power generation with carbon capture to rapidly unlock firm, clean baseload power in proximity to major demand centers. We are evaluating multiple opportunities today in this rapidly expanding market. First, utility and wholesale markets, where front of the meter sales could provide decarbonized baseload power directly into the grid to support system reliability and reduce emissions under the CPUC's newly proposed reliable and clean power procurement program or RC BBB.

Second, we can help meet demand from existing large technology and data center operators. Based on PG&E's interconnection queue, data center request in California have now exceeded 10 gigawatts, reflecting surging energy needs tied to AI, cloud computing and electrification across the state.

As the AI revolution advances from training to inference, data center sites are expected to shift from prioritizing areas with cheap abundant electricity to low latency areas near major population clusters. As the largest state in the nation with nearly 40 million people and 4 of the top largest U.S. cities, California screens extremely well.

As we evaluate our options, it's important that we do the right deal at the right time to create the most value for our shareholders. We're focused on turning an evolving market opportunity into real progress. And earlier today, we took another important step in our natural gas power with CCS strategy in Kern County, as we announced a new partnership with Capital Power to develop carbon management solutions for the La Paloma power facility.

This builds on our previous announcements with Hall Street and our own project, CalCapture and Elk Hill. These partnerships validate market demand expand scale from front or behind the meter data centers and highlight CRC's ability to connect firm power generation with carbon storage.

With strong execution, disciplined growth and a constructive policy environment, CRC is well positioned to lead California synergy come back, one that values both reliability and responsibility. Clio, over to you.

Thanks, Francisco. This quarter's operating performance once again exceeded expectations, underscoring CRC's consistent execution operational strength and financial discipline, the hallmarks of our strategy. For the third quarter of 2025 we delivered net production of 137,000 BOE per day, 78% oil, roughly flat quarter-over-quarter on a $43 million D&C and workover capital program.

Realizations remained above national averages. Oil at 97% of Brent, NGL at 60% of Brent and natural gas improving to 113% of NYMEX. We generated adjusted EBITDAX of $338 million and free cash flow before changes in working capital of $231 million, reinforcing the durability and efficiency of our operating model. G&A and operating costs were within guidance and our hedge portfolio continued to provide downside protection, while preserving margins. Capital investment for the quarter totaled $91 million, squarely within plan.

In October, we raised $400 million on attractive terms to refinance Berry's debt ahead of the pending merger. This financing demonstrates our ability to quickly capitalize on favorable market conditions, strategically enhance our balance sheet by lowering costs and extending duration and maintain leverage below 1x.

These proactive steps kick start our synergy capture and position us well for a seamless integration once the merger closes. Our balance sheet remains a key strength. At quarter end, net leverage is at 0.6x and total liquidity exceeded $1.1 billion, including $196 million of cash and an undrawn revolver.

In October, we used available cash to redeem the remaining $122 million over '26 senior notes at par. Since then, we've rapidly rebuild our cash balance, ending October with more than $170 million, excluding the high-yield proceeds reserved for the very closing. We have no near-term debt maturities. The next comes due in 2029.

Rating agencies have taken notice. Moody's upgraded CRC's corporate family rating to Ba3 and Fitch assigned a positive outlook, citing our consistent cash flow generation, low leverage, disciplined capital allocation and the improving regulatory environment in California.

In addition, our borrowing base was reaffirmed in October at $1.5 billion, while existing and new lenders increased their elected commitments by $300 million to $1.45 billion, further enhancing our financial flexibility. CRC's balance sheet and capital framework remain among the strongest in our sector, giving us flexibility to fund disciplined growth, while sustaining meaningful shareholder returns.

During the quarter, we increased our dividend by 5%, reflecting continued confidence in our business and cash generation. Year-to-date, we returned more than $450 million through dividends and share repurchases. Under our current authorization, we have over $200 million of remaining capacity for share repurchases through mid-2026.

The fourth quarter is shaping up extremely well. We expect to benefit from continued stable production, lower costs and new efficiencies. Capital spend will be modestly higher than in the third quarter, mainly reflecting the catch-up of deferred projects and a strategic scope change to our CCS project at CRC's Elk Hills cryogenic gas plant.

As we've advanced this project, we've identified an opportunity to upgrade facilities to serve both Belridge and Elk Hills. Improvements that enhance NGL recovery and increase operational efficiency as we prime the facility for carbon capture. This once again demonstrates our team's innovative approach and our focus on value-enhancing initiatives through integration.

Importantly, full year capital expenditures are still expected to remain within our previously disclosed annual guidance range of $280 million to $330 million. As we look ahead, CRC is poised to enter 2026 with a premier balance sheet, a flexible capital structure and a resilient production base, all supporting durable free cash flow and long-term shareholder value.

Furthermore, roughly 2/3 of our expected 2026 production is hedged at a Brent floor price of $64 per barrel, ensuring the stability of our cash flow. Our preliminary 2026 plan assumes an average of 4 rigs supported by our strong hedge position and our inventory of existing permits. We plan to operate these rigs using both current permits and those expected following SB 237 enactment.

As always, we will remain disciplined and agile, adjusting our capital program as commodity prices and market conditions warrant. Importantly, our current outlook does not yet include the impact of the pending Berry merger, where we anticipate meaningful synergies once the transaction closes. CRC remains focused on consistent performance, disciplined growth and competitive shareholder returns as we move into 2026.

And with that, I'll turn it back to Francisco.

Thanks, Clio. 2025 is proving to be a remarkable year for CRC with strong momentum as we head into 2026. We're posting wins across multiple fronts. Robust reservoir performance, the structural improvements in our portfolio, lower cost, a more resilient capital structure and greater alignment between industry and the state to achieve common goals.

For the second consecutive year, we will grow our production through strategic transactions and disciplined reservoir management. More importantly, we expect these actions to position us for sustained cash flow per share growth in 2026 and beyond.

We're excited about what lies ahead from closing and integrating Berry to advancing Carbon Teravault and CalCapture and expanding our power and CCS partnerships. Together, these initiatives will allow us to unlock meaningful value for our shareholders. Our focus remains clear, creating considerable and sustainable value for shareholders.

We believe California is entering a new era for locally produced energy, one defined by abundance, affordability and sustainably produced solutions. California's energy landscape is improving and CRC intends to play a leading role in that transition. CRC is a different kind of energy company. Operator, we're now ready for your questions.

[Operator Instructions] Our first question comes from Kalei Akamine from Bank of America.

I want to start with the MOU on -- with Capital Power. It's been our view that brownfield emitters power plants in your vicinity would need to get involved to underwrite the CTV development. So yesterday's announcement in our view was a positive step.

My question concerns your PPA efforts from this going forward. 200 megawatts, one could argue that maybe it's not big enough, but if you're collaborating with others and presumably, there's more megawatts on offer. So as you think about developing in this business, there are others in the area that you can perhaps pull into this joint effort. So maybe just kind of stepping back, can you talk about maybe next steps for the PPA?

Kalei, thanks for the question. Yes, we -- the market is getting hot. We're seeing far more opportunities today than we did 12 months ago. And I think the -- as we mentioned in the remarks, having 1 of the hyperscalers, Google going into natural gas powered with CCS is similar to when you hear the hyperscale is going into nuclear, right?

So it's a big moment. It's a big market signal. So the vision that we've had for Kern County, which is on Slide 7 on our deck, is to build a hub for -- to serve their data centers or the grid but at big scale.

And yes, our CalCapture project, our excess power at our own plant is a big component to that. It's an anchor element to it. But now we're -- as we move with partnerships with both Capital Power and Hall Street, we're putting a significant scale on the map.

So as these hyperscalers are looking now for more inference, low latency you have a site here that can serve the LA market at scale and decarbonized. So it's coming together. It's coming together nicely and it's the story of not only building data centers or increasing power, which is what everybody is looking for. But we're particularly well positioned on both the gas supply, natural gas supply that we have in basin.

But also take away the CO2 emissions and store them on our side. So it's a nice integrated project and with great partners like Capital Power is a fantastic independent power producer. I think the signal is CCS is here, and this site is going to be an attractive place for us to grow that power demand.

So excited about the next steps. And yes, there's a lot more to come. I think the site continues to -- we continue to find ways to grow different power elements to it and the things are coming together nicely.

I appreciate that, Francisco. Maybe for the next question, going to your '26 soft guide you highlight a 2% entry to exit decline. When I think about your assets, projects like floods require some time to activate a production response. So I'm wondering about the cadence of that decline. Is it isolated to maybe the first half of the year, while second half of '26 firms up as those projects come to bear?

Yes. It's really been building an exceptionally good 2025 in terms of reservoir delivery and the team's performance in managing the assets. We will have -- our plan is to have 4 rigs on 1/1. So January 1, by then, we would have 4 rigs running and no, we expect that to be the entry to exit plan as we lower our base decline assumptions, we're putting capital back to work, primarily in the form of workovers and sidetracks permits that we have in hand. We expect that to be a fairly steady performance throughout 2026.

Our next question comes from Betty Jiang with Barclays.

It's really great to see the momentum across the portfolio. My first question is on the upstream side on the PDP decline. It struck me that your PDP decline improved from 10% to 15% to 8% to 13% since like this natural decline don't typically change. So can you just speak to what's driving that improvement? Is that a function of the portfolio or anything else you're doing operationally?

Yes, it's a combination of things. It really is an answer that has several components, Betty. But it's first of all, it's owning great assets and conventional assets are just good rock in assets that our team knows how to manage really well. So as we move the decline rates and now that we are a year plus with the Aera assets, and we can see that this team can really bring the most out of it, we feel comfortable changing the corporate assumption.

In terms of tangible things that the team is doing, if you look at 2025 and the composition of our activity, a lot of it was focused on injection and injection at Belridge. So with pressure support in these great reservoirs the oil flows nicely. So the Belridge field is performing extremely well, an asset that we acquired from Aera.

We also, on Elk Hills, it was more about technology, and it's about remote surveillance. So it's -- I mean, it's an AI component of being able to identify wells when they fail and quickly repair those wells, right? So any well that's down, it's cash flow. So our team has been seeing some improvements in that surveillance and that leads us to be able to manage the down list that you have in conventional assets and manage that more effectively.

So and those are the 2 biggest fields. So Belridge and Elk Hills, if you're able to move those reserves, those decline rates shallower that cascades to the rest of the portfolio, right? So -- and it's really just -- I mean, I really want to comment on the team's performance. I mean, they are just completely on the ball and doing the right things in terms of managing the asset base.

So that's how you get conventional assets to perform better. It's just this blocking and tackling, it's things like surveillance, things like injections that ultimately pay off big dividends.

Great. My second question is on the Kern County decarbonized power opportunity. As you highlighted in Slide 7, it's really great to see the capital power MOU. But what strike me also is this emerging hub of opportunities that's in Kern County with multiple power plants on top of the CO2 reservoir.

So can you speak to the vision that you see that's emerging in this area? How could a potential hub decarbonized power scenario could look like? And what needs to happen to really catalyze that development?

Yes, Betty. So a lot of things have come together very nicely. So -- but it's also a reminder that the California market operates different than other parts of the U.S. Here, you have a lot of the infrastructure already exists. And it's been -- natural gas fired generation has been sidelined as more and more renewables have come in.

But then if you take the growth expectations of California power, right? So where we're looking to double in 10 years and triple in 20 years, that growth is not going to be all served by renewables and batteries. So you're going to have to bring in baseload, you're going to have to bring baseload at scale. So we have the ability to take these plants in retrofit for CCS to make them decarbonize so they can participate in this growing market.

So in Kern County alone, and this is all very close to our -- either within our field boundaries or next to it, we see 2.4 gigawatts of power generation that could serve a growing market. Now when we also saw pipelines, the more autonomous CO2 pipelines being lifted, that brought forward that brownfield idea that we had and b, we're now able to connect -- we'll be able to connect these power plants with our storage sites.

And as you see on the map, these are very short distances and some 5 to 20 miles for all these power plants to be able to get to one of our reservoir. So we're building scale on power. We're building scale on emissions. On an aggregate basis, we see about 5.5 million tons of emissions from these plants. And if you look at our inventory of permits, we're up to about 9 million tons that we are in some part of the permitting process all in the Central Valley.

So it's all coming together. The big part that we were waiting for is that market signal. And the market signal already talked about Google, but also California is looking for decarbonized power, understanding that we're going to have to bring incremental sources. And we feel retrofit of existing plants that are already there producing power is going to work much better and faster than having new build of any power generation in California, right?

So really well positioned to create this hub. L.A. is within 100 miles, 100 miles is important because of latency requirements as you look for inference. So this is all starting to take shape, where before we talked about a single site with single pore space. Now you can see that it's multiple sites, multiple plants and third parties are coming -- looking for a solution that only CRC can provide.

Our next question comes from David Deckelbaum with TD Cowen.

Francisco, Clio and Omar and team on several of the milestones achieved to date. I'm probably going to ask you more questions around a lot of things you're going to be asked on today. I want to go back to just the PDP decline. Curious like as we approach sort of year-end reporting for Francisco or Omar, how you think about are we recovering more oil in place at this point with performance revisions? Or are we shifting more recovery into earlier parts of the reservoirs economic life at this point?

David. I'll turn it to Omar to give any incremental highlights. But yes, these are some of the largest oil fields in the country. And if you look at oil in place, they are in the billions of barrels of oil in place. If you look at the ultimate recovery factors, these are sandstones that have both good permeability and porosity.

So the ability to, in a lot of cases, maintain pressure support or to go through a bypassed oil enhances those recoveries. But -- so this is different than shales, right? Shales is all about drilling and completion and about how effective can you make that single event of drilling.

Here, you're managing the reservoir and now that we have both permits and a very strong backdrop or from our ability to allocate capital to these projects, we're able to really work on life of field plans to maximize that output, bring a lot of that production forward. But maybe I'll turn it to Omar to see if he wants to add anything.

Yes. Thanks, Francisco. And thanks for the question, David. One thing I would add to Francisco's comments is just where we are with these reservoirs in their life cycle. We have a long history of operating these reservoirs. So we have steamfloods that started steaming back in '70s, waterflood back in '80s.

And the point I'm making is that we understand the behavior very well. So there are very little surprises as you manage PDP. And then you can look for incremental opportunities to shallow the decline. And it's basic blocking and tackling with the EOR projects, you're not going to get 2,000 barrel wells, you have a lot of 20, 30 better wells that you manage well and you work on them to gain another barrel or 2? And just given the number of wells they add up to a shallower decline.

So the 2 things that Francisco mentioned earlier, we have been focused on improving the injection side of EOR, both in steamfloods and waterfloods. That was most of the work we did in the first half of the year. And then we are focused on getting to the wells that fail quicker through technology. And AI is a big help. It's eliminating a lot of human error. It's eliminating a lot of human lag and we are getting to those opportunities faster.

So it's never a single silver bullet. It's a combination of all these factors. Where we are in the reservoirs life cycle where the declines are very predictable. Application of basic blocking and tackling and leveraging technology.

And then maybe Francisco, can I ask on just the high-level thoughts on the '26 plan, which I think was a pleasant surprise for everyone, just given the capital efficiency. It appears as you kind of approach a maintenance level, I'm curious as with the pending opportunity now for increased permits. It seems like your approach to capital allocation is still very much rooted in maximizing free cash per share, if I have that correct.

And I guess how do you think about that in the context of now more or less receiving a call from local governments to increase production in the state?

Yes, David. It's a great question. So you're absolutely right. Our focus is on growing cash flow per share. And so you do look at production as 1 of the components, but it's not the only one. So the way we're thinking about 2026 is a disciplined ramp-up on capital and we have a lot of flexibility.

And 1 of the things that we talked about, the type of assets that we have, but the ownership of the assets, it's also create a key advantage that we have. We own 100% of our fields. And so we controlled the spend depending on the commodity cycle. So it allows us to be very efficient. And as you make these assets better, as we've talked about, then your capital deployment becomes 1 of the highlights -- so the way we thought through it is, as we look for the best and optimal way to grow cash flow per share, it's really through a combination of drilling and also leaving cash to that we can opportunistically buy back shares, right?

So I think the combination of 2 -- of the 2 with a foundation of a very, very strong hedge book, we have 64% of our oil hedge into 2026. And that's only going to improve once we close the deal with Berry. So that gives us a really good place to start delivering we need to showcase the inventory, and we have a significant runway of great inventory to go after.

But we've been in a permitting constrained scenario, right? So the reactivation needs to be measured, thoughtful discipline in a way that we can showcase what this business is capable of. But you're right, in terms of the signal from the government is we need more California production. We need more Kern County production in particular. So as the state is looking for increased activity in Kern County, we will look to participate as we look to, first, grow cash flow per share and look for inventory that gets developed.

We will look to participate and our contribution is going to be to effectively double our rig count for now. But we'll continue looking and we'll obviously have to see where oil prices are. We'll have to see where our share prices are as we continue to think about capital allocation. But the way we are leaning into 2026, it's a good balance between buybacks and investing in our business.

Our next question comes from Josh Silverstein with UBS.

Maybe just sticking on the decline rates. You had previously discussed around a 6 to 8 rig, $500 million capital program in order to keep production flat. Now that you've had this reduction in the base decline rate I was curious if you could just kind of give us some color as to what that new maintenance level may be for CRC going forward?

Josh. Yes, I mean, we're below $500 million, clearly. I think with our 2026 preliminary guide. That's the number that you can triangulate around. Now as we mentioned, these numbers do not include the Berry assets. So as we bring -- we closed the Berry merger, we'll refresh that number inclusive of their assets and we'll provide a full corporate number to maintain -- the maintenance capital to keep production flat.

But on a stand-alone basis, so CRC and Aera assets given the improvements that we showcased in the earnings call today, we're clearly now below $500 million. We've seen Berry be able to maintain their production, total capital, and that's all of the capital with about $70 million, but we need to be able to close the transaction and provide a refresh to the market, but the baseline assumption is improving.

Got it. And then it's been a while since we've gotten an update on the Huntington Beach assets and what you guys are doing there and what the permitting and that process looks like. If you could just provide an update, that would be great?

Yes, absolutely. So things continue to progress well with Huntington Beach. We've made a number of public filings around preliminary development plans, 800 units that could be ultimately built at the site, once it's fully approved. That's all part of the process of engaging with the City of Huntington with all the local and regulatory agencies around the project.

So things are marching forward. We have a dedicated rig abandoning the wells there as we go. We continue to produce, we have abandoned the wells as we get all the permitting lined up. As we said before, we think this project is going to be ready 2028 time frame. That doesn't mean that there's not a monetization sooner. But as we looked at this project in the past, the -- as you re-entitle the land for its best use, which is residential housing and you are able to abandon the -- abandon the wells, you're going to get to an optimal price, where the market appetite will be there.

We provided guidance on the cost around $200 million to $250 million to abandon the property. That was a 2023 number. We have already made number of abandonments. So that number will come down as we look for that point to monetize the asset in 2028, but things are progressing well.

Our next question comes from Nate Pendleton with Texas Capital.

Congrats on yet another strong quarter. Looking at Slide 8 with your existing power generation portfolio and with some of your investments to date, can you talk about your willingness to lean further into the power generation space beyond Elk Hills such as additional plan ownership or additional investment in some more leading-edge power generation solutions?

Nate. So I would say for right now, the focus is going to be on the feedstock, which is natural gas, low methane emissions gas and certified -- third-party certified gas, which we think is going to be very attractive and we're the largest natural gas producer. And then on offering a CCS solution on the back end. And that's the way we're positioning the company.

I don't anticipate owners of -- ownership of natural gas combined cycle plans beyond what we have at this point. We are looking for other ways to bring power forward, things like fuel cells and geothermal, there's a lot of prospectivity in California for -- for geothermal, there's a lot of appetite on fuel cells to have a CCS solution.

So we're looking to see what's the right mix of providing this both the carbonized, but also baseload power that we need to be able to serve the growing market. So -- but we are the solution on CCS, and we are the feedstock on natural gas. That plays to our strength, and that's where we're going to continue to advance. And as we continue to bring some of these ideas forward more and more technologies, more and more hyperscalers. I think we'll start looking at what we have and to build that vision for a Kern County power platform that we talked about earlier.

And as a follow-up from an earlier question on connecting the emitters on Slide 7 with the recently passed legislation. Are there any underutilized pipelines right of way around those assets that could be brought in-house or repurposed to serve as the connective tissue there?

Yes, absolutely. So as you look at Slide 7, and you can see that we showcased the footprint fairly well that has both the fields and the current pipelines. So you can see that this is -- these are right of ways that are owned either by CRC or by other E&P companies. These fields are adjacent to ours sort of these power plants are also adjacent to ours.

So it's a particularly good place to be able to decarbonize this whole kind of micro grid. And so definitely, there's advantages as we talked about, we own a lot of land. We own a lot of surface ourselves and that we have partnerships with others that own that land as well. So -- so this is something that -- now that we have the moratorium on [ pace ] lifted, that's what we were really waiting on to be able to connect all of these assets, and that's what we're working with Capital and Power and others to try to figure out.

Our next question comes from Noel Parks with Tuohy Brothers Investment Research.

I have a couple of questions. So sort of as a reality check, how long has it been, since you've had the activity levels at Elk Hills that you're going to be ramping up into starting next year?

Yes. We've been in a permitting constrained environment, since the beginning of 2023. So the improvements that we've had in the past few months around the regulatory framework is a significant milestone for the company. Now we have been able to execute capital workovers and sidetracks effectively over that time, but it's new well bores that we haven't had permits to pursue. But now we have SP 237, so a brand-new law that not only allows for permits in kern County, but it also gives us duration.

So it's effectively a 10-year tied to the Kern County EIR. So a 10-year runway -- so how much -- when the last time we had as much support and as big of a runway, it's been a very long time. So as we mentioned in our slides, and I think we mentioned publicly before, the state is looking for local production to ramp back up to about 25% of the supply of the state. We've been trending down over the years.

We used to be 40%, 50% of the local suppliers, local E&P companies to the state. That's trended down to about 22%. So the call from the government is to bring more of that California low CI production. And so meaningful changes and meaningful improvements and in terms of the stage view towards local production and as the leading producer in the state. We have -- we want to do our part to help stabilize the fuel markets and look forward to bringing more production forward.

Great. And I'm just sort of thinking that there are so many irons in the fire and different types of catalysts you have at work right now. And with sort of the message of trying to the need to double the state's power production by 2035. So when do you foresee a ramp-up in production for your gas assets as you look ahead?

Yes. It's a function of capital allocation, where the best returns are. And if we look at our 2026 plan with the 4 rigs, we're going to focus on primarily oil. About 80% of the anticipated contribution from '26 activities is oily. So that means 20% gas and NGLs. So that's just a matter of where we are in terms of the returns, again, supported by a very strong hedge book. We see great returns in the projects, the returns that we've outlined before.

So natural gas will come if we get either stronger natural gas prices or we have supply agreements to all these groups that need power. Certainly, that will be the call to drill more gas. We have a lot of prospectivity. We have -- we're sitting on these great basins. And depending on what you are in the state, you could have heavy oil in the shallow reservoirs and then deep gas, a few thousand feet below that, right?

So -- you have a lot of stacked pay and a lot of flexibility in how you can run the assets and allocate capital. So we're looking for where the best returns are. And right now, we're seeing them in oil. But as again, as the market demand changes or increases in particular for natural gas, we will be ready to also pursue some gas on a go-forward basis.

[Operator Instructions] Our next question comes from Leo Mariani with ROTH.

I wanted to ask a little bit about on the capital plan for 2026. So as you're talking about running 4 rigs continuously for roughly $280 million to $300 million of D&C plus workover capital -- but if I just look at your kind of E&P spend in 2025, it was 200 -- I think it's $245 million to $275 million for kind of 1.5 rigs. So just the proportion seems a little bit out of whack there. So can you kind of help me just kind of square up the numbers a bit there?

Yes. I think you may be mixing Leo total capital versus D&C. So the D&C for '25 is lower. We have like you said, 2 rigs, and we didn't start the year with 2 rigs. We stepped into 2 rigs later. We do have a different facility spend and the facility spend that we talked about in this quarter, which is to bring the NGL project forward from Aera.

And so what we're doing is we're building a pipe from Aera to Elk Hills to bring rich wet gas to Elk Hills run it through our cryogenic plant and extract the 1,000 barrels of NGLs. It's a particularly good project because it just follows the natural gas that's already in place. It's just a more efficient way to extract incremental value from the project. But in terms of the D&C numbers, they're definitely lower for 2025. I don't know, if -- what is the number, Clio?

Yes, absolutely. Leo, you're comparing, obviously, our total capital versus what we're disclosing here related to the activity pickup. But for 2025, capital, we're effectively lining up to stay within our guidance. We haven't changed that. And that spend is all encompassing. It includes, obviously, the oil and gas spend as well as our carbon management spend and so that's where you're seeing the delta here as well as our corporate level spend.

But going forward, there's definitely significant capital efficiencies those gains have been through the merger with Aera, consolidating those gains has been the story for 2025. And in 2026, you're seeing that come through in the numbers and the efficiency that we're able to get from that capital spend in the $280 million to $300 million range, that's really yielding a very significant arrest of the decline.

Okay. And is that largely going to be workovers, which maybe are less capital intensive? Is there kind of a component of new drilling there? Do you have an estimate of that? Just trying to kind of get this a little bit apples-to-apples here?

Yes, 2026 will be -- will continue to be primarily workovers and sidetrack. Roughly speaking, 60%, 70% of the D&C will be in that category. So the rest would be in new wells as new permits start coming in for those.

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

Thank you. Thanks, everybody, for joining us today. We really look forward to seeing you in upcoming investor conferences during the winter season. Thank you so much.

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

Good day, and welcome to the California Resources Corporation announces all-stock combination with Berry Corporation. [Operator Instructions] Please note, this event is being recorded.

I would now like to turn the conference over to Joanna Park, Vice President of Investor Relations and Treasurer. Please go ahead.

Good day, everyone. Welcome to our call to discuss California Resources Corporation combination with Berry Corporation. Leading today's call is our President and CEO, Francisco Leon. In addition, we are pleased to be joined by Berry's CEO, Fernando Araujo, who will also make a few remarks. Members of CRC's executive team are also here today and will join us for Q&A. Supplemental slides are posted in the Investor Relations section of our website, along with reconciliations of non-GAAP financial measures to GAAP financial measures.

Today's discussion will include forward-looking remarks based on current expectations. Actual results may differ due to factors described in today's press release and in our SEC filings.

With that, I'll turn the call over to Francisco.

Good morning, and thank you for joining us. Today marks another milestone in CRC's growth story, an accretive all-stock combination with Berry. This transaction enhances our scale, creates significant operating and cost synergies and strengthens our ability to deliver affordable, reliable and responsibly produced energy for Californians, all while maintaining a strong balance sheet and ample liquidity.

Let me cover the key highlights. First, the complementary California asset fit is compelling and will ultimately benefit a state that needs more energy. This bolt-on transaction aligns perfectly with CRC's core footprint. Berry will add approximately 20,000 barrels of oil per day of California-based Brent-linked conventional production on about 20,000 mostly adjacent net acres. The added scale will make CRC more durable and provides new flexibility in how we elect to allocate capital.

With more than 75% of California's oil consumption sourced from abroad, the need for locally produced responsibly developed energy has never been clearer. California possesses vast resources and a world-class geologic formation, and our company was built to responsibly unlock that potential.

We have shown that assets are better in our hands. Recent legislative actions are very encouraging, and will help offset the state's reliance on foreign oil by incentivizing local production, making the timing of today's California-focused combination all the more significant.

Next, the deal was priced right. The transaction is valued at approximately 2.9x 2025 consensus EBITDAX and about $30,000 per flowing barrel. Importantly, the transaction delivers accretion of more than 10% to second half 2025 operating cash flow and free cash flow, even before incorporating anticipated synergies.

Third, we have a strong track record of delivering synergies. And in this transaction, we're targeting annual synergies of $80 million to $90 million within 12 months. This represents approximately 12% of transaction value. In our view, these significant synergies can only be realized because of the exceptional fit of these two portfolios. We expect synergies to come primarily from corporate synergies, lower interest costs from debt refinancing, operating improvements and supply chain efficiencies.

Looking back at the Aera merger, we achieved our targeted synergies ahead of schedule, demonstrating our strong integration capabilities as a premier California operator. We intend to apply the same disciplined approach when we integrate Berry. Additionally, Berry will bring 2 exciting business units with its wholly owned subsidiary, C&J Well Services and a large contiguous position in the rapidly developing Uinta Basin.

First, C&J Well Services will help to insulate the business from future cost inflation and support responsible operations. And second, the Uinta assets will provide additional oil-weighted operational and financial optionality, with several opportunities to unlock significant value.

Next, we will maintain our strong balance sheet. Upon closing, we expect our pro forma last 12 months leverage ratio to be about 0.8x, making this essentially a credit-neutral transaction from a leverage standpoint. We have ample liquidity and can use the strength of our capital structure to refinance debt at more attractive interest rates.

Following the closing of the combination, CRC shareholders will own 94% of the combined company. And we expect all stakeholders will benefit from greater capital efficiency, increased free cash flow and sustained long-term value creation. Closing is currently expected to occur during the first quarter of 2026, subject to customary closing conditions, including regulatory clearance and Berry shareholder approval.

And lastly, I would be remiss not to mention the significant legislative developments from this weekend coming out of Sacramento. Last week, California took meaningful steps to address the state's need for more abundant, reliable and affordable energy. As you know, CRC was built for California. We have proven our ability to safely operate with high regard to the environment while building a business with lots of optionality.

Today's deal further strengthens our position. Recent actions will go a long way to incentivize increased local production, stabilize fuel markets and advance California's decarbonization and emission reduction goals. Three important bills now await the governor's signature. The first is SB 237. This bill deems the Kern County EIR as sufficient. It removes the risk of further litigation on the adequacy of the EIR and moves to eliminate CEQA-related delays starting in January 2026 and lasting for a decade.

The law will encourage local production through permits for up to 2,000 new wells annually in Kern County, furthering the state's goal for in-state crude production to meet at least 25% of refinery feedstock demand. Second, SB-614. This bill lifted the moratorium on CO2 pipelines. These pipelines are instrumental to us as we commercialize and expand our leading carbon management business through CTV.

And third, AB 1207. The bill extended the state's cap-and-trade program through 2045, providing additional clarity and important incentives to support the energy transition. Together, these milestones not only strengthen the framework for responsible production in Kern, but also provide a clear path to grow and scale our carbon terrible business.

Before we move to Q&A, let me ask Berry's CEO, Fernando Araujo, to say a few words from his perspective. Fernando?

Thank you, Francisco, and it's a pleasure to be here. This combination marks an exciting new chapter for Berry. It builds on the value our team has created through disciplined execution and strong operational results across all areas of our business. By joining with CRC, we're creating a stronger, more durable energy business, one with significant scale and enhanced capital structure and greater technical depth to responsibly, safely and efficiently grow production, reduce emissions and support energy security in the state. I'm proud of what we've built at Berry. I'm confident that this combination positions us to unlock even greater long-term value for our shareholders, our employees, our communities and for California itself. And back to you, Francisco.

Thanks, Fernando. This transaction is about building a stronger CRC, larger, more efficient and positioned for enhanced free cash flow generation. We're excited about the path forward and confident in our ability to deliver the benefits of this combination. We continue to show that CRC is a different kind of energy company.

Thank you for joining us today. Operator, please open the line for questions.

[Operator Instructions] The first question today comes from Kalei Akamine with Bank of America.

Nice timing. With oil permitting done in the state, I guess, the coast was clear to do a deal like this. My first question is on the synergies. So $80 million to $90 million, obviously, that's a solid number. Annuitized at a 10% discount rate will point to about $850 million in value, but you guys are calling at $500 million. That represents 70% of the deal value. But I imagine that the $850 million is an EBITDA valuation and the $500 million is a free cash flow discounted valuation. I'm curious what the delta is between the two numbers. Is it mainly tax? Or is there any associated capital to get there?

No, Kalei, I think, yes, it's two different numbers. So the $500 million is a discounted annual run rate of synergies, so $85 million on the midpoint. We're tremendously excited about the synergy potential of this deal. The asset fit is just so compelling. We looked at the Berry portfolio very differently after we acquired Aera. That really changed our view on the fit of the deal.

So -- and we've now, after a year after closing Aera, where we were able to deliver 100% of our synergies ahead of schedule, the confidence that this team can execute those synergies and get all the value accelerated for the shareholders is truly something that really motivated us to do in this deal. So -- but I think if you're talking about two different numbers, the -- I mean, we basically see the synergies effectively paying for the deal over time.

Got it. Just a clarification point. Do you need to spend any capital to get the $500 million of PV synergies?

Yes. Largely, the synergies come from corporate staff reductions from refinancing, from supply chain. So no, I mean there could be some capital that has to be spent as you think about infrastructure consolidation, but those are small dollars in a relative sense. This is a deal that's accretive day one, and were very achievable synergies to pursue in the very near term.

The next question comes from Josh Silverstein with UBS.

Based on the legislation passing and now this transaction, how should we think about the volumes and activity levels for the pro forma company?

Yes. We had -- just have been having the tremendous, very constructive conversations with the state of California. It's been -- it's really a truly a significant change as we think about our business going forward as we -- as the state is signaling a need for California production and in particular, Kern County production. The dependence on foreign oil has taken its toll. It's driving prices higher. It's having refineries exiting the state. So to stabilize the fuel markets, the state really wants that local production.

We've been dipping -- we think we're about 22% of contribution in terms of overall state -- in-state supply. And the government wants us to be at least at 25%, that's collectively between all the operators. But it signals not only a need for that production, but a step-up in activity going forward. As we look at the kind of the new normal, the kind of what California is looking going forward, we're going to continue to stay very disciplined on capital allocation.

But we felt the incremental cash flow from the Berry assets from also all the synergies puts us in the best position combined to be able to meet that challenge and increase that contribution of local supply. So we're excited to kind of test this new world and await the governor's signature of the bill, and then we'll talk about our 2026 plans as to what the production is going to be. And -- but it's an exciting day for California, and an exciting day for CRC.

Got it. Okay. I guess maybe along the same line, how would you weigh potential increases in activity versus shareholder returns? And maybe if you can give us a little bit of a view as to what shareholder return and profile may look like kind of until the deal closes, then maybe afterwards as well?

Yes. We've been in a permit-constrained environment, buying back our shares aggressively, continue to see a lot of value. And the intrinsic value of CRC is phenomenal once you look at all the upcoming catalysts. So we'll continue buying back our shares. So we fully expect to continue that program. And what this allows us to do as we think about capital allocation by bringing in incremental cash flow and again, enhanced with synergies, it allows us to be able to continue to do all of the above, as we've been doing, increase the fixed dividend year-on-year, buy back shares.

But now, we also have the ability to invest in the business. So we expect to have a balanced view of the portfolio, looking to grow cash flow per share. That's ultimately what our main objective is. We've been doing it, again, in a permit-constrained environment, and we look to do that in now a world where California is really looking for that California production, and it's giving us a significant runway to drill our inventory, which is very high quality. So one more tool to be able to enhance shareholder value and -- but we continue to see at current levels, a lot of value in our stock, so expect the buybacks to continue.

The next question comes from Betty Jiang with Barclays.

Just wanted to share the congratulations on the deal as well as the California bills. It's really coming at a time where Francisco, you guys have a lot more choices today on how to allocate capital. And earlier, you mentioned you're very much focused on per share growth. But I'm just curious how you're thinking about the investment opportunities across the portfolio now between Aera assets, the newly acquired Berry and then Legacy. Are there just things that we might underappreciated or these assets just being so underinvested for so long that -- how should we think -- what are you looking at when you think about allocating capital across the portfolio now?

Yes. No, it's -- if you look at the maps that we put on our PowerPoint, you will not find the [indiscernible] and strategic fit of the portfolio. Just to give you an example, Berry owns a property called the Hill which is 480 acres, so 3/4 of a section. It's in the middle of the Belridge field. It's not adjacent. It's not close to Belridge, it's inside of Belridge, and that produces about 3,500 barrels of oil per day.

As it's the tradition in California, every operator builds their own facilities. No centralized facilities, and that presents a very compelling opportunity to extract savings and real synergies very near term. And when we looked at Aera -- and you've asked this question before, Betty, the assets are performing extremely well since we bought Aera, the declines are shallower. The production has just been even more and more steady. So when you look at the kind of the missing acreage and some of the missing parts of Berry, expect that to be just as high quality as the rest of the Aera portfolio.

So -- but you're right, these assets have been -- assets that have either incredibly good rock, that's benefit of California production is conventional, low decline, fantastic rock and with a very strong backdrop with California needing more production. And with the know-how of our team to be able to develop these assets, I expect the Berry portfolio to be very competitive, similar to Aera and CRC's, right?

So now we have the ability to really optimize that portfolio and move capital as we increase potentially some activity into projects that are very, very compelling. So excited to have the full force of the inventory as we're getting permits for the first time in more than 3 years. Excited, really excited to be able to really have all the option value come forward and pick the best projects in the combined portfolio.

Great. That's great to see. My follow-up is on the Uinta asset. What are you looking to evaluate? And what are the objectives going forward for you to decide on whether or not to keep that asset within the portfolio?

Yes, Betty. So the deal for us is all about California. That's the -- that's what we focused on, the timing of it, of the permitting reform and the value of being able to buy a very derisked PDP assets that were trading heavily at a discounted PDP value. That's the #1 priority. That and the synergies is what we did the deal.

An added feature is certainly the Berry Uinta portfolio. This is -- we've been 100%, the California company since we -- since inception. So we'll take a look, we'll explore what the Uinta Basin has to offer. We've been hearing a lot about the Uinta Basin as having a lot of activity, a lot of interest. Certainly, Berry has been doing a great job with their horizontal wells. So no, it's an added feature. It brings option value, and we look forward to digging in and learning more about the basin.

The next question comes from David Deckelbaum with Cowen.

Congrats on the deal, and obviously, 237 and 881. Francisco, you just remarked Betty about how this deal is all about California. Also just curious how you think about this deal, either complementing or enhancing non-upstream businesses or if you just see all of the value in this deal really squarely coming from the upstream side?

Yes, the tangible value that David, is in upstream, but by being able to unlock incremental cash flow, improve the cost structure and enhance the margins, that gives us more ammunition and scale to be able to do more in California. I mean, the sentiment -- not only the sentiment shift, but the reality of California is very different today than it's been for years. And it might take some people a while to realize the shift in the view, but that's -- we were excited. I mean, this will continue our focus on growing cash flow per share.

And we have a very strong position on the power business. Berry happens to have about 66 megawatts of power generation in the portfolio. So it's an enhancement across that. And the more power assets that you have, the more flexibility you have to think about not only self-supply, but how do you participate in an exciting power market in California. So expect elements there.

And then there's also Carbon TerraVault benefits of owning more of your production, more of the ability to be able to build infrastructure that connects different fields. The right of ways are extremely valuable. So the more that we own in that space now that we have the ability to invest in CO2 pipelines, it will have an impact -- a positive impact there as well. So it covers every aspect of our business. I mean we did the deal for upstream and for cash flow, but certainly, it positions us for more success as the largest energy company in the state.

If I might ask one more question on the permitting side. Now with this combination, obviously, you're benefiting as well, I guess, from just increased staffing and resources that Berry would have had available to them in California for permitting. With 237, if we assume that Newsom signs off, we move into next year, I guess how do you think about this deal complementing the -- or improving the pace of permit issuance? We know that you can permit up to 2,000 new wells per year in Kern County for the whole industry. Realistically speaking, like how quickly do you think you could start achieving these permits and start being able to deploy incremental capital?

No, absolutely. We were -- the counties, so effectively, the Kern County is going to have the delegation to be able to issue permits, and talking to the county, they're ready to go. They've been looking to get the Kern County EIR established for some time, very supportive of our industry. They've been staffing up on the permit front. And like I said, 2,000 wells per year for a decade gives us a full access to our inventory, and we expect to be a very large participant on the permitting process.

So yes, we have our own staff ready to go. We have permits ready to be filed. Some of them already have been filed. We will wait for the governor to sign the bill, effective January 1. So expect a quarter, maybe 2 quarters max to be able to get all the -- to get the incremental activity going. But everybody is getting ready, and we'll have time between now and January 1 to make sure all things are moving in the right direction. So we're ready to go and excited about the opportunity. It's really been a long time coming. And yes, we can wait.

The next question comes from Nate Pendleton with Texas Capital.

And congrats to both of the teams on the transaction. Francisco, Berry had been able to keep California production roughly flat despite the permitting headwinds in the state. Can you talk about how that low decline production base complements your assets and potential maintenance capital going forward?

Yes. No. Thanks, Nate. Yes, maybe not something that our investors have appreciated, but Berry has been 4 years keeping production flat in kind of the same environment we've had in the -- so about $70 million to -- annually to keep production flat. So a great portfolio. Again, we know the assets extremely well. Really good fit and very similar, very similar in every respect. And like I said, even inside of our field boundaries in some cases. But I would expect the corporate decline to be the same as we've been trending prior to the deal. So 10% to 15%, call it, 12.5% midpoint with our capital. And as we get to deploy capital now with the full extent of the portfolio, expect to see a very capital-efficient program of conventional assets.

So yes, the Berry portfolio fits us very, very well, and expect the -- it's hard to find assets of the quality of our combined portfolios. And low decline in the shale world with shrinking inventory, that's never been the issue in California. It's an inventory-rich environment with [indiscernible] just without the need to really stimulate, it's more about maintaining pressure. It's more about recovery factors. And we know these assets wells. We I think when we picked up Aera, we brought a lot of engineering expertise that know how to run the steamfloods and [indiscernible] and that's what Berry owns. So I look forward for the teams to build a super team in the state to get access to all that resource.

That's great. And as my follow-up, perhaps for Francisco or Fernando, if he's on Q&A. It looks like that first operated Uinta pad delivered really encouraging early results from what we see in the PowerPoint. Is there anything you can share on how those wells are trending versus expectations and how you see those going forward?

Yes. Thank you, Nate. That's a very good question. And just for the benefit of the larger audience, let me provide just a quick overview of Berry and the Uinta Basin, and then I'll address the specific pad that you're asking about, Nate. But Berry holds 100,000 acres in the basin. We have high working interest. It's mostly held by production. And obviously, that gives us operational flexibility in terms of the pace of development. The basin is very rich in oil and gas, and there's significant drilling activity currently in the basin.

And Berry's focus shifted from legacy vertical wells to horizontal wells in 2024, initially targeting the Uteland Butte formation, which is 1 of 5 different reservoirs that we produce from in the basin. And actually, the industry has targeted all 5 reservoirs for horizontal well development as well with success.

But this year, going back to your question, Nate, this year, we drilled our first operated pad, 4 wells, 3-mile laterals, targeting this prolific Uteland Butte reservoir. The wells were put on production in August, and production from the pad is increasing every day as the wells continue to clean up. As mentioned, the pad is currently making about 3,800 barrels of oil equivalent, 93% oil, about 7% gas. That's gross production. And remember that our net production currently or in the first half of the year in Utah was about 40 -- or is about -- was about 4,200 barrels of oil equivalent per day.

But we expect to have big production from these wells in late September. And these results, Nate, are really consistent or even slightly better than our offset wells or offset nonoperated wells. So we're really encouraged with the initial results from these wells and with the potential that we have in the basin with horizontal well development.

The next question comes from Michael Furrow with Pickering Energy Partners.

Congrats on the deal. Obviously, it seems like there's a lot of benefits here. It seems like a logical natural combination. The state seems to be taking a more supportive stance towards the industry. But are there any regulatory approvals that need to be applied before this transaction can cross the finish line?

Thanks, Michael. So it's -- we expect to follow kind of the standard review process on an HSR basis. Given the size of the transaction, nature of the assets and the fact that this is an upstream combination, we don't anticipate any federal regulatory issues. Similarly, we don't expect any -- there's no state regulatory approvals needed.

That's great detail. And then I just have a follow-up on synergies. So that's been one of the items that's really stood out for us over the last year is just the positive execution on the Aera synergies that the company outlined. So is there anything that the company has learned through the Aera integration that made it easier to underwrite the synergies in this deal? And maybe as a quick follow-up to that, is there any sort of breakdown you can provide in the synergy target between operating costs, corporate costs and tax?

Yes. I mean, I think the learnings really comes from tremendous execution from the team. It's a -- there's certain types of synergies, especially personnel-related synergies that a lot of companies will advertise when doing deals. But what we really liked about Aera and we're going to do again with Berry is reimagine the California oilfield and make sure that when you have -- when you're looking at water, when you're looking at -- when you're looking at natural gas and power, you're able to move all of those into the best place to enhance margins. And that's what we've been able to do very successfully with Aera, and we see some very tangible opportunities to do that again here.

We also are -- part of Berry is C&J. C&J is a great Well Services company, has a significant participation of the market in California. And as we look at some of the cost and cost inflation challenges, having an integrated solution in-house is something that we look forward to thinking about. So there's a lot of compelling aspects to this deal and -- in terms of a breakdown, I would say it might track something similar to Aera in terms of proportions. We look to -- Berry's spin on their a term loan that we'll be able to refinance and we think the market backdrop is favorable to do so. So there will be an element of improved interest expense. There will be an element of corporate savings and operating savings and also some enhancements on the supply chain. So proportionately weighted similar to Aera, and we're ready to get started.

The last question today comes from Noel Parks with Tuohy Brothers.

Good morning. I was wondering, just as far as the deal terms, is there a lockup condition involved or collars on the deal?

No, it's a straightforward deal, no lockups or colors. Berry is a publicly traded company. You can -- you see some of their ownership levels and who owns it. So you would see a lot of similarities in people that invest in Berry with CRC. So -- but nothing I would say out of the norm in terms of the deal, pretty straightforward all-stock deal.

Great. And you mentioned that the right of ways that the Berry assets would offer could be particularly valuable for Carbon TerraVault. So I was just curious if they had any -- well, I guess, since there is a good bit of overlap, does this move the needle on pore space at all? Do they have any estimates? And I'm just wondering, is there -- does it complicate or require you revising any of your Class VI permit applications to the EPA?

Yes. I will not look at the Berry assets as additive to pore space at this point. Well, our team will certainly look at it. But -- so no changes on Class VI. But it allows you -- I mean, so this weekend, we received the good news that the pipeline moratorium has been lifted for CO2s and for CO2 injection. So if you think about a world where we can connect brownfield emitters to our storage, every mile of right-of-way is valuable. Every straight line that we can either recondition or build new pipe is extremely valuable.

So land ownership is one of the strengths of CRC and adding more acres to the combination to the combined company as we look to build that infrastructure of the future to decarbonize the state, that all has infinite value. So excited to again, add more land and more acreage to our portfolio. And I would say it's on the right-of-ways and CO2 pipelines where we see the connectivity with CTV.

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

Thank you for your time today and your interest in CRC. We look forward to keeping you updated as we move towards closing. Thank you. Bye-bye.

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

Good day, and welcome to the California Resources Corporation Second Quarter 2025 Conference Call. [Operator Instructions]

Please note this event is being recorded. I would now like to turn the conference over to Joanna Park, Vice President of Investor Relations and Treasurer. Please go ahead.

Good morning, and welcome to California Resources Corporation's Second Quarter 2025 Conference Call. Following prepared remarks, Members of our leadership team will be available for questions. By now, I hope you've had a chance to review our earnings release and supplemental slides. We have also provided information reconciling non-GAAP financial measures to comparable GAAP financial measures on our website and in our earnings release. Today, we will 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 allows us to get to more of your questions.

I will now turn the call over to Francisco.

Good morning, everyone. Thanks for joining us. We're excited to share today's update with you. As you can see from our release last night, 2025 is shaping up to be a very solid year. Our teams are executing extremely well, driving strong operational performance, strategically advancing our carbon and power platforms and returning meaningful capital to our shareholders.

Let me walk through a few highlights before handing it over to Clio to discuss quarterly results. First, we delivered record quarterly returns to shareholders. We returned nearly $290 million this quarter, more than 260% of our free cash flow. These record returns were largely related to a discounted share repurchase from ICA facilitating an orderly reduction in their ownership.

Our actions reflect our strong conviction in the value and upside we see in our stock. Next, we've implemented ARA-related merger synergies ahead of schedule. About a year ago, we announced this transformative merger and committed to delivering meaningful synergies. We fulfilled that commitment 3 months ahead of schedule, fully implementing our $235 million target. Importantly, the net present value of these synergies over the next 10 years is estimated at approximately $1.4 billion. That's about 2/3 of the announced deal value or more than 100% of the value of our equity issued at the time of the transaction. We've demonstrated our ability to identify value-accretive combinations execute seamless integrations and unlock long-term value through scale and operational synergy.

Third, strong operational performance has enhanced our full year outlook. Year-to-date, operational execution and reservoir performance have exceeded expectations. By building on this momentum with the addition of a second rig we strengthened our outlook, resulting in a roughly 7% increase in adjusted EBITDAX. A few weeks ago, we were encouraged by the California Energy Commission's response to Governor Newsom directive to ensure fuel reliability during the energy transition. We welcome the state's greater collaboration with refiners and our industry. The state is actively working to improve the oil and gas permitting process and we expect additional details once the legislature reconvenes in mid-August.

If approved, these reforms could give us greater flexibility to access our extensive inventory, while being mindful of shareholder returns. We applaud the governor's leadership to advance solutions that address affordability, protect local jobs and reduce foreign oil dependence.

Clio, over to you.

Thanks, Francisco. I'll start with a review of our second quarter results and financial highlights.

Our focus on base production management continues to deliver results. We recorded net total production of 137,000 BOE per day with average realizations at 97% of Brent before hedges and 100% after hedging. Nearly all of our costs for the second quarter were within or in some cases, below the lower end of our guidance. Importantly, our first half 2025 costs were down approximately 11% from the second half of 2024, reflecting lower G&A expenses, lower nonenergy operating costs and lower taxes other than on income. With continued cost discipline and the benefit of ARA-related synergies, we've now reduced nearly all of our 2025 operating expense items by about 7% when compared to our original outlook, even as we anticipate higher energy costs and increased levels of activity in the second half.

This performance underscores our ability to effectively manage costs and protect margins. Our teams have done an outstanding job staying focused. Total capital was $56 million with 60% allocated to high-return workovers and sidetracks. Capital came in lower, mainly due to portfolio optimization as well as project deferrals into later this year. Adjusted EBITDAX for the quarter was $324 million, exceeding consensus expectations. This performance was driven by strong commodity price realization higher-than-expected production and lower operating costs. We generated $109 million of free cash flow or $165 million before changes in working capital, demonstrating the resilience and cash generating power of our assets. Now on our capital returns to shareholders. We returned a record $287 million in the second quarter, bringing year-to-date shareholder returns to nearly $422 million. This quarter's returns were largely driven by a strategic $228 million block repurchase from ICAS executed at $46 per share.

Since combining with ARA, we've now repurchased approximately 45% of the equity issued at the time of the merger at an average price, reflecting about a 13% discount to the merger closing price. This has further enhanced the economics of an already accretive deal. Repurchases to date have utilized available cash on hand, reinforcing our long-term capital allocation priorities of delivering shareholder returns, maintaining balance sheet strength, and enhancing shareholder value. Since the inception of our share repurchase program, we returned nearly $1.5 billion to shareholders in dividends and share repurchases, representing approximately 86% of cumulative free cash flow over the last 4 years. We have slightly over $200 million remaining under our current share repurchase authorization, which was recently extended through June 2026.

Looking ahead to the second half of 2025, we are operating from a position of strength. Our leverage remains low at 0.7x. We have an undrawn revolver, and total liquidity remains robust at over $1 billion. We've had solid execution year-to-date, but it gives us the confidence to raise full year production guidance lower both cost and drilling capital expectations and increase our adjusted EBITDAX forecast. We are now expecting a 9% improvement in our 2025 free cash flow outlook before working capital, even after adjusting for lower oil prices versus our initial assumptions.

All in all, a very solid quarter. Back to you Francisco.

Thanks, Clio. Before we move to Q&A, let me quickly mention a couple of other items. Near term, we're focused on getting California's first CCS project into operation. CTV JV received construction authorization from the EPA. This was a big milestone as it was the first EPA awarded authorization to construct for our Class 6 project.

We expect to complete construction of the Class 6 wells at or around year-end 2025. Pending the receipt of final regulatory approvals, we will be ready to inject early in 2026. As we continue to maximize the value of our assets, we're actively engaged in discussions with multiple potential counterparties to supply power with a pathway to CCS from the Elk Hills power plant and CTV CO2 storage reservoirs for a decarbonized energy solution.

To add, there are several exciting developments on the regulatory front driven by the California Public Utilities Commission. The proposed reliable and clean power procurement program could unlock a new market for our carbon management platform.

In closing, we have a differentiated business model, benefiting from an integrated strategy and are uniquely positioned to support California's energy transition. Our high-return oil developments complement our expanding carbon management and power platforms. It's well known that California has some of the highest energy costs in the country.

Fortunately, CRC is positioned to provide cleaner and more affordable in-state production which California needs, while advancing decarbonization solutions across the central industries. As the next generation of energy infrastructure continues to develop, CRC has the assets and people to lead a changing energy landscape. One that demands affordability, reliability and responsibility. CRC truly is a different kind of energy company.

Operator, let's open the line for questions.

[Operator Instructions]

The first question comes from Scott Hanold with RBC Capital Markets.

Francisco, you had mentioned the improving regulatory environment in California, and it sounds like there's things going on a multitude of fronts. Maybe attacking one of them specific to oil and gas permitting. There are 2 avenues in which you've addressed in looking at getting permits, which includes, obviously, the Kern County litigation that appears to be nearing a resolution. Can you give us your sense of -- what is your view of these events? And how does that shape your current perspective on when you could receive new oil and gas permits? And as you look at all the things happening in California, like what are their priorities, first and foremost, like where do you think you're going to see the initial benefits of any kind of regulatory changes?

Scott, thank you for the question. Yes, we have a very dynamic and we're optimistic about all the changes happening in California. The state is actively looking to resolve the permitting situation and to help stabilize local production. A lot of conversations, which we feel are very constructive and what the governor appears to be signaling is that they're going to -- he's going to instruct the legislature to provide a fix for permitting in the state.

Right now, the legislature is on a summer break, and we expect more details to come out when they reconvene in mid-August. So it's tough to speculate as to ultimately what the outcome is going to be. But we've been building the company for this moment. We're well positioned. We're at the table, and we're ready to provide solutions. The answer really to California's energy challenges is that we need to be both affordable and clean and that is local production, and that's the CRC barrel. So we will see in terms of time line. It's hard to predict. Like you said, there's a lot of different fronts are being advanced, including the Kern County EIR litigation. But we see the leadership obviously rising up to the challenge and looking to stabilize local production and we're ready to go when that happens. So once the legislature reconvenes we'll have a few weeks in session, where we will know the outcome of those discussions sometime in September, early October.

The next question comes from Betty Jiang with Barclays.

It's really impressive to see the quarters -- the recent quarters showing stronger production with lower CapEx consistently. Could you just elaborate on what's driving that underlying capital efficiency improvements and how that could inform your go-forward maintenance CapEx outlook?

Yes, Betty, thank you. So we've been now operating with the air assets for a year. It's clear that those assets are just performing extremely well. the combination of strong assets with the CRC plus ARA operational leadership, it's been just phenomenal to watch and the performance, if you measure it in terms of gross production continues to outperform expectations and certainly what we underwrote when we did the deal.

So it's been just a year of quarter-over-quarter success in the team managing the basic client extremely well. We had guided to a range of $500 million to $600 million in terms of maintenance capital. But I think we're comfortable today to say we will be at the lower end of that range. And once we get permits back on track and once we have the full information as to how that's going to work. We'll come back with an updated number, but certainly, we see the capital efficiency and the trend lines being very favorable so far.

That's helpful. A follow-up to you, Clio. Just on cash tax benefits. Thank you for the guidance for 2025. How do you see that saving evolving in 2026 and beyond.

Great question. Let me frame a little bit the broader impact of the bill, and I'll jump into our outlook for '26. But we see a lot of benefits from the One Big Beautiful Bill for us and how it will help us really bring more clean and reliable energy to California. There's many pockets of improvement there. The bill really improves the long-term economics for both our E&P and our carbon management businesses. It restores and locks in really key tax incentives, notably 100% bonus depreciation and immediate R&D expensing, but it's also a win for our carbon management business.

Our CCS projects are earlier stage and capital-intensive by nature. So the features you see in the bill, such as R&D expensing, bonus appreciation and also the additional interest deductions, those really enhance our project economics. So Betty, as it stands today, we expect about $35 million in cash tax savings for this year. So that's a nice add to our free cash flow story.

But if you look ahead and what that could mean for future here, we expect our cash taxes as a percentage of EBITDAX, that, that will decrease from the low double digits to high single digits. So to give you a sense of scale over a 5-year horizon and assuming current activity levels and a [ $55 to $65 ] Brent price environment, cumulative tax savings to be in the $80 million to $150 million range. And obviously, additional activity would drive incremental savings there.

So all in all, the bill relief that supports our free cash flow story, and it provides some additional tailwind for our carbon management business.

And we have a follow-up from Scott Hanold from RBC Capital Markets.

I was kind of curious on Page 7, you all highlighted some of the general project returns that you all have going on in the second half of this year. Could you give us some color as you think about, again, the potential of getting new well permits maybe in sometime in 2026. How does -- how do those well breakevens compared to a workover side track? And if you had new permits to maintain production, what is sort of the optimal mix of the three?

Scott, yes. So just a reminder, we're running 2 rigs right now. We added our second rig in June primarily, it's going to be drilling side tracks for the rest of the year. And we also have a full year 2026 already permitted for those 2 rig lines with a mix that would be similar to this year, workovers and sidetracks.

As permits come back as we get the ability to drill new wells. I mean you can see that the returns or implied returns with very low breakeven prices will be very additive to the portfolio and the flexibility that we have. So it's difficult to pinpoint as we are still in a permit-constrained environment the what ifs, but we see a very deep inventory of projects.

As a reminder where conventional assets which really you look at the quality of the rock. We're not tight shale that needs very high capital-intensive long laterals with 80 state tracks, what we do is, it's about pressure support. It's about injection rates. It's about bypassed oil. So we feel the inventory, and it's several decades of good, attractive inventory as we go and increase recovery factors. So the rest, we see those incremental wells being very competitive to what we have today.

The next question comes from Josh Silverstein with UBS.

Clio, you had mentioned you plan to retire the remainder of the 2026 note in the second half of this year. After that, how are you thinking about free cash flow allocation going forward you don't have another maturity until 2029. So how are you thinking about the buyback? I know you were just opportunistic, but is there more of a game plan to have kind of a percentage allocation? Or how would you think about that?

Sure, Josh, and I appreciate the question. Let me start by reemphasizing that we're committed to driving long-term shareholder value and providing shareholder returns. It's really a core part of our value proposition and our track record in this regard, really speaks for itself. We've returned about $1.5 billion in dividends and share repurchases since the program inception and really, that's roughly 30% of our current market cap. You asked what we're going to do on the buyback side. I mean, looking forward, we plan to remain opportunistic with share repurchases.

We still have over $200 million available under our share repurchase program, and we extended that through June 2026. And we feel good about the performance of our assets and our free cash flow trajectory. But that being said, we're being thoughtful. I mean if you look at just this year, we've already returned capital at scale. We've returned 178% of free cash flow back to our shareholders.

And in the second half of this year, we need to balance any incremental buyback activity with our other strategic priorities, and you flag them. We're on track to redeem the remainder of our 2026 notes during the second half. So for us, longer term, I'd say it's about taking a balanced approach here. We're going to stay disciplined, but also focused on long-term value.

Got it. And then on the CVT I project, I think you guys have moved from year-end '25 to early '26 as the new first injection days. I think this was from some of the EPA delays there. Can you just talk about broadly how your construction is going? Would you have been on track for the year in '25, 1st injection? Just any update there would be great.

Josh, yes, so we are on track to be done with construction by the end of the year. We talk about ready to inject and -- by the end of the year. What that means is that we take care of things that we control, which is getting the project ready and to go. What's more difficult to handicap is the speed for the EPA to give the final approval. And that's what we're signaling early 2026.

Part of it is holidays, part of it is first mover. We are the furthest along of any company in the U.S. in terms of moving forward a Class 6 permit from permit to execution. So there's an expectation that the EPA is going to react quickly, but ultimately, we don't have a precedent to compare to. But we'll be ready with construction and ready to inject by the end of the year and start with our first project early in '26.

The next question comes from Kale Akamine with Bank of America.

Maybe I'll follow up on the permitting front. And I appreciate that we're going to have to wait on the Newson bill. But wondering if you can comment on the details of that proposal. My understanding is that there's kind of the P&A piece where every 2 wells P&A will allow one new drilling permit. Do you see that P&A piece as a bottleneck? Or do you think there's already sufficient industry activity to build a healthy permitting queue?

Kale, yes, I would say details, I wouldn't run with any details at this stage. There's a proposed language. There's still a few weeks before we know what certainty -- certainly, we're aware of the plug-in requirement. But we already have a very aggressive P&A program already. So it's something that, as we've adapted and built a California-made E&P company. This is something that we do as part of our stewardship of the assets, and we do it extremely well in a very efficient way.

So as we move forward, we don't see a P&A requirements as being something that ultimately gets in the way from a CRC perspective. So we continue to adapt and difficult to speculate on exactly what the solution will be. But we're really excited about the ability to showcase the asset base and this just phenomenal inventory that we've built over the years and almost 2 million acres of minerals behind it with very high NRI. So I think the focus is going to be on the California return, the California come back on oil and gas and we're being very -- having very constructive conversations to get that unlocked so it benefits the affordability concerns that Californians have.

I appreciate those details, Francisco. Maybe just a reference item. How many wells are you P&Aing this year? Or how many do you plan to do on a given annual year basis?

Yes. I think what we disclosed publicly is we're averaging about 1,500 wells per year.

Got it. I appreciate that. My second question is on the potential Elk Hills PPA. What do you think your current breakeven is to leave the grid? And I appreciate that there's many individual pieces and they're very nuanced, but maybe if you could address one specifically, what do you think you're going to get for resource adequacy in 2026?

Yes, we're still not ready to guide until 2026 on any front. We still see the print for '25 highest ever resource adequacy for 2025 in a state that's very short on reliable power, we see a long-term success on that program, but we don't want to put any numbers in '26. We still haven't placed any contracts in motion. What we're also thinking about is really how do we get the market to price the value of that power generation into our multiple. And that's how we keep talking about a number of customers that could come behind the meter and take that power and be a premium to what we make today and give us the duration on the contract.

That's been the focus and to stay on that front, we're making really good progress on what I would say are framing discussions and have interest from several groups. We remain very encouraged and our focus is on making the right deal. So where near term, we don't -- you still are looking at potentially participating in the resource adequacy program is that right deal that has the long-term contract that ultimately will add significant value to the shareholders.

So in our conversations with customers, it's clear that we -- that they need power now, that's obvious. But clean power is still very much a priority. So reliable clean power in a state like California, it's going to come from natural gas with CCS. And we're convinced that's the winning strategy and when we keep pushing forward to align the best contract so that we can add value to our power business.

The next question comes from Zach Parham with JPMorgan.

Just wanted to follow up on the Elk Hills power plant and a potential power deal there. Can you give us a sense of potential timing for signing something? I know you're in negotiations that have talked about having conversations. But is that likely to be something that happens later this year? Is 2026, a possibility? Kind of how are you thinking about that from a timing perspective?

Yes, Zack, we still are very much focused on it, and our plan is to provide an update before the end of the year. There's a lot of interest. There's a lot of conversations happening we highlighted on the script another evolution of a story, which is the CPUC in California is considering adding carbon capture alongside with nuclear and hydro into the reliable and clean power procurement program. So there's clearly not only market signals or regulatory support for the type of projects that we're going to -- we're pursuing.

We're also seeing M&A in the state, so buyers of existing power plants that are not in California coming into California and talking about carbon capture, the solution. We're also seeing hyperscalers doing deals in natural gas in other parts of the country. So we see -- we have an advantage in the portfolio that we'll capitalize on that advantage. And the feedback we're getting is Kern County is going to be a great site for development of data centers. We have a firm stream of natural gas.

We have land, we have permitted port space, and we have existing power generation. This is not a turbine in back order. This is an actual and running power plant that has an extremely high reliability. So we see the AI and hyperscaler market looking to -- for what we have and very much pursuing something to announce later this year. So the time line hasn't changed and continue to be excited about the prospects and the conversations we're having.

And then my follow-up on cash return. I mean, you opened very aggressively on buy backs recently. The other portion of that has been your dividend. How do you think about dividend growth over the medium and long term?

Yes. We've been very successful in having a combination of buybacks and a fixed dividend. As it relates to the fixed dividend, we like the growth model. And we've grown our dividend every year for the last 4 years. So it's a key part of our shareholder return policy and something that we evaluate with our Board of Directors every year. So it's something that we think our shareholders really value and appreciate and it's something that will continue to be in part of the package of shareholder cash return to the shareholders every year. So that's a main stay, and we'll continue to evaluate for a potential further increase.

The next question comes from David Deckelbaum with TD Cowen.

I wonder if we can go back to just the maintenance capital conversation, just appreciating that you all will update that number once permitting becomes a little bit more clear, but I'm curious, just as you kind of sit today, maybe Clio, you could chime in on just the management of the free cash profile. How -- if you had an unconstrained permitting environment, how quickly would you look towards to move to maintenance in the current commodity environment?

David, thanks for the question. So the way we think about streamlining our permits is that we'll have a lot more flexibility in the portfolio. And it's another tool to add to our very successful shareholder return program. We have grown cash flow per share every year, and that's what permit constraints and lower pricing. And so we feel that we're extremely well set up. So if you think about what we have, we have a very strong, solid balance sheet.

The team is executing superbly and there's a very strong foundation of assets with production that have very low declines and low capital intensity. So permits, new permits will give us an ability to also deliver value by drilling our extensive inventory. So the way to think about it is a way to enhance what we've already delivered over multiple years.

So what that means in terms of shareholder returns is we will be looking for the best mix to deliver that continuing growth on cash flow per share. So we don't look at maintenance production as the objective. We look at growth in cash flow per share, the objective. So yes, we keep in mind that commodity environment, we keep in mind where the stock is trading, and we keep in mind the returns on our wells, and that all goes into the mix as we make capital allocation decisions.

So it's going to be a great showcase of what this inventory is looking to do, but always focus on what's the best way to return capital to shareholders. So it's something that we'll address with more specificity once we know exactly what we have in terms of new permits. In the meantime, we have full permits for the remainder of the year for the 2 rigs, and we can continue that going into next year for 2026.

So more of the same great returns with some enhancements that will come from drilling inventory.

I appreciate the color, Francisco. And maybe just as a follow-up to that, you talked about the permit backlog, and I know that the company had pivoted a bit this year to applying for conditional use permits under CalGEM. At this point, what has the experience been like? And with a 2-rig program, what's the backlog in terms of drilling years at this point?

Yes. So we continue -- so as I mentioned earlier, the conversations right now are trending to a legislative fix on permits, and that's what the language that was floated around publicly from the governor's office.

That is separate from what we had been talking about, which was the Kern County ER litigation and the conditional use permit, right? So regulatory versus legislative fixes. So we continue to move all things in parallel. We see there was a revised EIR that was approved at the county and is heading back to the trial court for consideration. And we also having continued to work to satisfy the requirements on the conditional use permits.

So none of that has been slowed down, but the focus and attention is on a legislative fix that ultimately will be the best path forward to get permits back on track. So the inventory in terms of the duration of that inventory, it depends on the ultimate outcome of the discussions. There's different ways that we can ultimately get back to drilling more wells. But we haven't had any issues with sidetracks and workovers, and we continue to permit those and continue to build that inventory beyond 2026.

So progress continues and across multiple fronts. And I think we'll have a few updates by the end of the legislative session so that we can true up to where we are and where we think the future will be.

The next question comes from Nate Pendleton with Texas Capital.

Congrats on the strong quarter, with my first question, I wanted to dig a little deeper into the Class VI permitting process. Can you share any thoughts on how permitting is progressing for the A1/A2 reservoir and your other CTV projects. Also maybe if you could touch on any meaningful changes you have seen now that the new administration has had a little bit of time to make their mark.

Thanks for the question. I'll turn it to Chris to provide more details on EPA Class VI.

Nate, yes. The EPA tracker continues to be the best estimate out there for timing. We continue to see progress on all the permits that you see there through CTV VI, continue to have a constructive dialogue with EPA, particularly on the back of the first-of-a-kind and applying the learnings from 26R. Nowhere is that more evident than with A1/A2, as you know, in the same complex as 26R, so very close cousin, if you will, very sort of conducive to applying those learnings. I remind you that, that A1/A2 is also part of the Kern County conditional use permit, which was final. So we do see the estimate is likely for a draft permit for A1/A2 this year, and we see the rest of the permits as the tracker is a good estimate. There are estimates. So things can always change, but it looks reasonable to us.

And the BPA is committed to expediting permits, putting more resources behind the different EPA regions. So we're encouraged by the signal to streamline permits on that front and look forward to receipt of incremental Class VI permits in the very near term.

Got it. And maybe staying on CTV. On Slide 16, you added a comment about expecting support for CO2 pipeline transportation from California legislators. Can you provide some details on what you're seeing on the pipeline front.

Yes. It's another area Nate, where we're very encouraged about the progress. There's legislation that's advancing through the California legislature and that would support the construction of CO2 pipelines. The Assembly Bill 881 would basically lift the moratorium on interstate CO2 pipelines. The bill has a lot of momentum. It's currently sitting in the Senate. If it passes the legislature and signed by the governor by mid-October, the bill will be in effect by January 1, 2026.

So we've seen -- we haven't seen this much support and momentum in 2 or 3 years where we've been working on this. So we remain very optimistic that this is an important step towards unlocking the scale of carbon management, and we're seeing a lot of good support and dialogue with California leadership around this topic.

And I understand that there is time for 2 last questions. We have a question from Michael Furrow from Pickering Energy Partners.

It was positive to see the company step in and repurchase shares from ICA when they came to market in June. Now ultimately, the future intentions of each shareholders are unknown. But would you say that CRC is still well positioned to kind of step in again and help support these sellers if they come to market? And if so, would that require an expansion of the authorization program?

Yes. So we absolutely stand ready. We see a tremendous amount of value in our stock. And we started the year one are the first lock-up period came in, and we said we would step in if there was any interest from shareholder exiting. And then we followed through ended the block that we announced earlier. And -- so we continue to stand ready in terms of making sure the exit of any sponsor is efficient. But what we have seen is subsequent to us stepping in, there's ICA, we believe, sold another 1 million shares to a third-party showing that there's a very efficient market and a lot of liquidity for our shares and a lot of appetite for our shares. So we would believe strongly in the buyback program, and we see a lot of catalysts coming that are not recognized in the value of the company. So as we rebuild cash, as we look at paying down debt, buyback continues to be very much an element of our cash return strategy.

That's great. Just a quick follow-up on production taxes. It looked like they came in pretty low this quarter and helped drive some of the quarterly beat versus our model. At the back half of the year, production tax guidance kind of looks similar to the 1Q rate again. So can you inform us on what some of the drivers are for why the production taxes stepped down so much as they did in the second quarter?

Yes, Mike, we can. We had accrued at a higher rate, assuming a higher increase than is the one that we saw. So that's the adjustment that you saw on the production taxes. It's a catch-up.

The next questioner comes from Scott Gruber with Citigroup.

Francisco, I want to come back to the upstream investment strategy. if there is an unconstrained permitting environment, your tax position has improved. Is there any appetite not just to maintain production, but to recapture some lost volumes? Or is that really a question about other calls on capital. You obviously have the carry on the carbon management side. But just curious how you weigh recapturing lost volumes? Or is that off the table?

Yes. I mean, as I indicated, Scott, the way we look at managing the business is around cash flow per share. That's what we think is the metric that drives stock performance and shareholder value. We have been in a permit constrained environment for a few years, but have been able to grow cash flow per share and also with lower pricing. And the focus has been on buybacks and cost-cutting exercises and synergies around the ARA merger.

So on an unconstrained case, now we have the ability to move the top line and we have -- we look forward to the flexibility and added element to continue driving cash flow per share. At the end of the day, it's not growing the business -- the production just for the sake of growing, it's about growing cash flow. And so if we find the right combination of opportunities, we're going to invest into an unconstrained environment to a level that we feel maximizes that cash flow per share.

So I don't want to be prescriptive about rigs or about activity at this stage until we can cross into the unconstrained permitting scenario. But our commitment is to continue to drive shareholder value in the combination of everything we have at our disposal in terms of cost structure efficiencies, in terms of buybacks and in terms of investment. So that's the way we think about the business. It's all about cash flow and cash flow -- growing that cash flow every year.

That makes sense. And then a follow-up on the asset level detail on Slide 15, obviously, your recovery factors...

Excuse me, Mr. Gruber. I'm sorry you were breaking up. Would you please state your question.

Sorry. I'm curious on the recovery factors you show on Slide 15. How much more running room do you think you have to squeeze those recovery factors higher?

Yes. We have truly world-class reservoirs and fantastic rock here. And you might be surprised to see recovery factors that are as high -- but the reality is we have a lot of room to grow. We've seen fields in California that get up to 70%, 75% recovery. And so we have a massive running room. And you can do the math, incremental 1% recovery factor adds millions of barrels of reserves.

So the benefit of not having to deal with very tight rock that doesn't flow, that doesn't have the permeability is that your running room is in the multiple decades of quality inventory. It's about pressure maintenance. It's about making sure you have the right water floods, the right steam floods and yes, running room is absolutely an advantage that we're going to be able to showcase. And then looking at the slide, 97% working interest, 91% NRIs. I don't think you'll find a lot of -- in the public independents that have the quality of runway and inventory that we have here in California.

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

Thanks again for joining us today. We hope to see you at several conferences this fall and hope everybody has a good day. Thank you.

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