California Resources Corporation (CRC) Q2 2025 Earnings Report, Transcript and Summary

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.