Good day, and welcome to the California Resources Corporation's second quarter 2025 conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing star, then zero, on your telephone keypad. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star, then one, on your telephone keypad. To withdraw your question, please press star, then two. Please note this event is being recorded. I would now like to turn the conference over to 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 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 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 ICAF, 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 Aera-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 three 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 two-thirds 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 rest of our 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 EBITDA. A few weeks ago, we were encouraged by the California Energy Commission's response to Governor Newsom's 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 branch 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 non-energy operating costs, and lower taxes other than on income. With continued cost discipline and the benefit of Aera-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 EBITDA for the quarter was $324 million, exceeding consensus expectations. This performance was driven by strong commodity price realizations, 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 ICAF, executed at $46 per share. Since combining with Aera, 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 four 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, which gives us the confidence to raise full-year production guidance, lower both cost and drilling capital expectations, and increase our adjusted EBITDA 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 a Class VI project. We expect to complete construction of the Class VI 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 essential 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. We will now begin the question and answer session. To ask a question, you may press star, then one, on your telephone keypad. If you are using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw your question, please press star, then two. Please limit your questions to one primary and one follow-up. At this time, we will pause momentarily to assemble our roster. The first question comes from Scott Hanold with RBC Capital Markets. Please go ahead. Thank you. Francisco, you had mentioned the improving regulatory environment in California, and it sounds like there's things going on on a multitude of fronts. Maybe attacking one of them specific to oil and gas permitting. There are two avenues in which you've addressed in looking at getting permits, which includes, obviously, the current 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? As you look at all the things happening in California, what are their priorities, first and foremost? Where do you think you're going to see the initial benefits of any kind of regulatory changes? Hey, Scott. Thank you for the question. Yeah, 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. What the governor appears to be signaling is that 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. It's tough to speculate as to ultimately what the outcome is going to be. 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 a CRC barrel. We will see in terms of timeline. It's hard to predict. Like you said, there's a lot of different fronts that are being advanced, including the current county EIR litigation. We see the leadership of the state rising up to the challenge and looking to stabilize local production, and we're ready to go when that happens. 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. Please go ahead. Hi. Good morning to you guys. It's really impressive to see the recent quarters showing stronger production with lower CapEx consistently. Could you just elaborate on what's driving the underlying capital efficiency improvements and how that could inform your go-forward maintenance CapEx outlook? Yeah, Betty, thank you. We've been now operating with the Aera assets for a year. It's clear that those assets are just performing extremely well. The combination of strong assets with the California Resources Corporation plus Aera operational leadership, it's been just phenomenal to watch. The performance, if you measure it in terms of gross production, continues to outperform expectations and certainly what we on the road when we did the deal. It's been just a year of quarter-over-quarter success and the team managing the basic line extremely well. We had guided to a range of $500 million - $600 million in terms of maintenance capital. I think we're comfortable today to say we will be at the lower end of that range. 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. Certainly, we see the capital efficiency and the trend lines being very favorable so far. That's helpful. Thank you. 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? Hi, Betty, and great question. Let me frame a little bit the broader impact of the bill, and I'll jump into our outlook for 2026. We see a lot of benefits from the one big beautiful bill for us and how it'll help us really bring more clean and reliable energy to California. There are 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 a 100% bonus depreciation and immediate R&D expensing. It's also a win for our carbon management business. Our carbon capture and storage projects are earlier stage and capital-intensive by nature. The features you see in the bill, such as R&D expensing, bonus depreciation, and also the additional interest deductions, really enhance our project economics. Betty, as it stands today, we expect about $35 million in cash tax savings for this year. That's a nice add to our free cash flow story. If you look ahead and what that could mean for future years, we expect our cash taxes as a percentage of EBITDA will decrease from the low double digits to high single digits. To give you a sense of scale over a five-year horizon and assuming current activity levels and a $65 Brent price environment, cumulative tax savings to be in the $80 million - $150 million range. Obviously, additional activity would drive incremental savings there. All in all, the bill really further supports our free cash flow story, and it provides some additional tailwinds for our carbon management business. With a follow-up from Scott Hanold from RBC Capital Markets, please go ahead. Yeah, thanks. I was kind of curious. On page seven, 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 sometime in 2026? How do those well break-evens compare to a workover or sidetrack? If you had new permits to maintain production, what is sort of the optimal mix of the three? Hey, Scott. Yeah, just a reminder, we're running two rigs right now. We added our second rig in June. Primarily, it's going to be drilling sidetracks for the rest of the year. We also have full-year 2026 already permitted for those two 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, you can see that the returns or implied returns with very low break-even prices will be very additive to the portfolio and the flexibility that we have. 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, we're 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 stage tracks. What we do is it's about pressure support. It's about injection rates. It's about bypassed oil. We feel the inventory, and it's several decades of good, attractive inventory as we go and increase recovery factors of the reservoirs. We see those incremental wells being very competitive to what we have today. The next question comes from Josh Silverstein with UBS. Please go ahead. Yeah, thanks, guys. 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 know, you don't have another maturity until 2029. 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% allocation, or how would you think about that? Thanks. 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. 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. That's roughly 30% of our current market cap. You asked what we're going to do on the buyback side. 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. We feel good about the performance of our assets and our free cash flow trajectory. That being said, we're being thoughtful. 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. In the second half of this year, we need to balance any incremental buyback activity with our other strategic priorities. You flagged them, we're on track to redeem the remainder of our 2026 notes during the second half. 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. On the CTV I projects, I think you guys have moved from year-end 2025 to early 2026 as the new first injection date. 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-end 2025 first injection? Any update there would be great. Thanks. Hey, Josh. Yeah, we are on track to be done with construction by the end of the year. We talk about ready to inject by the end of the year. What that means is that we take care of the things that we control, which is getting the project ready to go. What's more difficult to handicap is the speed for the EPA to give the final approval. That's what we're signaling, early 2026. Part of it is holidays. Part of it is first mover. We're the farthest along of any company in the U.S. in terms of moving forward a Class VI permit from permit to execution. There's an expectation that the EPA is going to react quickly, but ultimately, we don't have a precedent to compare it to. We'll be ready with construction and ready to inject by the end of the year and start with our first project early in 2026. The next question comes from Kalei Akamai with Bank of America Merrill Lynch. Please go ahead. Hey, good morning, guys. Francisco, Clio. I want to start with maybe a follow-up on the permitting front. I appreciate that we're going to have to wait on the Newsom bill, but wondering if you can comment on the details of that proposal. My understanding is that there's kind of a P&A piece where every two 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? Hey, Kalei. Yeah, I would say details, I wouldn't run with any details at this stage. There's a lot of proposed language. There's still a few weeks before we know with certainty. Certainly, we're aware of the plug-in requirement, but you know, we already have a very aggressive P&A program already. 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. We do it extremely well in a very efficient way. As we move forward, we don't see P&A requirements as being something that ultimately gets in the way from a CRC perspective. We continue to adapt. It's 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, you know, almost 2 million acres of minerals behind it with very high NRI. I think the focus is going to be on the California return, the California comeback on oil and gas. We're having very constructive conversations to get that unlocked so it benefits the affordability concerns that Californians have. I appreciate those details, Francisco. Maybe as 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? Yeah, I think what we disclosed publicly is we're averaging about 1,500 wells per year. Got it. No, I appreciate that. My second question is on the potential Elk Hills PPA. What do you think your current break-even is to leave the grid? 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? Yeah, we're still not ready to guide into 2026 on any front. We see the print for 2025 highest ever resource adequacy for 2025. In a state that's very short that reliable power, we see a long-term success on that program. We don't want to put any numbers yet in 2026. 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. That's what we keep talking about, a number of customers that could come behind the meter and take that power and pay a premium to what we make today and give us the duration on the contract. That's been the focus. 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. Our focus is on making the right deal. We're near term. We still are looking at potentially participating in the resource adequacy program. It's that right deal that has the long-term contract that ultimately will add significant value to the shareholders. In our conversations with customers, it's clear that they need power now. That's obvious. Clean power is still very much a priority. Reliable, clean power in a state like California is going to come from natural gas with carbon capture and storage. We're convinced that's the winning strategy. We keep pushing forward to line the best contracts so that we can add value to our power business. The next question comes from Zach Parham with JPMorgan. Please go ahead. Hey, thanks for taking my question. 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 and have talked about having conversations, but is that likely to be something that happens later this year? Is 2026 a possibility? How are you thinking about that from a timing perspective? Yeah, Zach, 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, and there's a lot of conversations happening. We highlighted on the script another evolution of the story, which is the California Public Utilities Commission in California is considering adding carbon capture and storage alongside nuclear and hydro into the Reliable and Clean Power Procurement Program. There's clearly not only market signals, but regulatory support for the type of projects that we're pursuing. We're also seeing M&A in the state, with buyers of existing power plants that are not in California coming into California and talking about carbon capture and storage as a solution. We're also seeing hyperscalers doing deals in natural gas in other parts of the country. We see we have an advantage in a portfolio that will capitalize on that advantage, and the feedback we're getting is Kern County is going to be a great site for development of AI data centers. We have a firm stream of natural gas, we have land, we have permitted pore 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. We see the AI and hyperscaler market looking for what we have and very much pursuing something to announce later this year. The timeline hasn't changed and we continue to be excited about the prospects and the conversations we're having. Thanks. My follow-up is on cash return. You've been very aggressive with buyback recently. The other portion of that's been your dividend. How do you think about dividend growth over the medium and long term? Yeah, 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. We've grown our dividend every year for the last four years. It's a key part of our shareholder return policy and something that we evaluate with our board of directors every year. We think our shareholders really value and appreciate it. It's something that will continue being part of the package of shareholder cash return to the shareholders every year. That's a mainstay, and we'll continue to evaluate for a potential further increase. The next question comes from David Deckelbaum with TD Cowen. Please go ahead. Afternoon, Francisco, Clio, Omar, thanks for taking my questions. Francisco, I wonder if we can go back to just the maintenance capital conversation, appreciating that you all will update that number once permitting becomes a little bit more clear. I'm curious, as you kind of said today, and maybe Clio, you could chime in on the management of the free cash profile. If you had an unconstrained permitting environment, how quickly would you look to move to maintenance in the current commodity environment? Yeah. Hey, David. Thanks for the question. 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 with permit constraints and lower pricing. We feel that we're extremely well set up. 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. Permits, new permits, will give us an ability to also deliver value by drilling our extensive inventory. The way to think about it is a way to enhance what we've already delivered over multiple years. 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. We don't look at maintenance production of production as the objective. We look at growth in cash flow per share as the objective. Yes, we keep in mind the commodity environment. We keep in mind where the stock is trading. We keep in mind the returns on our wells, and that all goes into the mix as we make capital allocation decisions. 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. 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 two rigs, and we can continue that going into next year for 2026. More of the same great returns with some enhancement that will come from drilling inventory. Appreciate the color, Francisco. Maybe just as a follow-up to that, you talked about the permit backlog. I know that the company had pivoted a bit this year to applying for conditional use permits under CalGEM. At this point, what has that experience been like? With a two-rig program, what's the backlog in terms of drilling years at this point? Yeah, we continue, as I mentioned earlier, the conversations right now are trending to a legislative fix on permits. 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 current county EIR litigation and the conditional use permits, right? Regulatory versus legislative fixes. 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. We also have been continuing to work to satisfy the requirements on the conditional use permits. 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. The inventory, in terms of the duration of that inventory, depends on the ultimate outcome of the discussions. There are different ways that we can ultimately get back to drilling more wells. We haven't had any issues with sidetracks and workovers. We continue to permit those and continue to build that inventory beyond 2026. Progress continues and I'm across multiple fronts. 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. Please go ahead. Good morning and congrats on this 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. Hi, Nate. Thanks for the question. I'll turn it to Chris to provide more details on EPA Class VI. Hi, Nate. Yes. You know, 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 6. We 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. Very close cousin, if you will, very sort of conducive to applying those learnings. I remind you that A1/A2 is also part of the Kern County conditional use permit, which was final. We do see the estimate is likely for a draft permit for A1/A2 this year. We see the rest of the permits in the tracker as a good estimate. These are estimates, so things can always change, but it looks reasonable to us. The EPA is committed to expediting permits, putting more resources behind the different EPA regions. We're encouraged by the signal to streamline permits on that front and look forward to the receipt of incremental Class VI permits in the very near term. Got it. Thanks, Francisco and Chris. 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 are seeing on the pipeline front? Yeah, it's another area where we're very encouraged about the progress. There's legislation that's advancing through the California legislature that would support the construction of CO2 pipelines. 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 is signed by the governor by mid-October, the bill will be in effect by January 1, 2026. We haven't seen this much support and momentum in two or three years where we've been working on this. We remain very optimistic that this is an important step towards unlocking the scale of carbon management. We're seeing a lot of good support and dialogue with California leadership around this topic. I understand that there is time for two last questions. We have a question from Michael Furrow from Pickering Energy Partners. Please go ahead. Hi, good morning. Thanks for taking my question. It was positive to see the company step in and repurchase shares from ICAF when they came to market in June. Now, ultimately, the future intentions of these shareholders are unknown, but would you say that CRC is still in a position to kind of step in again and help support these sellers if they come to market? If so, would that require an expansion of the authorization program? Yeah, we absolutely stand ready. We see a tremendous amount of value in our stock. You know, we started the year where the first lockup period came in, and we said we would step in if there was any interest from shareholder exiting. We followed through and ended the block that we announced earlier. We continue to stand ready in terms of making sure the exit of any sponsor is efficient. What we have seen is subsequent to us stepping in, there's ICAF, 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. We believe strongly in the buyback program. We see a lot of catalysts coming that are now recognizing the value of the company. 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. Thank you for the details. Just a quick follow-up on production taxes. They look like they came in pretty low this quarter and helped drive some of the quarterly beat versus our model. The back half of the year production tax guidance kind of looks similar to the one key rate again. 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 the one that we saw. 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. Please go ahead. Yes, good morning. 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? Obviously, you have the carry on the carbon management side, but just curious how you'd weigh recapturing lost volumes, or is that off the table? Yeah, 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. The focus has been on buybacks and cost-cutting exercises and synergies around the Aera merger. In an unconstrained case, now we have the ability to move the top line, and 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 production just for the sake of growing. It's about growing cash flow. 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. I don't want to be prescriptive about rigs or about activity at this stage until we can cross into the unconstrained permitting scenario. 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. 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. Appreciate the detail. A follow-up, you know, on the asset level detail on 5/15. Obviously, your recovery factors, Trump share. Excuse me, Mr. Gruber. I'm sorry, you were breaking up. Would you please state your question? Sorry. Yeah, 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? Yeah, you know, we have truly world-class reservoirs and fantastic rock here. 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 we have a massive running room. You can do the math. Incremental 1% recovery factor adds millions of barrels of reserves. 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. The running room is absolutely an advantage that we're going to be able to showcase. Looking at the slide, 97% working interest, 91% NRIs. I don't think you'll find a lot 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.