Good day, and welcome to the California Resources Corporation Third Quarter 2025 Earnings Conference Call. 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 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. 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 co-location, 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 seven 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. Second, we can help meet demand from existing large technology and data center operators. Based on PG&E's interconnection queue, data center requests 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 four 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's energy comeback, 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 kickstart 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 rebuilt our cash balance, ending October with more than $170 million, excluding the high-yield proceeds reserved for the Berry 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 two-thirds 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 four 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.

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?

Thank you for the question. Yes, the market is becoming very active, and we're experiencing significantly more opportunities now compared to a year ago. As we mentioned earlier, having a major player like Google enter the natural gas sector with carbon capture and storage is a pivotal moment, much like their previous moves into nuclear energy. It's an important market signal. Our vision for Kern County, which is detailed in our presentation, is to develop a hub to support data centers and the electrical grid at a large scale. Our CalCapture project and the surplus power from our facility play a crucial role in this initiative. With our partnerships with Capital Power and Hall Street, we are establishing significant capacity. As these major companies seek low-latency solutions, we have a site ready to serve the Los Angeles market sustainably and at scale. Everything is aligning well, emphasizing not just the construction of data centers or increased energy supply, but also our strong position regarding natural gas availability and carbon emissions management. This integrated project, particularly with excellent partners like Capital Power, highlights the readiness of carbon capture and storage technology. Our site is poised to attract growing energy demands. We're thrilled about the next steps, and many more developments are on the horizon as we continue to discover ways to expand our energy offerings.

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. Our plan is to have four rigs on January 1. So by then, we would have four 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 factors. The key element is owning high-quality conventional assets that our team excels at managing. Now that we have had the Aera assets for over a year, we can see that our team is maximizing their potential, allowing us to adjust our corporate assumptions. Looking at 2025, a significant portion of our activities is centered around the injection at Belridge. With pressure support in these excellent reservoirs, the oil flows efficiently. The Belridge field, which we acquired from Aera, is performing exceptionally well. For Elk Hills, we are leveraging technology and remote surveillance, particularly through an AI system that quickly identifies and repairs failing wells. Any well that is down represents lost cash flow, so our team has seen improvements in surveillance, which helps us manage the declines in our conventional assets more effectively. Belridge and Elk Hills are our two largest fields; improving their reserves and decline rates positively impacts the rest of our portfolio. I want to commend our team's performance; they are doing a fantastic job in managing our asset base. This focus on fundamental practices, like surveillance and injections, ultimately yields significant benefits.

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 strikes 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 look like? And what needs to happen to really catalyze that development?

Yes, Betty. Many elements are aligning well. However, it’s important to note that the California market functions differently from other regions in the U.S. A significant amount of infrastructure is already in place, and natural gas-fired generation has been reduced as renewables have increased. Considering California's growth projections for power, we expect to double in ten years and triple in twenty. This growth won’t be entirely supported by renewables and batteries, so we need to incorporate baseload power on a large scale. We have the capability to retrofit existing plants for carbon capture and storage to ensure they can engage in this expanding market. In Kern County alone, which is close to our operations, we see an opportunity for 2.4 gigawatts of power generation to meet increasing demand. Additionally, our plans for autonomous CO2 pipelines are advancing, allowing us to connect these power plants to our storage sites. The distances involved—ranging from 5 to 20 miles—are manageable for transporting power to our reservoirs. We are scaling up both power generation and emissions management. Collectively, we anticipate around 5.5 million tons of emissions from these plants, with our permit inventory reaching about 9 million tons currently in the permitting process, all centered in the Central Valley. Everything is coming together, especially with the market signals we have identified, including interest from Google. California is seeking decarbonized power and recognizing the need for additional sources. We believe retrofitting existing power plants will be more effective and quicker than constructing new facilities. We are strategically positioned to create a hub since Los Angeles is within 100 miles, which is critical for meeting latency requirements. What we previously viewed as a single site with one pore space has evolved into a scenario with multiple locations, various plants, and third parties seeking solutions that only CRC can offer.

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 this is different than shales. 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 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 steam floods that started steaming back in the '70s, and water floods back in the '80s. 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 barrel wells that you manage well and you work on them to gain another barrel or two? And just given the number of wells, they add up to a shallower decline. So the two things that Francisco mentioned earlier, we have been focused on improving the injection side of EOR, both in steam floods and water floods. 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. 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 reservoir's 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 one 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. One of the things that we talked about, the type of assets that we have, the ownership of the assets, it's also a key advantage that we have. We own 100% of our fields. And so we control the spend depending on the commodity cycle. So it allows us to be very efficient. As you make these assets better, as we've talked about, then your capital deployment becomes one of the highlights. 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 that we can opportunistically buy back shares. So I think the combination of the two with a foundation of a very, very strong hedge book, we have 64% of our oil hedged 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. The reactivation needs to be measured, thoughtful, disciplined 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; we need more California production. We need more Kern County production in particular. 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 is 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?

Yes, we’re clearly below $500 million. Based on our preliminary guidance for 2026, that’s a figure you can use for reference. These figures do not account for the Berry assets. Once we close the Berry merger, we will update that number to include their assets and will provide a complete corporate figure to maintain the capital needed to keep production stable. However, for CRC and Aera on a stand-alone basis, considering the improvements we highlighted during the earnings call, we are indeed now below $500 million. We've observed that Berry has been able to maintain their total production capital, which is around $70 million; however, we need to finalize the transaction and refresh the market. Nevertheless, the baseline assumption is showing improvement.

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 by the 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 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 a 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?

Our current focus is on feedstock, which includes natural gas with low methane emissions and third-party certified gas. We believe this will be very appealing, and we are the largest natural gas producer. Additionally, we are working on providing a carbon capture and storage solution. I do not foresee expanding our ownership of natural gas combined cycle plants beyond what we currently have. We are exploring other avenues to advance power generation, such as fuel cells and geothermal energy, especially since there is significant potential for geothermal in California and a strong demand for fuel cells integrated with carbon capture solutions. Our goal is to find the right balance between providing decarbonized and baseload power to meet the growing market needs. We are committed to being a leader in carbon capture and the feedstock provider for natural gas, which aligns with our strengths. As we introduce more technologies and connect with more hyperscalers, we can refine our vision for the Kern County power platform we mentioned 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, definitely. As you examine Slide 7, you will notice that we have effectively highlighted the footprint, which includes both the fields and current pipelines. These rights of way are owned by either CRC or other exploration and production companies, and the fields are situated next to ours, making the power plants also nearby. This creates an excellent opportunity to decarbonize the entire microgrid. As we've mentioned, we possess a significant amount of land and have partnerships with others who also own land in the area. With the lifting of the moratorium on pipelines, which was the key factor we were waiting for, we are now able to connect all these assets. We are currently collaborating with Capital Power and others to explore this further.

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 facing a permitting constraint since early 2023. The recent improvements in our regulatory framework represent a significant milestone for the company. We have managed to effectively carry out capital workovers and sidetracks during this time, but we were unable to pursue new wellbores due to the lack of permits. Now, with SB 237, we have a new law that not only permits operations in Kern County but also provides a 10-year duration linked to the Kern County EIR. It's been a long time since we've had such strong support and a lengthy runway. As we've highlighted in our slides, the state aims to increase local production to about 25% of its overall supply. Our production has decreased over the years; we used to contribute 40% to 50% of the local supply from local exploration and production companies, but this has fallen to around 22%. The government's call is for more California low CI production. This signifies significant changes and improvements in the local production outlook, and as the leading producer in the state, we are committed to doing our part to help stabilize the fuel markets and increase production.

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. If we look at our 2026 plan with the four rigs, we're going to focus on primarily oil. About 80% of the anticipated contribution from '26 activities is oily. This 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. 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're sitting on these great basins. And depending on where you are in the state, you could have heavy oil in the shallow reservoirs and then deep gas a few thousand feet below that. So, you have a lot of stacked pay and a lot of flexibility in how you can run the assets and allocate capital. We're looking for where the best returns are. Right now, we're seeing them in oil. But 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.

Our next question comes from Leo Mariani with ROTH.

I wanted to ask about the capital plan for 2026. You're discussing running four rigs continuously for approximately $280 million to $300 million for drilling and completion, plus workover capital. If I compare this to your E&P spending in 2025, which was between $245 million and $275 million for about 1.5 rigs, the proportions seem a bit inconsistent. Can you clarify the numbers for me?

Yes, I think there might be some confusion between total capital and drilling and completion costs. The drilling and completion costs for 2025 are lower. We have two rigs, but we didn't start the year with two rigs; we added them later. Our facility spending is different as well, particularly the spending we discussed this quarter, which involves advancing the NGL project from Aera. We're constructing a pipeline from Aera to Elk Hills to transport rich wet gas to Elk Hills, where it will go through our cryogenic plant to extract a thousand barrels of natural gas liquids. This project is advantageous because it aligns with the existing natural gas infrastructure. It’s just a more efficient method to derive additional value from the project. However, the drilling and completion figures are indeed lower for 2025. What’s the exact 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. 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, in 2026, most of the activity will be focused on workovers and sidetracks. Approximately 60% to 70% of drilling and completion will fall into that category. The remaining portion will involve new wells as new permits begin to be approved.

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.