Good day, and welcome to the California Resources Corporation First Quarter 2025 Conference Call. All participants will be in listen-only mode. After today’s presentation, there will be an opportunity to ask questions. 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 First Quarter 2025 Conference Call. Following our 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 some forward-looking statements based on our current expectations. Actual results may differ due to factors described in our earnings release and in our periodic SEC filings. As a reminder, please limit your questions today to one primary and one follow-up as this allows us to get more of your questions today. And now I will turn the call over to Francisco.

Good morning, everyone. Thanks for joining our call and for your interest in our company. CRC is executing very well. We delivered a solid quarter and are reaffirming our full year 2025 outlook. Our business strategy is designed to mitigate commodity price volatility and generate cash flow to execute our operations, maintain a strong balance sheet and sustainably return cash to shareholders. Before Clio covers our first quarter financial and operating highlights, let me open with some thoughts on how CRC is positioned to withstand the uncertainty in today's macroeconomic environment. First, the strategic steps we have taken to strengthen our business were timely. We have achieved critical scale. The Aera merger made us bigger and better, proving that assets are better in our hands. This combination provided new opportunities to streamline our business and achieve meaningful cost savings that strengthen our returns today and well into the future. We have now realized more than 70% of our total $235 million in announced annual synergies and expect to achieve the full target in early 2026. Second, our cash flow is underpinned by a strong hedge portfolio and diversified revenue stream. For the remainder of the year, we have approximately 70% of our oil production and 70% of our natural gas consumption hedged at attractive levels relative to the current strip. In addition, our power and natural gas marketing strategy are delivering meaningful margins, further underscoring the strength of our business. This integrated strategy provides strong visibility into near-term cash generation, supports debt service and shareholder returns and allows us to generate free cash flow at Brent prices down to approximately $34 per barrel. Third, we have high-quality conventional assets. They have low decline rates, high net revenue interest and high ultimate recovery rates. With modest development cost, we can manage our production largely through capital-efficient workovers and sidetracks. Low capital intensity provides an advantage over peers. We're also able to control the pace of activity due to our high ownership interest where we own both surface and mineral rights. We have a solid inventory of development projects, and recent improvements in the state's oil and gas regulatory environment provide confidence that we will continue to build our permit inventory through several avenues later this year. We are returns focused and allocate capital to our highest return projects while effectively managing production and investing in our growth opportunities. Lastly, the strength of our business allows us to sustainably return meaningful cash to our shareholders. In the first quarter, we returned a record $258 million to stakeholders through dividends, share buybacks and debt redemption. We continue to show that CRC is a different kind of energy company. I'll turn it over to Clio to summarize our first quarter results and some of the drivers behind our strong outlook.

Thank you, Francisco. Good morning, everyone, and thank you for joining us. This quarter, our results exceeded the expectations. We delivered flat net production quarter-over-quarter at 141,000 BOE per day and realized prices that were 98% of Brent. Adjusted EBITDAX was $328 million, net cash flow before changes in working capital was $252 million and free cash flow totaled $131 million, all of which came in above consensus. This performance was primarily driven by our continued cost discipline. In Q1, our combined operating and G&A costs were $388 million, approximately 5% better than what we had guided. Looking ahead, we expect to reduce our operating costs in the first half of 2025 by nearly 10% compared to the second half of 2024. We remain focused on delivering value to shareholders. This quarter, we repurchased a record $100 million in shares, nearly double our historical average, and paid $35 million in dividends. Altogether, that's $135 million returned or about 103% of our Q1 free cash flow. With a strong start to the year and despite nearly a 16% decline in oil prices, we are reaffirming our full year adjusted EBITDAX guidance of $1.1 billion to $1.2 billion, driven mostly by our low-decline assets, focus on cost reduction and hedge book. We continue to target average annual production of 136,000 BOE per day with D&C capital investment between $165 million and $180 million. Now I want to take a moment to talk about our financial resilience and highlight three core strengths. First, balance sheet strength. We have a strong financial foundation. Our leverage is below 1x. We have more than $1 billion in liquidity and nearly $200 million in available cash. Earlier this year, we redeemed $123 million of our outstanding 2026 notes at par, and we expect to address the remainder later this year. This balance sheet strength gives us the flexibility to reduce debt, return capital and invest in disciplined opportunities. We also have access to third-party capital from Brookfield to support the growth of our carbon management business. Second, our cost reduction progress. As Francisco mentioned, we realized $173 million in annual run rate Aera-related synergies based on our Q1 results. We expect those to be sustainable and enhance our future margins. Third, executing on our strategy. Our integrated approach is gaining traction. We're capturing value through resource adequacy payments for standby power capacity, natural gas marketing, commodity derivatives and emerging opportunities in carbon management. We're executing on our broader vision. Our gas to power and carbon capture strategies are not only actionable, but they're also scalable and position us to deliver long-term value while reducing risk. We are pleased with how we started 2025 and confident in our ability to execute for the rest of the year. We're executing today and building for tomorrow. Thank you. Back to you, Francisco.

Thank you, Clio. Before we move to Q&A, let me quickly summarize today's call and offer a few things to watch for as the year unfolds. Through our carbon management business, we continue to build scale and expect new vaults and projects to be announced later this year. Industrial partners are turning to us for solutions to energy challenges and desire for clean, reliable power. We have a leading CO2 storage reservoir business in various stages of permitting with multiple CCS projects under consideration. We're also excited to launch California's first CCS project at the Elk Hills cryogenic gas plant with construction breaking ground in the second quarter and with first injection expected later this year. In our power business, we're pursuing multiple new opportunities with AI data center companies and other large offtakers interested in our available power capacity. Our firm supply of gas, speed to market, access to land, proximity to CCS and scalable infrastructure are key attributes in our portfolio. The proximity of our assets to large industrial centers in the world's four largest economies creates multiple advantages as we progress these discussions. Stay tuned for more later this year. CRC is executing, and we sit in an advantaged position. With a strong balance sheet, quality assets, a low and declining cost structure and well-priced hedges, our margins are well insulated from near- and medium-term reductions in commodity prices. We certainly recognize the challenges presented in today's markets, but CRC has a plan. In closing, let me reiterate my opening comment. CRC is well-positioned. Our durable assets and integrated business strategy are yielding strong results today. Operator, we're now ready for questions.

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

A nice quarter. I was wondering if you all could walk through how you're able to achieve the similar EBITDA using a much lower Brent assumption. I mean, obviously, you pointed to some things like lower costs being one thing. But is there things incrementally happening from the prior outlook that has been a tailwind? And can you give us some specifics on what really is driving some of those OpEx costs down?

Yes, definitely, we're seeing a lot of tailwinds related to our synergy targets. The team has just been outperforming every expectation in terms of getting the Aera assets integrated into CRC. So think about it as 3 stages. The first stage was around refinancing and the people aspect of a merger. The second one was around leaning in on our supply chain advantage and renegotiating good contracts to have long-term runway. What we're doing right now is we're consolidating infrastructure, and that's where we're seeing tailwinds. We're moving cost savings earlier. And that in combination with our very strong hedge book is what positions the company to be able to not only reaffirm guidance, but continue to invest in this business. So excited with the progress and the results from the merger and we expect to continue getting every dollar from our target in the synergy bucket.

The next question comes from Josh Silverstein with RBC Capital Markets.

I had a question on the breakeven that you guys were highlighting. Obviously, they're very low. And Francisco, you just mentioned the hedge book. Can you give us a sense as to what it may look like on an unhedged basis? Is it closer to those other kind of workover and sidetrack costs that you guys were alluding to earlier in that slide as well?

Let me take a moment to explain how we arrived at this point. For four years, we have been preparing the company to manage the fluctuations in the market. Volatility is an inherent aspect of commodity prices in this industry, so we needed to create a resilient business that can consistently return capital to shareholders. Our future is fundamentally based on the quality of our assets, which have a low decline rate and are predictable. The measures we've implemented have been designed to prepare for scenarios with heightened volatility, like the current situation. We've engaged in mergers and acquisitions, established hedges, maintained a strong balance sheet, and proactively worked on reducing costs. Consequently, our corporate breakeven is approximately $34 per barrel for Brent and around $30 for WTI. This is how we operate, and all these steps were taken to prepare for this moment. Moving forward, you can expect this proactive approach rather than a reactive one, ensuring we can provide certainty to our investors and continue to return cash to shareholders consistently.

Got it. And then a follow-up question for me. I think I asked this a couple of quarters ago. But we've seen another refinery shutdown in California. Is there a growing concern about who you guys are able to sell to or the Brent premium that you guys receive?

Yes. We are not worried about the refinery shutdowns. We can still sell our crude to the existing refineries. As a reminder, these refineries are designed for California crude, which has low sulfur content. This is why our realizations are very high, comparable to Brent prices, due to the better market demand for our crude. California faces challenges as the fourth largest economy in the world and a major consumer of gasoline, second only to Texas, as well as the largest consumer of jet fuels in the U.S. The state is struggling with reduced refining capacity. However, when we communicate with the government and refineries, we emphasize that there are solutions. We can enhance cost structures by increasing local production. I believe this message has been understood, and we are observing progress in various areas. While the refining situation can improve, we will assist by producing more of our barrels, which is what the refineries actually need.

And we have Scott Hanold from RBC Capital Markets.

For my follow-up from my earlier start, Francisco, I was wondering if you could give us a sense of what you're seeing and hearing on the political landscape, both in California and Washington. I know you stay pretty active and close to that. And what kind of progress is occurring on things like CO2 pipeline regulation, carbon tax credits, oil and gas permitting specifically in the state. What kind of progress are you seeing at this point? And is it encouraging? Are you seeing some movement by some of the politicians to be more open to, I guess, oil companies in the state?

Yes, I appreciate that question. It's very encouraging to see how this is unfolding. We are focused on two main goals: reducing emissions in line with California's objectives and taking advantage of California's substantial oil and gas reserves. This allows us to cut emissions while improving energy affordability and enhancing energy security. As we engage with stakeholders in Sacramento and Washington, D.C., there is significant alignment, and our projects serve as a connection between the two perspectives. It’s a win-win situation, and we are seeing progress with CO2 pipelines, cap-and-trade, and oil and gas permitting. Overall, we are observing much more constructive engagement and tangible progress, which enables us to invest in both new energy initiatives and the legacy industry. Therefore, we have a positive outlook on our engagement in both Sacramento and Washington, D.C.

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

For my first question, I'm looking at Slide #16 here, which covers Huntington Beach. It looks like you've got visibility on the necessary permit for land use at the city level. Wondering if that opens up an opportunity to start marketing the real estate to potential buyers. And if you could give us an update on the timeline, that will be great.

Yes, Kale. We have submitted the proposal with the city of Huntington Beach and are currently undergoing community reviews. To clarify regarding marketing, the asset is for sale, and we would consider selling it for the right price at this moment. Our main focus is to ensure we achieve the best value, which we believe can be accomplished by abandoning the field, allowing us to control the pace. We are working towards getting the land re-entitled for optimal use, and we have conducted considerable preliminary development work. The plan is for a mixed-use community featuring 800 homes and over 350 hotel rooms, addressing the pressing need for housing in California and Los Angeles. We are moving forward with these plans and have been consistently working on a rig abandonment program since 2023, making progress in that area. Our goal is to determine the right time to monetize the property effectively. There has been significant media coverage regarding this asset, and we anticipate a timeline of about three years to secure all necessary approvals, which includes navigating CEQA and environmental impact reviews. We are also exploring if any processes can be expedited while preparing the asset for incremental value for shareholders.

This is not my second question, but just a really quick follow-up on this. Can you share any color on how many interested bidders there are?

In response to your first question, Kale, we do not have a formal bidding process in place. We have simply invited interested developers to engage with us. These are substantial projects, as demonstrated by our recent sale of a smaller property adjacent to Huntington Beach for approximately $10 million per acre. It requires a developer with a strong vision for the future. We anticipate a decrease in interest rates, which will benefit project development. Instead of focusing on the number of bidders, it's important to view this as a unique property with significant interest, and we are progressing towards achieving the best possible value for it.

Got it. This is my follow-up question. I want to ask on the Elk Hills PPA. The way that we understand it is that the PPA could create demand for clean energy that you could supply from Elk Hills with carbon capture. Carbon capture is a more expensive project than the cryo that you're breaking ground on this quarter. So wondering if you could offer any latest thoughts on funding.

Yes. When considering CalCapture, we view the final investment decision as closely linked to a Power Purchase Agreement (PPA). We have various clean energy incentives, including 45Q, LCFS, and the avoidance of a carbon tax in California, all contributing to our revenue stream. Ultimately, our goal is to establish a new business model centered around baseload 24/7 natural gas-fired energy with carbon capture. We are focused on finding the right partner and PPA for this initiative, advancing all fronts. While we are heavily engaged in engineering to optimize costs for CalCapture, we are also exploring funding options. This involves contemplating whether the power plant will function as a merchant power plant, which it currently does, whether it will participate in resource adequacy, which it also currently does, or whether we will sell the power to a third party, which values clean baseload electrons. We are receiving significant interest in the power and believe that hyperscalers are re-engaging, alongside other potential offtakers. Now, I'd like to turn it over to Clio, who joined us at the start of the year. In her previous role, she worked on the other side of PPAs with technology companies, so she might want to share her insights.

Yes. So Kelly, as Francisco mentioned, prior to joining CRC, I was working on a number of things, but one that was keeping me very busy was brokering and structuring deals between the data center developers, so that's your hyperscalers, that your co-locators, and power asset owners. And that's where really I recognized the significant potential of CRC's power business and how that fit a clear market need and fit that very well. So one of the most exciting opportunities I saw was related to the Elk Hills power plant and what is the behind-the-meter partnership model and opportunity that we have been progressing. Now I've got a more in-depth view of our operations of our assets and the market. And so I'm even more confident in the strength of our value proposition to data centers and to large offtakers. Our offering really is not only differentiated, but it's resonating strongly in ongoing discussions, and those are advancing constructively.

So just to kind of close out the question. Getting the right long-term partner, we won a 10-year-plus PPA with the right partner that not only recognizes how valuable this opportunity is. The hyperscalers want speed to market. We can deliver that. We have capacity today. We have land. So we won the right PPA structure in the right way. But we also are looking to solve for the northern CTV reservoirs, where we see a lot of demand, potential natural gas power generation. Big emitters need a solution. And if we can unlock this at Elk Hills, it should ultimately also scale to our northern reservoirs and create a further business opportunity there. So a lot of things to solve for, but we are making progress. We're getting the land ready. We're getting our permits in good shape so that when we finalize the details of a contract with a third-party, it will be something that really can unlock value for us.

The next question comes from David Deckelbaum with TD Cowen.

I was just curious, just going back to the synergies. You've effectively almost achieved your '25 target. And I want to say that you all had left, call it, around $60 million of additional synergies in '26 as perhaps upside. Is there any reason why that should remain in '26 versus being pulled forward? Or is it the timing of certain projects that you're looking at? Or it seems like since you're already ahead of the game here, we might be able to see some of those elements perhaps showing up a bit earlier.

Yes, I appreciate the question. It highlights our team's capability to meet targets ahead of schedule, and we continue to achieve that. As we set out additional targets and synergies, our team has identified several promising projects. These projects have already been initiated, and the real impact will come when we start seeing results. Now, I'll hand it over to Omar to discuss the timing aspect and share insights about some exciting projects we are working on that will be ready later this year and will be fully operational by early next year. Omar, would you like to elaborate on that?

Yes, if you look at the rest of the 2025, David, and how we are thinking about synergies, we are really focused on delivering operational efficiencies tied to infrastructure consolidation. So we have excess capacity in our major fields around gas processing, produced fluid treatment and, in some cases, power. And what we are working on is bringing production from our various fields in the basin to these central facilities to fill in the excess capacity. And it does 2 things for us. It eliminates the need to maintain and operate multiple facilities once you consolidate them and it also helps us monetize our produced oil, gas and natural gas liquids. And I'll give you a couple of more concrete examples around the second point. So we acquired Ventura Avenue field as part of the Aera acquisition, a field that had associated gas, but doesn't have the facilities to fractionate natural gas liquids from that gas. So we were actually paying a third-party to take that production off our hand. What we are doing now is we are bringing that natural gas liquid production to Elk Hills, where we have capacity in our cryogenic gas plant and monetizing that production stream. Similarly, Belridge, which is a major field we acquired as part of the Aera acquisition, also has associated gas but do not have gas processing, and we have excess capacity in our cryogenic gas plant. So we are working on a project to connect that gas to CGP, the cryogenic gas plant, drop liquids and monetize the revenue around that. So some of these projects on that time scale need some initial capital investment, and we are progressing them forward. They will all be completed by the end of third quarter or end of '25, but some of the revenue stream we'll see in first quarter '26 and onwards. So hopefully, that was helpful.

So we're making the investment now. We see the benefit of incremental NGLs in 2026. And so we're going to count the synergies when they come in '26.

I appreciate the insights, Omar and Francisco. As a follow-up, I’d like to dive a bit deeper. In the first quarter, you hit your numbers and significantly reduced CapEx, saving around $10 million compared to your initial plan. You've reiterated your full-year guidance, so I'm curious if this is simply a result of the mix of activities in the first quarter, or if there are aspects of your capital program that are ahead of schedule this year?

It is a mix. And we see there's efficiencies in the numbers, but we also planned the year where we expected a light capital first quarter, increase in the second quarter. And then we're also increasing potentially the activity as the second half of the year comes in with a second rig. So there will be a ramp-up in activity that ultimately leads to a higher D&C capital as the year progresses. But we are seeing efficiencies and savings through the supply chain discussions around capital as well. So it's a little bit of a mix. The story as a whole is very good.

The next question comes from Nate Pendleton with Texas Capital.

Congrats on another strong quarter. Taking a step back and looking at the value you can add with Aera and the ability to decarbonize production streams, can you talk about your willingness to pursue bolt-ons in California should assets become available in this market?

Yes, Nate. So we're very focused on executing our business right now. As you saw, I think it was really important for us to get the transformational deal completed with Aera. As you can see by a lot of our messaging, the key is to have the infrastructure in place, the consolidation to be able to really extract value from any acquisitions. Acquisitions are an important part of our strategy going forward. We do feel that assets in California are going to be better in our hands from every standpoint. So in terms of bolt-ons, when we see something that really makes sense and can be accretive and, I would say, significantly accretive to cash flow per share, this is something that we would consider. But we have a strong inventory. We have a lot of uses for capital in our portfolio. So it's a really high bar to think about bolt-ons, but it is part of the strategy as we finalize and think about all the achievements we've done with Aera and then what do we do next.

Got it. And then I wanted to shift over to the CCS space. Understanding that your business is primarily focused downstream of the capture for third-party volumes, can you provide any update on recent carbon capture technology advancements and how maybe that's impacting discussions with emitters for CO2 offtake?

Yes, Nate. From the beginning, we have taken an agnostic approach to technologies, recognizing the significant amount of investment and progress being made. While others concentrate on technology development, our advantage lies in our ownership of land and minerals. The pore space is where we find value in California's carbon capture and storage. That's where we direct our efforts. As we navigate the permitting process and engage emitters both in Elk Hills and Belridge, as well as outside, we gain a clearer understanding of how various technologies are evolving. We aim to see a reduction in costs and improvements in efficiency, but we believe this is best achieved with the support of third-party capital. Our partners, like Brookfield, are working on their own technologies, and we will provide them with an environment to compete for the best solutions. We also have the capability to tailor technology solutions to different sources. As we progress in post-combustion capture, we will discuss the potential of these technologies. There isn't an abundance of innovation in this area; it primarily involves straightforward aiming units. It really comes down to cost and determining who can offer a competitive price for capture in the future.

The next question comes from Betty Jiang with Barclays.

I want to ask about the base decline and the maintenance capital. What stuck out this quarter is that if I look at your 1Q production versus 3Q last year, your oil volumes are only down 2%. And then over that period, your capital was just around $200 million. And I know there's timing of the spend, but could we just get an update on where you think maintenance capital is going forward? And then what I'm really trying to get to is in an unconstrained permitting environment, once you take into account all these cost savings and synergies, how much lower could maintenance CapEx go versus what we thought before?

It truly emphasizes how we stand out from others in the sector. While most companies focus on drilling techniques and the effectiveness of their fracking, that's not our approach. We concentrate on base decline mitigation and surveillance, which involves operational expenditures. Then we efficiently allocate capital for workovers and sidetracks as part of our normal operations. The question arises about what we would do in an unconstrained permitting situation. At this point, we aren't prepared to provide guidance on that scenario, despite seeing positive signs regarding permits. As we have expanded and gained new assets, our team has consistently delivered strong oil production with minimal quarter-over-quarter decline and very little capital investment. This indicates that our strategies in surveillance, workovers, and sidetracks are highly effective. Looking ahead, we will assess the inventory based on well permits and the mix of wells to establish future guidance. Previously, we mentioned that maintaining flat production would require around 6 to 8 rigs. However, we will keep evaluating this based on the team's performance. I would prefer to revisit this topic when we are prepared, with a complete set of permits and a longer timeline to deploy more capital effectively.

The next question comes from Leo P. Mariani with ROTH.

I wanted to follow up a little bit here on the production. So looking at the second quarter guidance, it looks like production is going to be down versus 1Q slightly over 4% using kind of the midpoint of your guidance. Obviously, that decline would be in excess of the annual decline that you guys have kind of spoken about. And clearly, not nearly as good as the performance that you've been achieving the last couple of quarters, which is shallower declines for less capital. So just wanted to see if there's anything specific about the second quarter or maybe there's some maintenance or shut-ins or whatnot. I did see that in your slides, you talked about 10 million a day of production, which sounds like that's going to be going offline to kind of replace some field use gas. So just any more color on that would be helpful.

It's important to clarify that while production on a BOE basis is decreasing, cash flow is actually increasing at lower prices. The key to this is our power plant, which utilizes a combined cycle gas power generation system that is very flexible. Typically, we operate it in a 2 by 1 configuration, meaning two gas turbines for every steam turbine, during periods of full capacity. However, during certain times of the year in California, when there is significant solar energy available, we can shift to a one-by-one mode at our discretion. This adjustment reduces natural gas production, but the gas remains valuable. Instead of counting it as production, we've historically injected it back into the reservoir when it’s not feasible to produce it. Now, following the Aera merger, we can redirect that gas to Belridge, which is adjacent to our other fields. Sending the gas to Belridge provides two benefits: it reduces our operational expenses since we are purchasing less gas from third parties and it also lowers our costs at the power plant by operating in a one-by-one configuration. So while you may notice a reduction in net production of about 10 million a day of gas, we are simultaneously seeing increased cash flows by lowering costs. Our goal is to maximize value and cash flow rather than merely production, making it an easy decision to utilize our redundant system by directing the gas where it can be used most effectively.

Okay. I appreciate that thorough answer. Now just jumping over to kind of oil and gas permitting side. You certainly talked about how things are improving of late. But can you get a little bit more specific in terms of where the EIR in kind of Kern County sort of stands today? My understanding was I think maybe the public comment period is maybe recently kind of wrapped up. And just can you give any kind of color on where we stand and what you think the time line is for a judge to be taking a harder look at that in the near term?

On permitting, it's really been a tremendous highlight. We're very encouraged by the progress being made on the permitting front. The focus has been on the EIR. But as we talked about before, we have multiple alternatives in motion, which we think all of them will work into the future. So we're very optimistic, first of all, because we have what we need in terms of sidetracks and workovers. We've reached, what I would say, is a regular way process and have all the permits that we need for 2025. We're building inventory into 2026 for our drilling program. Specifically, as it relates to the Kern County EIR, litigation process continues, but the county is expected to adopt a revised EIR later in the year to address the deficiencies identified by the court. So we expect some resolution and progress towards the second half of the year. But at the same time, we're doing what's called a conditional use permit, which is an alternative route with a different agency, where we have about 90% of our proved and developed reserves in 4 fields, and we're developing a field-specific permitting process around those. So I would say, if you look at it as a whole, if you step back from the specifics on EIR and kind of what's out in the public domain, if you step back, we have a very constructive dialogue with multiple agencies. There's a need for more local production. I think there's a much better understanding than in the past that the solution to affordability and cutting emissions is local production, and we want that to be a CRC barrel. So this year, we decided even if we get a lot more progress on permits to continue with a 2 rig program. But what we're doing is we're really building that inventory of high-quality projects and gaining more and more confidence. We'll be ready to go.

The next question comes from Phillips Johnston with Capital One.

Just wanted to clarify the wording in the press release regarding the potential PPA. It read that you guys are engaged in discussions with multiple large-scale industrial customers for the PPA. Francisco, it sounds like from your comments on the call here, that doesn't imply that you're no longer negotiating with other types of potential counterparties. Am I hearing that right?

Philips, thanks for clarifying. We are focused on data centers as the offtaker for Elk Hills power, specifically the 200 megawatts plus. The discussion about additional industrial players relates to new entrants seeking clean baseload power. California is currently facing a shortfall in baseload power, and we've observed globally the consequences of being overly reliant on renewables. Similar trends are evident here. The interest in one of the most efficient plants in California, which can be converted with carbon capture to a low carbon or even no emission facility, is an appealing opportunity that extends beyond data centers. The message is not about a shift in focus but rather an expansion of interest beyond data centers. However, we remain heavily engaged with data centers, including both hyperscalers and co-locators.

Okay. That sounds great. Clio, you noted the share buyback was really strong in the first quarter. It was basically 2x the pace as what you bought back in the prior 2 quarters. Can you maybe talk about what you're thinking about in terms of the pace of buybacks going forward?

I'm happy to provide more context regarding our decision in Q1, which will help clarify how we prioritize our buybacks in relation to other capital opportunities. We see considerable value in our equity and are dedicated to retaining and increasing shareholder returns. In Q1, we recognized a distinct value dislocation in our stock and were positioned to act decisively. By the end of 2024, we had rebuilt our cash balance to over $350 million just six months after completing the Aera merger. In February, we took steps to reduce our debt by redeeming $123 million of our '26 notes, highlighting our commitment to maintaining a strong balance sheet and disciplined capital management. At that time, share repurchases were the most attractive use of our excess cash to enhance long-term shareholder value. Since the Aera merger closed in July last year, we've repurchased 20% of the shares that were issued at that time, achieving this at an average discount of about 9% compared to the issuance price. This further strengthens what was already a highly beneficial deal and demonstrates our disciplined, value-focused capital allocation approach. Looking ahead, we will remain opportunistic in our strategy, continuously evaluating our buybacks alongside other capital priorities, but you can expect us to concentrate on maximizing returns and delivering value to our shareholders.

The next question comes from Nitin Kumar with Mizuho.

I want to ask about the cost savings; however, the electricity margin guidance for the year has increased significantly. I would like to understand whether this is due to better pricing, lower costs, or a combination of both.

As I mentioned earlier regarding our management of the power plant, the key to understanding the margins lies in the fluctuations of merchant power prices. We are addressing this by transitioning from a 2 by 1 to a 1 by 1 operation. The resource adequacy, referred to as the capacity program in California, is fixed and contracted, amounting to $150 million for 2025. Therefore, when we observe an increase in the margins, it indicates that our efforts to shift to a 1 by 1 operation are contributing to that enhancement. It's a combination of effectively managing the merchant aspect and the additional value we are obtaining from the contracted component of Aera.

The next question comes from Noel Parks with Tuohy Brothers Investment.

I have a couple of questions. You mentioned earlier that we should expect to see some new programs for Carbon TerraVault announced later this year. Can you describe the agreements or the process involved in getting there? Additionally, could you give us an idea of what the final stages look like in securing some of these deals?

The current focus for Carbon TerraVault is to execute our first project, which we will begin in a few weeks. It is crucial to get this project started, as we aim to have CO2 injected by the end of this year, marking the first cash flow for carbon capture and storage in California. Our team has also been making progress with the EPA regarding incremental permits. We expect to receive 6 or 7 permits that have been pending for a couple of years, which should soon be close to final issuance, at least in draft form. This will increase the permitted pore space and significantly expand our capacity in the state. We’ve noticed that as we advance toward receiving the first permit of its kind in California, interest from emitters grows. Right now, our primary focus is on the Elk Hills project, but we anticipate expanding to our northern reservoirs near the Bay Area, where there are numerous potential customers from both existing and new power sources. Additionally, there are industrial customers seeking solutions for their emissions in our fields. In California, there is not only the existing incentive structure but also a rising carbon tax, which provides a financial incentive for companies to consider CO2 storage. We aim to be prepared for this market opportunity. We expect to see announcements and progress regarding permits and emitters soon. We have concentrated efforts in the Central Valley, but our focus will move north as we expand.

Is it accurate to say that the concept of carbon capture and sequestration is still relatively new in the state and generally at scale, leading to a sort of standoff? There is awareness of its significance and benefits, and interest exists, but there seems to be a lack of urgency among customers to commit. It appears that the understanding that available pore space is finite isn't enough to prompt customers to be more proactive in utilizing the capacity we have.

Yes. To reframe the question a bit, I don't necessarily agree with the perspective you presented about potential delays. This is a new business and a new opportunity, and we are making significant progress. When you compare Carbon TerraVault's advancements to others nationally, we're performing very well in terms of speed. There are many elements to address. We have a robust pipeline of emitters and are also working on physical pipelines. Our focus has been to unlock that aspect. Historically, there hasn't been a need to transport CO2 in California, but now that there is a market demand and government initiatives, we need to get those pipelines permitted, which takes time. This is true in California and essentially any state. However, we are optimistic about the progress on CO2 pipelines. In California, both the Senate and Assembly are proposing legislation that will establish the framework for utilizing retrofitted CO2 pipelines. This is a significant catalyst for the CTV business. We believe the momentum is building, and the current moratorium should be lifted later this year. There is considerable support and interest from both the market and regulators for enabling CO2 flow soon. Once we achieve that, we will be better positioned to discuss emitters and our business model, but we first need the physical connectivity afforded by approved CO2 pipelines.

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

Great. Thank you so much. We're looking forward to seeing you. We're going to do several conferences throughout the summer. But thanks again for listening, and have a good day. Thanks.

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