Good day. And welcome to the California Resources Corporation Third Quarter 2024 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 third quarter conference call. Following our brief 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 discussed to the most directly comparable GAAP financial measures on our website, as well as in our earnings release. Today, we will be making some forward-looking statements based on 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 to one primary and one follow-up as this allows us to get more of you on today. I will now turn the call over to Francisco.

Thanks, Joanna. Good day, everyone. By all accounts, this has been a very strong year for CRC with excellent progress on several fronts. We are bigger and financially stronger following our combination with Aera Energy. We have successfully integrated Aera’s talented workforce into CRC to form California’s largest producer with a portfolio of high quality, low decline and low capital intensity conventional fields. Our statewide portfolio of assets and long-duration development inventory allows for flexible capital allocation opportunities through workovers and sidetracks to offset natural declines in our reservoirs. We have executed on our business strategy, demonstrating an ability to acquire assets and rapidly capture synergies to enhance returns and grow cash flows. In regards to Aera, we are ahead of schedule as we have already implemented more than 55% of the $235 million in annual synergies. Our track record of growing cash flow per share is a core competency in a rapidly consolidating industry. We are an innovative energy solutions provider, helping California decarbonize essential and hard-to-evade industries while attracting new partners and green capital to the state. And we offer a very compelling investment proposition for existing and prospective shareholders. Our equity is underpinned by the PPA value of our conventional assets and our carbon business is gaining momentum with multiple projects in various stages of development. In addition, the combination of our natural gas production with power generation has us well positioned to monetize excess power capacity to meet this rapidly accelerating electricity demand in California. CRC has a very bright future.

Thank you, Francisco. Our operating results exceeded expectations, driven by strong production, improved operational efficiencies, and lower cost when compared to last quarter. Reservoir performance remained resilient due to the workover program, which effectively manages our production decline. Third quarter production averaged 145,000 barrels of oil equivalent per day and oil averaged 113,000 barrels per day. Oil sold at 96% of Brent after hedges. We generated $402 million in adjusted EBITDAX and $141 million in free cash flow. Results benefited from cash costs that came in approximately $0.04 below our guidance. In just one quarter, and despite weaker commodity prices and merger-related payments, we rebuilt our cash balance to more than $200 million and rewarded owners with peer-leading shareholder returns. Our liquidity remains robust at $1.15 billion, and we are committed to reducing debt to our leveraged target level in 2025 while continuing our dividend and share repurchase programs. We continue to maintain capital discipline and delivered strong quarterly results on lower-than-expected capital of $79 million. This decrease is mainly related to lower-than-expected capital deployment after high-grading our workover projects. We have a track record of returning meaningful cash to shareholders, with approximately $965 million returned to shareholders since 2021. In the third quarter, we returned $76 million to shareholders or more than half of the quarter’s free cash flow. This was comprised of $34 million in dividends and $42 million in share repurchases. If you have questions on our quarterly financial results, Francisco and I will be happy to answer them at the end of our remarks. Francisco, back to you.

Thanks, Nelly. Now let’s talk about our growing carbon management business. We continue to experience significant interest from various stakeholders as we make progress in helping solve the dual challenge of quickly reducing California’s industrial emissions while delivering reliable and affordable energy. We all share a common goal to safely and rapidly decarbonize California. In our carbon tariff vote release, we provided some exciting new information, including three major updates. First, Kern County unanimously approved our conditional use permits for CTV I at Elk Hills. For the EPA tracker, we expect to receive our final EPA Class VI permits for CTV 1 26R reservoir next month. Shortly after receipt of the EPA permit, we expect to FID and break ground on our first carbon capture storage project at our Elk Hills gas processing plant. Next, we recently signed a brownfield MOU to develop carbon solutions for a leading California power company, which will allow for up to 1.5 million metric tons per annum of CO2 sequestration. While important to CRC, this partnership is uniquely aligned with California’s goal to decarbonize by 2045. I’ll take a moment to explain the significance of this MOU. California’s regulators have highlighted the importance of carbon sequestration and acknowledged that decarbonizing power is critical as this high-emitting industry is vital to grow our economy. Our new MOU with Hull Street Energy, a leading power provider in a state that desperately needs more clean power today, is aligned with ours and the state’s climate objectives. Natural gas is necessary to power California today and combining it with CCS will deliver net zero power, which is needed to achieve the state’s climate goals. California’s own Senate Bill 100 states that 100% of retail electricity sales must be sourced from renewable and zero-carbon resources by 2045. At CRC, we’re doing our part to lead California’s decarbonization, but we need regulators to do their part and take fast action on CO2 pipeline regulations to enable the installation of new pipes. This will allow carbon to be safely captured, transported, and stored. Our CTV subsidiary is rapidly scaling today with nearly 4.2 million metric tons per annum of CCS projects under consideration and other substantial agreements in discussion. Lastly, we continue to explore multiple opportunities in connection with new AI data centers in California. Having existing power required to run these centers, coupled with a desire to decarbonize that power, creates a unique first-mover advantage for CRC. Data centers are expanding rapidly across the country, with contracts for nuclear, SMRs, and geothermal energy sources receiving recent attention. We believe that natural gas power generation with CCS is the best option for tech companies in California, given the expansive existing infrastructure and the ability to reduce emissions. We are positioning CTV as California’s energy solutions provider, with the goal of making data centers carbon-free. Together, we can attract and retain highly technical, high-paying jobs and encourage new investments in our state with the aim of meeting California’s aggressive decarbonization goals and helping ensure the reliability of an already taxed power grid. We hope to have more to report soon on CRC’s role in creating the carbon-free digital bridge between energy and tech. Let me close out our remarks with some preliminary thoughts on 2025. Over the last few weeks, we have seen tremendous volatility in oil prices. With this backdrop, we have taken steps to provide near-term cash flow certainty through our significant hedge positions. For the full year 2025, roughly 72% of our oil production is hedged at an average floor price of $67 per barrel. These positions underpin our merger assumptions and support our cash flow. We are confident that we have the right strategy and our 2025 priorities are clear. We will maintain our strong balance sheet and improve our bottom line. Through continued capital discipline, delivery of area-related synergies, and the strength of our near-term hedges, we expect to generate significant cash to both reduce total debt and return meaningful cash to investors. In the E&P business, we will proactively manage our low natural declines with a combination of workovers, sidetracks, and new wells with permits on hand. We plan to start 2025 with a one-rig program, which we can sustain through 2026. In Carbon TerraVault, we will add scale in our leading carbon management business, entering into agreements with new brownfield and greenfield emitters. After years of planning, we are moving closer to our target to inject CO2 into CTV I by the end of 2025. In 2025, we will once again demonstrate the strength of our power business. We have resource adequacy contracts in place that will increase these payments by 50% year-over-year to approximately $150 million in 2025. Lastly, we will aggressively pursue additional cash flow-generating opportunities. We are in an unrivaled position to provide solutions for AI data centers, the power industry expansion, and other new industries looking to enter our great state. We are a different kind of energy company, and we look forward to unlocking the value of our business for the benefit of our shareholders and our fellow Californians. With that, we can now open the line for questions.

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

Thanks. Good afternoon. I want to begin with the Hull Energy MOU you signed. This is significant for two reasons: it is your largest agreement to date, and it pertains to a brownfield situation. You mentioned that CO2 pipeline regulation in California is necessary. Can you share your current thoughts on that and a timeline for when it might be addressed? Additionally, could you provide some context about that agreement in relation to the location of assets in California? Would this likely be the first area you consider for that, and what would be required for you to manage the entire process instead of just the storage aspect?

Hey, Scott. Regarding CO2 pipelines, that’s definitely going to be needed to scale the business to where we want to take it. There’s significant market demand and a market need to reduce emissions. I think our MOU with Hull Street proves that there’s market appetite and this is also going to be needed to attract data centers in California. So I think this transaction or this potential transaction highlights the market need to get there. So the next step to be able to scale the business, because this will certainly be one of many opportunities we bring to the table, will be the connectivity on pipe. As we talked about before, we have two ways to think about pipelines. One is a Californian can make around their SB905 bill to be able to regulate pipelines throughout the state. But we also are looking at the federal government and I believe they’re going to start drafting potential pipeline legislation soon. So we definitely need it to scale the business. As we think about a portfolio of greenfield and brownfields, we like the combination of two new fields with greenfield, existing emitters with brownfields. But this is just a start, right? And the evidence of the market support, the evidence of the market need is going to be critical to take this going forward. So the nice thing is we were able to continue to be very selective as we advance the permitting process in getting to this first ever CUP permit at Kern County awaiting the EPA. We’re able to now get to the next stage of our development, which is this brownfield emitter portfolio that we’ve been building. So excited that we got here with Hull Street to announce an MOU today. We’re not being specific at this point on project details. There are still things to work through. But we’re building that queue, we’re building that inventory for brownfield emitters, and a lot more to come.

I appreciate the context. And as my follow-up, obviously the political landscape has been pretty dynamic, we’ll say, in the last month or so. And obviously, with the change that came about last night, how do you think about the prior agreements that you’ve signed? Were they very reliant on the IRA bill that was put out there or do you think if there is some uncertainty in the IRA bill or that changes, those prior agreements really, from a financial perspective, don’t change for you all too much?

Yeah. We headed into the election looking at the aspects of the IRA that we’re working through as bipartisan. So if you look at carbon capture and sequestration, it’s really being done nationally. There’s a lot of interest in states that have both emissions and the capability to store them, irrespective of if they’re red or blue states. We think this is the right compromise solution, right, to use your existing infrastructure and retrofit with CCS. So we went into the election thinking it’s bipartisan. Certainly, red states use CO2 for EOR, so we don’t see that changing at all. So we think the IRA is the right thing to bring more technology and investment forward. But as we think about our California projects, there’s multiple ways to ultimately make these projects viable, right? So IRA is one component, we feel very, very good about that. We also have the LCFS program here locally. But what we’re starting to also develop is both the voluntary credit market is starting to take hold, but then you’re also going to start seeing a premium value to having clean electrons and clean products, right? That’s where bringing the data centers and it doesn’t have to be data centers, right? It could be really any customer that sees value in having clean base load power or clean, lower carbon intensity fuels. That will come to the table and really benefit on CCS. So if you look at the entirety of the incentives and the market opportunity, we don’t see an over-reliance from one versus the other. We think the whole kit is going to be ultimately what’s needed to make this, the CCS, the carbon management business really take off nationally. But for us specifically in California, we see multiple ways to win, multiple ways to bring these projects forward and we don’t see that changing at all with the election.

Thank you.

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

Hey. Good morning, guys, Francisco and team. I guess first, it’s really good to see some definition forming around the option value in your portfolio. As you know, we’ve been pretty constructive on your power business and the opportunity to take some of those watts behind-the-meter. If there’s demand for clean base load power, we think that you guys are well-positioned to provide it. And I guess that brings me to the MOU. I don’t think it’s coincidence that this comes after receiving the surface permit. You’ve got the Class VI penciled in for December. Can you give us a sense of the work that’s been building up behind the Class VI and in anticipation of that milestone and whether we should expect even more news flow after getting that permit?

Thank you, Kalei, for the question. We’ve been discussing our Class VI permit for three years, so reaching this milestone is fantastic, especially as it's our first. We cannot overlook the considerable effort that went into getting this permit in Kern County for conditional use. It truly reflects the dedication of the team at CRC in creating value and moving these projects forward. This is indeed an important achievement, but our work is not finished. We expect the EPA permit to be next, tracking for next month. As we’ve considered the scale and impact of the business over the years, there is substantial work ahead in defining where the value chain fits. To recap, we observe a state with a strong commitment to decarbonization, which is mandated by law. We currently have carbon taxes and a greenhouse gas tax that emitters are obligated to pay. There is a real necessity to discover and prolong the life of existing infrastructure that has already been funded by other emitters. In analyzing the landscape, we identified an opportunity to invest alongside Brookfield throughout the value chain. However, with a pioneering approach, there are those who may want to wait and see if CRC can deliver. I believe we are demonstrating significant progress and are leading others in the state, as evidenced by our current memorandum of understanding. I anticipate the same will be true for data centers, where there is a clear market need. When you implement a first-of-its-kind solution, such as natural gas combined cycle with carbon capture and storage, it's understandable for people to question its legitimacy. I believe we are at that point. In response to your question about expecting more, absolutely. The market is ready for these solutions, and we are prepared to provide them. While I cannot discuss other conversations in detail, I do anticipate more developments in the coming months. Given that our resource, pore space, is finite and will fill up over time, it is crucial to bring in the right long-term partners who will greatly benefit from CO2 storage and capture.

I appreciate that, Francisco. This is my really quick follow up. So last week, the regulators pushed back on the Susquehanna plant going behind-the-meter. Can you talk a little bit about why the California market is different than behind-the-meter? And I’ll leave it there.

Yeah. Kalei, I won’t speak to what’s happening in other states and might not know the details to speak to them. But what’s the dynamic in California is unique. We say laid out already there’s mandates to decarbonize and this is not about a there’s both carrots and sticks around that ultimately to make these companies viable going forward. They need to find a solution to store that CO2. We can’t continue where our goal is to lower emissions. So when we think about what’s in place in California, there’s a significant penetration of renewable solar and wind and there’s an appetite to move away from natural gas power. Well, as we do that, what we’ve seen is it’s a cost increase to consumers on electricity. We’ve also seen a lack of reliability in the system. So as we think forward, okay, what do we need to do to deliver both, right. They should not be mutually exclusive. We can lower emissions and we can provide reliability. We think it’s this infrastructure that’s in place that today acts more as speaking speakers and not as base load. These are going to be great solutions for the state. And the key is to take some of these power behind-the-meter. That’s not servicing the communities, but it also can be used to attract new businesses that ultimately have a great benefit for California. So the dynamics are different here. We have excess capacity in natural gas generation. We’re going to make it clean and we’re going to like to bring it behind-the-meter.

Thanks, Francisco. See you next week.

Thanks.

Thanks. The next question comes from Betty Jiang with Barclays. Please go ahead.

Hello. Hi. Thank you for taking my question. It’s definitely great to see the momentum that you’re seeing in a carbon management business. But as those activities start to pick up and you’re imminent to FID, your own gas processing carbon capture project starting for next year. How should we be thinking about the CapEx, the capital allocation that you expect to put into the carbon management business next year? And just help us remind us, like, what percentage of the capital is being spent at the CRC level versus what’s being funded at the subsidiary JV level? Thanks.

Thank you for the question. Our first project, 35R, involves carbon capture at an existing facility where we will remove CO2 from the gas stream. We expect to reach a final investment decision shortly after receiving the necessary EPA permit, which is the last condition needed to move forward. This project is expected to cost less than $20 million and requires a relatively simple modification of the existing plant. We also have the injector nearby, about 4,000 feet away, making it a low capital project. We will provide more details once we reach the final investment decision. For now, in terms of capital, we have communicated to the market that our focus is on the 25R project. The ongoing operational costs consist of a mix of permits and personnel expenses, as outlined in our financials. The significant capital projects will come later as we expand our capture, transport, and storage business, particularly for brownfield emitters, where we have a strong partnership with Brookfield. We can sell a portion of the pore space at $10 per ton, which will help finance capital calls for our carbon capture business. I anticipate that 2025 will be a year of further developments and more partnerships with emitters across various industries. However, capital expenditures in 2025 will primarily be limited to the 25R and 35R projects that we're initiating this year, with more substantial investments expected in 2026.

That’s really helpful. Thank you for that. My follow-up is cash return and buyback specifically. The third quarter, we see the first full quarter of Aera impact and seeing the cash flow generation capability of this business. The adjusted free cash flow is $171 million this quarter and then you bought back only $42 million. It’s a bit less than we thought you are capable of doing. So as we look forward to 2025, the business protected by hedges. So should we be expecting that buyback pace to pick up or any reason that it wouldn’t?

The first point I want to make is that we see significant value in our stock. Considering our various business lines, opportunities, and catalysts, it's encouraging to see the first catalyst with our MOU today. We don't believe the stock reflects this value, so we will continue to buy back shares aggressively as long as this situation persists. We have had a share repurchase program since 2021, and over the last four years, we've used about 65% of our free cash flow for buybacks. The recent Aera transaction adds stability, scale, and cash flow to our business. After closing the Aera deal, we reduced our cash levels to zero and then rebuilt them to over $200 million in just one quarter, highlighting our cash flow capacity. We still have approximately $600 million authorized by the Board for share buybacks, and we assess this daily, exploring smart capital deployment options. We're not fixing a specific number of shares we'll buy in the future, but our past actions indicate our potential course if opportunities arise. One advantage of our cash-generating business and hedge book is the ability to reduce debt. We have around $240 million in outstanding 2026 bonds, which are callable at par starting next year. We're committed to managing a strong balance sheet and liquidity while deploying capital in ways that reward our investors. That summarizes our approach to shareholder returns.

That sounds great. Thank you so much for that color.

Thanks, Betty.

The next question comes from David Deckelbaum with TD Cowen. Please go ahead.

Good afternoon, guys. Thanks for taking my questions. I was curious just as you think about 2025. Obviously, there was some outperformance in the upstream business on just capital deployment this quarter. As you integrate the Aera assets and you think about you kind of gave some bookends around production guidance for next year. As you think about optimization, was some of that optimization and high grading workover this quarter more of a one-time thing or do you see future opportunities as you kind of look through that portfolio where you could significantly lower capital expenditures next year as you kind of look to high grading?

Yeah. No. First of all, we see a lot of opportunities as we continue to integrate. We now have the hands on the steering wheel, have a really good sense of the opportunity set and the capacity of the business. Yeah, the bread and butter of California is the workovers and sidetracks. And those are great projects that make really good returns and help offset the decline. I would not say that the third quarter is evidence of any sort of one-time activity. I think it’s the continuation of the business is to continue to really focus on those type of projects on a go forward basis. We obviously are not going to guide today to 2025 in terms of specifics, but we see a very similar trajectory of the business in 2025 from an E&P perspective in terms of capital deployment, in terms of activity set, in terms of decline rate. So it’s a steady business in that we can do a lot of the blocking and tackling by surveillance-based management, workovers and sidetracks and expect that to continue. We’ve been rebuilding the permit inventory as well. So we see a similar trajectory into next year as we’ve had this year and it was great to see the production coming in strongly as it did. That’s just a testament to the quality of the assets and the quality of the team that runs them.

I appreciate the insight and congratulations on the carbon storage MOU. I'm interested in your current perspective on the solar market in relation to your surface acreage. This was a notable point in the last quarter, where you mentioned having approximately 84 to 85 megawatts of projects in development. Considering all possible solutions for enhancing power generation in the state, there is clearly significant potential with carbon capture and clean energy from existing emitters. How is progress on the solar front, and how do you view the demand for opportunities between solar projects on your surface acreage and the interest in carbon capture?

It all fits together very well. As the largest holder of mineral land in the state and a significant surface landowner, we are facilitating many solar projects on our property. We have the capacity to introduce more solar solutions in California, and those initiatives are advancing successfully as part of our clean energy portfolio. However, I want to expand beyond just solar. We are also exploring traditional battery solutions, but we see a promising opportunity with enhanced geothermal energy in California. This involves harnessing heat from natural reservoirs or steam flooding to generate clean energy, effectively utilizing the earth as a battery. We are enthusiastic about the potential to provide backup power for data centers and contribute to a greener grid. We see ourselves as enablers of these technologies because we possess the reservoirs, land, and often the interconnectivity needed to transform innovative ideas into concrete solutions. We're developing a diverse portfolio that includes not only solar but also traditional geothermal, enhanced geothermal, and battery storage, and we are excited about the direction of this business.

Thanks, Francisco.

The next question comes from Josh Silverstein with UBS. Please go ahead.

Thank you, everyone. I have a couple of questions regarding upstream operations. First, I'd like to know about oil realizations. What are your thoughts on potential developments in this area, especially in light of the recent news about a California refinery shutting down, and possibly others as well? I understand you're more connected to Brent. Do you anticipate any changes in the discount you face in relation to Brent, or improvements in higher realizations compared to WTI, over the next few years?

Thank you for the question. It’s important to remember that California has a significant demand for oil, particularly for gasoline and jet fuel. The state accounts for about ten percent of the total gasoline consumption and roughly one-third of jet fuel use. Therefore, the demand remains strong. In terms of refining capacity, California produces around 1.5 million barrels through its refineries, with CRC contributing over 300,000 barrels per day. These refineries were designed for California crude, and in considering the Nelson Complexity, they are geared towards producing jet fuel and other products. We utilize our crude as a blending source, and there is a notable preference for our crude when blending with lighter or high sulfur crude from other states or countries. This is why we can see high realizations for our heavy crude, which often trades above WTI in California. I’ll pass it over to JB to see if he has anything to add.

I think Francisco basically captured the essence of this. 1.5 million in demand versus 300,000 in native production. It’s a nice ratio. These refiners really built around the crude and that’s not changed. It could change, but it would take capital investment, which I think right now you’d find most refiners reticent to make. So I think for the time being, we’re going to continue to see strong demand for our products in particular.

Got it. Thanks for that. Next one is, I’m curious what you guys need to do to implement and execute on the remaining $100 million of the Aera synergies. You’ve done a really good job on the financing and G&A side. It looks like the bulk of the $100 million is more operational related. So what needs to happen for you guys to execute on that? Thanks.

Yeah. No. I appreciate the question. That’s an absolutely tremendous job by the team. We talked about it as we announced the Aera merger. This is a unique fit of assets. They’re right next to each other, have been running independently for decades. So when we talked about synergies and the confidence we had on those, it wasn’t just about rightsizing an organization and thinking about the organization. We were really focused on a lot of the operational synergies. You can see in our slide deck the disclosure we have between G&A and OpEx. And ultimately, we see a natural progression of synergies focused on supply chain, focused on infrastructure optimization and scheme for optimization. But I’ll pass it over to Omar Hayat to provide more color and some examples on where the next $100 million will come from.

Yeah. Thank you. So, the way to think about synergies is really think about it on a timeline. So what we have done so far is we have executed the projects that we can execute fast and deliver value, which is the workforce optimization and the supply chain contracts, re-evaluating them, moving the combined company to more favorable contracts now that we have doubled our scale. The next thing in the line is really around infrastructure consolidation. And what we’re looking at here is leveraging our proximity to Aera assets and connecting those assets to move the products in the most economical direction. What I mean by that is if you look at power, while we feed most of our operations with our own generated power and therefore can provide power at a low cost, there are still leases and assets that are on PG&E power at a higher cost. So we look at the opportunities to bring those assets at a lower energy cost by power provided from our own assets. Similarly, if you look at gas, we have net producers in Elk Hills and net consumers in Bell Ridge, which are two major fields. So we have recently connected those two fields and we look at moving the gas in the right direction based on prices and consumption. We also have a lot of capacity in our cryogenic gas plant at Elk Hills and not all our assets are connected to that plant. So there is a large opportunity we see in bringing gas to CGP and extract natural gas liquid in the future. And comments that were made earlier by Jay and Francisco, we now produce quite an array of oil in terms of API gravity. And our marketing team continuously works with operations to look at the right blends to send to refineries to optimize our realization prices. And then finally, the water is the same way. There are disposal capacities. We have access disposal capacities in some areas. We have pinched in others. So we consolidate to optimize costs around water movement. So those are just some of the examples around infrastructure consolidation.

Got it. Thanks, guys.

Thanks, Josh.

The next question comes from Scott Gruber with Citigroup. Please go ahead.

Hi and good morning on your end. We’ve covered a lot of ground, so just one for me, given the MOU announced. I’m curious, is big tech interested in directly underwriting capture on gas plants? Are you having those types of conversations or is it kind of the broader market forces here and the incentives in place that’s really underpinning the interest or capital to come into this space? I’m just curious how direct or indirect that big tech driver is today when it comes to capture on gas plants?

I think we’re about to find out. When you have a project that very few people possess, no one has established the framework we have, which includes the capability to utilize excellent infrastructure, natural gas, combined cycle power, and then implement carbon capture and storage to reduce emissions. It truly addresses everything we believe large technology companies are seeking as they develop artificial intelligence. So why aren't we seeing announcements across the U.S.? Because it simply doesn’t exist. However, you can observe how power-hungry they are, exploring every possible avenue to secure power as they compete for market share. So what does that imply regarding interest? I believe it's significant. Is there an underwriting capacity? We have yet to determine that. This is where having proof points or permits comes into play; it’s about showcasing what we can offer. Today at Elk Hills, we believe we present a one-stop shop for land, water, fiber networks, power, and space for carbon capture and storage, making it an appealing proposition. It’s really about seizing a first mover advantage that we expect will position us as a market leader. This also allows us to be selective, ensuring we have the right partner, the appropriate capital structure, and the ideal return profile for our investors. That’s our ultimate goal, and we will be glad to share updates when we have them.

That’s great. And certainly a great solution. I guess in terms of cadence, in your view, after you kind of work through the small stock of nukes that we can restart, do you think the interest in capture on gas plants takes a meaningful step higher? Is that what we kind of need to progress through?

Yeah. Absolutely. I think that should be the natural progression that we see in the state. We see a lot of opportunity. I mean, we really are just getting started and this brownfield conversation of can this be something that CRC executes? I think we proved that today that we can. But there’s a lot of market appetite behind this and I look forward to bringing more projects forward so that we can talk about it.

The next question comes from Leo P. Mariani with ROTH. Please go ahead.

I wanted to just follow up on the drilling permit situation. It seems like the CalGEM has been kind of rethinking that for many months now. And I was just curious if there was kind of any update there. Are there any actual drilling permits coming out of CalGEM to you or others that you guys could kind of talk about? I certainly know there’s work over and sidetrack permits or whatnot, but just curious if there’s any update there?

Thank you for the question, Leo. There are several ways we can get our permits back on track. We are currently addressing the Kern County Environmental Impact report we discussed earlier, and we are also working on obtaining a Conditional Use Permit. We’ve observed that other operators are making good progress with their Conditional Use Permits, with around 80 new permits issued to them in the state over the last two quarters. They are following a similar approach to ours, specifically focusing on Conditional Use Permit field level CEQA, which is tailored to specific fields rather than countywide. This is the path we are undertaking as well. We have some of the largest fields in California, and most of our Conditional Use Permit applications are concentrated in four fields: Elk Hills, Buena Vista, Kern Front, and Bell Ridge, which together account for approximately 85% of our approved undeveloped reserves. We see various options available to help us regain our permits, with the potential for resolution in the second half of next year. We are actively monitoring Kern County's progress on their revised ordinance and collaborating with CalGEM to meet CEQA requirements. There's a lot of activity taking place, and we are witnessing positive developments with smaller operators as well. Additionally, we're making good progress on workovers and sidetracks. While it's challenging to predict exact timing, we are growing increasingly confident that a resolution is forthcoming, and we see productive discussions regarding the permit.

Okay. Appreciate that. And then earlier you mentioned certainly the need in the state to get some pipeline regulations in place on the CO2 side. Just wanted to get a sense. I know that was something that might have been getting discussed in the legislature over the summer. Do you sense that there’s been any real progress there or is this issue just kind of slipped? Maybe there was other priorities and do you have expectations this can get taken up again by the legislature maybe early next year when things are back in session?

Yeah. That was my expectation. There’s a lot of support and a lot of interest in the legislature to lift the moratorium on CO2 pipelines. I think it’s just a matter of who comes first, right? So we see California moving in that direction. We see the federal government also trying to address it. Again, we need one. One of the two would satisfy it. But really what we see is California has an opportunity to move forward and ultimately capture an advantage that we have over the rest of the country by doing this earlier and attracting significant capital into the state. That’s the opportunity we’ve been conveying to legislatures. And, yeah, I would expect it to be picked up at the next session as we move forward. And but it’s all connected, right? I think if you start delivering the proof point, so there’s a market need, there’s permits flowing on the subsurface, that’s a natural step to look at ways to bring in existing pipelines that can be retrofitted to transport CO2 as a natural next step. So continue to have those constructive conversations and I do expect the conversations to continue as the session begins again next year.

The next question comes from Michael Scialla with Stephens. Please go ahead.

Hi, everybody. Thank you. If you do find that big tech is willing to underwrite the decarbonization of power plants, you have a large co-gen plant there at Midway Sunset. I was wondering if all the capacity there is needed to power that field or is there some excess capacity there, like you have it uphill that could be used by a customer and do you have any plans to decarbonize that plant?

We have over 850 megawatts of power generation across the state through various plants. Currently, we use less than half of this capacity for our oil field, with the remainder contributing to resource adequacy and supplying the grid. Our focus is on optimizing what provides the greatest value to our shareholders. While we have discussed CalCapture at our Hills site, where we plan to implement carbon capture and storage, we are assessing the cost-benefit of everything in our portfolio. We have a preference for owning power assets in the state and believe a balanced solution incorporating carbon capture or natural gas generation is ideal. Looking ahead, our goal is to convert a significant portion of this capacity into firm contracts and long-term power purchase agreements, whether with large tech companies or others. This is the opportunity we're actively pursuing.

Got it. And then with Elk Hills, any step portion, you have the excess there that goes to the grid now. Is that, I guess, tied to the grid or what would be if you did have an opportunity to have a customer there? How much is that free to go to the customer?

The plant produces approximately 550 megawatts of power, with about one-third used by our exploration and production operations. This leaves two-thirds of the power without a specific destination, so we feed it into the grid at varying spot prices throughout the year. Additionally, we engage in resource adequacy, which involves standby power contracts with various groups in California, providing us compensation when the grid faces high demand, especially during the warmer months. We've participated in this program for years and noted a rise in contract value. In 2024, we generated $100 million from standby power in California, and this is expected to increase to $150 million in contracted value by 2025. The excess capacity primarily doesn't have a set destination, which is why it is sent to the grid. We have the potential to take this capacity behind the meter, aligning with California's goal of increasing renewable energy in the grid. Our aim is to form partnerships and utilize this power in an optimized manner, targeting industries that could benefit from base load power with carbon capture and storage. Our challenge is to identify the customer base that can utilize this power beyond the grid. Currently, we are optimistic about resource adequacy and actively participating in it, but our decisions will focus on maximizing the value of our surplus power.

The next question comes from Noel Parks with Tuohy Brothers. Please go ahead.

Hi. Good afternoon. I have a few questions. Could you discuss the momentum and timing you’re observing between brownfield projects with emitters and your conversations about new projects, such as data centers? Are the main topics of discussion focused on the terms, or is it more about complexities like risk sharing as you work towards an agreement?

We have discussed CRC being rich in catalysts, and it’s encouraging to see those catalysts starting to emerge. The mix of brownfield and greenfield projects is important, with connectivity being crucial for brownfield developments, particularly the link between the emitter and the storage location. This highlights the significance of CO2 pipelines. Additionally, when we consider our greenfield projects at Elk Hills, we’ll be incorporating renewable natural gas, clean hydrogen, and renewable diesel. We aim to identify market opportunities to offer these clean fuels to emitters, helping them reduce their emission footprint. There are many synergistic elements in our portfolio strategy, and while different project aspects still require attention, connectivity is essential. We are enthusiastic about our role as a solutions provider in California and believe we are well-positioned to capture significant market share. Although there are many details to finalize, the market opportunity appears very strong.

I see that we’re past the top of the hour. This concludes our question-and-answer session. I would like to turn the conference back over to Francisco Leon for any closing remarks.

Thank you so much for joining us today. We will be presenting at several investor conferences in both November and early December, and look forward to seeing everybody on the road. Thanks.

The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.