California Resources Corporation (NYSE:CRC) Q4 2025 Earnings Call Transcript

California Resources Corporation (NYSE:CRC) Q4 2025 Earnings Call Transcript March 2, 2026

California Resources Corporation misses on earnings expectations. Reported EPS is $0.47 EPS, expectations were $0.49.

Operator: Good day, and welcome to the California Resources Corporation Fourth Quarter 2025 Conference Call. [Operator Instructions] Please note that this event is being recorded. I would now like to turn the conference over to Daniel Juck, Vice President of Investor Relations. Please go ahead.

Daniel Juck: Good morning, and welcome to California Resources Corporation’s fourth quarter and year-end 2025 conference call. Following prepared comments, members of our leadership team will be available to take your questions. By now, I hope you 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. Today, we’ll 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’ll now turn the call over to Francisco.

Francisco Leon: Thank you, Daniel, and good morning, everyone. I’ll begin with our 2025 results, then highlight what different CRC today. Including our unique position in California’s energy and decarbonization landscape and how that translates into long-term value creation. I’ll then turn it over to Clio for the financials and 2026 guidance. Let me start with the big picture. In 2025, we grew production for the third consecutive year, delivered record financial performance and return record capital to shareholders. Even as commodity prices declined 14% year-over-year. Our guidance shows further annual production growth in 2026. Our high-quality, low-decline conventional assets generate stable cash flow, supporting annual capital returns, while maintaining balance sheet strength.

Since 2021, we have returned nearly $1.6 billion to shareholders, underscoring our commitment to long-term value creation. Our capital priorities remain clear: invest in high-return opportunities, preserve financial strength and return excess cash to shareholders. We will continue to take a measured and disciplined approach to shareholder returns, maintain the flexibility to invest through the commodity cycles. As we enter 2026, CRC stronger and more resilient with a differentiated asset base and improved access to the full depth of our reserves, positioning us to grow cash flow per share. Three factors define CRC today. First, our conventional reservoir base is a core strength. These assets are characterized by low natural declines, strong recovery factors and very predictable performance.

That allows us to sustain production with less capital and lower risk than shale-focused peers. Our expanded 2P disclosure of nearly 1.2 billion Boe, highlights the depth and longevity of our inventory, supporting 20-plus years of development at current production levels. Our assets are large scale, low decline, multi-stack sandstone reservoirs. Conventional systems where production is sustained through reservoir injection management and long-duration recovery, requiring low capital intensity without the need for the continuous high-intensity reinvestment. Notably, we see a similar recovery potential in our Belridge field compared to Elk Hills. But at an early stage of development, reinforcing the strong industrial logic behind the Aera merger.

While many peers are looking to new basins and international opportunities to extend reserve life. Our deep inventory provides confidence in the long-term durability of our production and cash flows right here in California. Second, regulatory progress has been meaningful. The resumption of new drill permitting and the steady flow of approvals through the system represent a step change from where we’ve been in recent years. We appreciate the efforts of state and local regulators to move this process forward. This progress positions us to stabilize production while supporting the state’s objectives for energy affordability. We now have the majority of the permits required to execute our 2026 capital program, which materially expands our flexibility to plan, sequence and high-grade capital across the portfolio.

Importantly, it also allows us to adjust activity levels methodically as market conditions and returns dictate. We have returned to drilling new wells in 2026 and see ample potential across our long runway assets. Third, our integrated strategy continues to differentiate CRC. We’re investing in high-return oil and gas developments, while advancing our carbon management and power platforms in a capital-efficient and return-driven manner. Carbon TerraVault has moved from concept to execution. Construction is complete on California’s first commercial scale CCS project at Elk Hills, and we’re now in the commissioning and testing phase. We have successfully captured CO2 from our gas processing plant and are awaiting final EPA approval to commence injection.

We believe each step in the process materially derisked the platform. from engineering and construction to capture performance to regulatory clearance and positions us to transition into full operations. Importantly, the proximity of our permitted CO2 storage reservoirs to existing infrastructure across the street, provides a structural advantage as demands grow for reliable, low-carbon power solutions. We continue to advance discussions related to our power platform with multiple high-quality counterparties. The demand signal is evident, but these are large complex transactions in a market that is still maturing. As it evolves, commercial structures are improving, and our options continue to expand. We have strong conviction in the value of our integrated power to CCS offering.

We’re not focused on speed. We’re focused on getting the fundamentals right and securing the right agreement at the right time, one that appropriately aligns risk and returns and delivers durable long-term cash flow. As the market matures, we believe our differentiated position only strengthens. So what does this all mean for CRC as we look ahead for the long-term? What defines us is durability of inventory and returns. We’re investing in 2026 from a position of strength. With 2027 marking the point where we returned to a steady-state level of activity to sustain production. On a hedge basis, our corporate maintenance breakeven sits in the mid-50s WTI, providing resilience in the range-bound oil macro. This reflects the full enterprise, including upstream operations, Carbon TerraVault, power, base dividend interest, corporate needs and hedges.

For context, our upstream-only maintenance breakeven is in the low to mid-50s WTI among the more competitive levels across pure-play E&P tiers. This outlook is grounded in asset quality, inventory depth and structural cost discipline, not aggressive capital assumptions or optimistic pricing. Together, our reservoir base improved regulatory visibility and integrated strategy support resilient long-term value across cycles. With that, I’ll turn it over to Clio to walk through our financial results and 2026 guidance. Clio?

Clio Crespy: Thank you, Francisco, and good morning. The fourth quarter capped a record year for CRC. We delivered on our financial and operational targets, while further strengthening the durability of our business. In the fourth quarter, we generated adjusted EBITDAX of $251 million and free cash flow of $115 million, including 14 days of contribution from Berry. Net production averaged 137,000 barrels of oil equivalent per day with oil realizations at 97% of Brent before hedges. For the full year, we generated nearly $1.25 billion of adjusted EBITDAX and $543 million of free cash flow, the highest level since 2021. Results were driven by strong base performance, structural cost reductions, realized synergies and higher-than-average resource adequacy payments from our power assets.

Net production increased 25% year-over-year to 138,000 barrels of oil equivalent per day, reflecting consistent capital execution and value accretive transactions. Fourth quarter capital spending totaled $120 million within guidance, bringing full year capital deployment to $322 million. Capital allocation remained returns-focused throughout the year. In a permitting constrained environment, we directed investments towards our highest drilling opportunities and returned excess free cash flow to shareholders. The dividend continues to anchor our returns framework, and we have grown it meaningfully since 2021. In 2025, we returned approximately 94% of free cash flow to shareholders through dividends and share repurchases. Given the permitting constraints last year, repurchasing shares represented an attractive use of capital and enhance per share cash flow.

The Board recently approved a $430 million increase to our share repurchase authorization and extended the program through 2027, bringing remaining capacity to approximately $600 million. As we enter 2026, we began receiving new well permits, as a result, a greater share of our capital will be directed toward high-return reinvestment opportunities that support sustainable production and cash flow growth. This framework reinvesting at attractive returns, while maintaining a strong balance sheet and a durable dividend remains central to our capital allocation philosophy. Turning to the balance sheet. We exited the year at 1x leverage with total liquidity of $1.4 billion. During the year, we completed a refinancing transaction associated with the Berry merger.

Redeemed our 2026 senior notes, expanded lender commitments and received improved outlooks from the rating agencies. Collectively, these actions enhance financial flexibility and reduce our cost of capital. Looking ahead to 2026, our guidance reflects a measured capital deployment ramp-up and resilient cash flow generation. At $65 Brent, we expect to generate approximately $1 billion of adjusted EBITDAX supported by lower costs and ongoing synergy capture. These efficiencies position us to sustain strong margins, despite lower commodity price assumptions and a softer resource adequacy market. We expect capital spending at roughly $450 million. Drilling, completions and workover capital is projected at the $280 million to $300 million range, supporting a 4 rig program.

Our development plan is grounded in decades of production history and consistent performance, and we retain flexibility to adjust activity levels as the year progresses. Net production is expected to increase 12% year-over-year to 155,000 barrels of oil equivalent per day at midpoint of our guide, with oil representing roughly 81% of volumes. 2/3 of our expected oil production is hedged at $65 Brent, providing meaningful cash flow protection. We enter 2026 with a stronger balance sheet and expanded inventory of high-return projects and improved visibility into sustainable production and cash flow growth. With that, I’ll turn it back to Francisco for closing comments.

Francisco Leon: Thanks, Clio. As we look to 2026 and beyond, our priorities are clear. We’re focused on responsibly developing our deep, high-quality resource base, lowering cost, maintaining our balance sheet and effectively allocating capital. We will continue to advance platforms that will shape CRC’s future. Carbon TerraVault and our power strategy are moving from concept to execution and are expected to contribute to a more durable, diversified cash flow profile over time. CRC plays an important role in California’s energy future. Our locally produced oil and gas, combined with scalable carbon management and power solutions, position us to help meet the state’s affordability needs, while advancing emission reduction goals. As California’s demand for secure, lower carbon energy evolves, we see our integrated model as part of this solution. Operator, we’re now ready for questions.

Q&A Session

Operator: [Operator Instructions] The first question comes from Scott Hanold with RBC Capital Markets.

Scott Hanold: I was hoping if you could provide some added context on your 2P inventory update and maybe talk to see how that — talk to that relative to how you see permitting — the permitting environment moving forward? And also speak to the duration of that inventory to hold your production flat.

Francisco Leon: Scott, thanks for the question. Really appreciate you leading with this question. Important that we convey in the potential of the business. And I have a few things to say. So we have a great foundation. That’s well known. Conventional assets with low declines, repeatable inventory. We actually have really good rock that actually flows. It’s an asset base that’s been built to outperform through any cycle. But really 3 things to highlight. The — in terms of the runway, the inventory, as I said in my remarks, we have permits in hand to execute 2026. We’re building line of sight into 2027. So now that permitting is back to normal cadence, that allows us to put the focus on the resource. And we grew our 1P reserves, 350% reserve replacement ratio on the back of the permits coming in, stronger-than-expected base decline and the Berry acquisition.

And if you look at the value of the 1P reserves alone, that’s about $9 billion at SEC prices. But what really stands out is the running room beyond that. We said we have 23 years of inventory of 2P basis — on a 2P basis in our disclosure. We operate about 4 of the largest oil fields in the U.S. You can add 3 more, so 7 have each well in place that exceeds 3 billion barrels of oil in place. And these are fields that have been producing for decades and have many, many decades ahead. Recovery factors of 40% plus on waterfloods, 75% plus on steamfloods. And that just tells you some of that gives you a sense of how much resource remains to be captured. But on top of the resource, we also have very low subsurface risk that makes capital allocation very predictable.

We have a lot of well control across all of our acreage. A lot of our production is about 2,000 feet deep, so very shallow. We have a lot of data that helps us derisk every dollar that we deploy. A lot of the activity that we have on new wells is infill drilling. So low geological risk. And as technology continues to help us improve our lower base decline, we have a very repeatable capital-efficient program that we can execute with confidence. Finally, I would like to highlight, it’s truly an opportunity set with stacked optionality and returns. We have thousands of feet of stacked pay across multiple producing horizons, 2 million acres of minerals, 89% on average working interest, which means really strong netbacks. As I highlighted in my remarks, Belridge is probably the best example.

We look at Belridge in terms of development as we saw Elk Hills about 20 years ago. So extremely long runway, low risk. And one of the highlights of Belridge is it’s less than a 5% royalty burden. So amazing netbacks and really excited about the setup that we have for the company going forward. I think you had a second question?

Scott Hanold: Yes, yes, absolutely. I appreciate the context. And as you — and just staying on kind of a similar theme, if you step back and think about 2026 program, it looks like 4Q flattens. I’m just wondering, is that a good forward rate to utilize for that building the maintenance of ’27? And also maybe a little bit about the capital efficiency. That appears to have improved as well. So any color there? And I don’t know if it’s the type of wells you’re drilling or what other factors might have helped the capital efficiency.

Francisco Leon: Yes. We’re extremely proud of the work the team has done to improve the capital efficiency. We’ve seen tremendous progress year-over-year and continue to work on it. So I’ll turn it to Clio to highlight — to give some of the highlights around efficiency and the well mix.

Clio Crespy: Thanks, Francisco. Scott, yes, so on our ’26 program, it’s really designed to materially reduce our corporate decline to roughly 2%. So as you alluded, it really equates to 0.5% glide path quarter-over-quarter. That’s effectively flat production throughout the year, while generating substantial free cash flow. And so we’re operating 4 rigs. We’re deploying $280 million to $300 million of D&C and workover capital to support that production on a materially larger asset base. The program is intentionally weighted towards lower risk development. It’s really focused on PUD inventory. And we’ve got roughly 2/3 of our activity on sidetracks and 1/3 on new wells. That’s all supplemented by a very robust workover program.

And the sequencing here is deliberate, more sidetracks and workovers in the first half, and then we transition into new wells as permit inventory builds here throughout the year. So a couple of points. We’re reinvesting less than 50% of cash flow. We’re maintaining our leverage around 1x. You’re really seeing a disciplined capital allocation at work here. And you were asking, Scott, around our capital efficiency. We will think about it through 2 lenses. So on project level returns, but also on corporate capital intensity. If I start with our project level returns, our ’26 program, it’s highly competitive on a stand-alone basis at $9 per Boe of development cost. The program generates just shy of 4x multiple on invested capital. It generates mid-40% returns at $65 Brent and roughly a 3-year payout.

The portfolio is also oil weighted. It’s 90% oil weighted, which supports strong cash margins here and durable economics across the cycle. So those metrics reflect the quality of our inventory that Francisco was highlighting and also the structural improvements that we’ve captured over the past several years. If you take a step back and look at the corporate level, the impact of the Berry integration here is clear. What’s most notable is that we’re delivering this very low decline on a materially larger portfolio without increasing our structural capital intensity. We absorbed here roughly 25,000 Boe per day of incremental production with Berry, while managing to hold the combined business at 2% decline with no increase in our capital and no increase in our rig count versus our early November guide, and that was built in a much smaller footprint without Berry.

So that’s a meaningful demonstration of our improved capital efficiency and our integration synergies. We’re generating the strong marginal returns on our new capital, and we’re also lowering the capital required to sustain the broader base. And that combination really supports our durable free cash flow generation.

Operator: The next question comes from Betty Jiang with Barclays. .

Wei Jiang: Congrats on a very strong finish to 2025. Shifting gears a bit to the other growth opportunities in the portfolio, maybe starting with the CCS business. Can you speak to the remaining approval process needed to start injection at the cryogenic gas project? And maybe more broadly, as the CCS, the carbon capture business is finally moving into execution, what are the key milestones you are targeting this year from a business development or permitting perspective?

Francisco Leon: Betty, thanks for the compliments. And yes, in terms of our CCS business, really good progress, and we are near the finish line to deliver a fully integrated end-to-end capture to storage solution. Construction is complete, commissioning and final approvals are underway. We have successfully captured our first CO2 from the plant to running it to the amine system. And we’re working closely with the EPA through the final operational readiness and compliance steps. We’re excited. This first injection is really a big derisking of the CCS business model and really brings a lot of confidence to the business that we’re building. As we wait for market adoption, and there’s many moving parts to it, but it’s coming quickly, being able to have decarbonized molecules and electrons in California is what we think wins the day.

We have a state requirement under cap and invest to 2045 to decarbonize. So we’re bringing a market solution that may be very different from whatever else is happening in the rest of the country. We continue to see progress from our team in terms of permits. We just filed CTV [indiscernible] with the EPA. That’s another 27 million tons of capacity. It’s adjacent to CTV I. So it’s bringing the hub concept into that Elk Hills area to accommodate higher growth, which we expect. 2026 will also be a year where we see a lot of the permits in the queue that we filed 2, 3 years ago starting to come in the form of draft permits coming forward. So overall, really good progress, really exciting proof point to be able to decarbonize our gas processing plant, but there’s a lot more to go and excited to share the news as it comes, but 2026 is a big year for us.

Wei Jiang: Great. Sounds great. And my follow-up is on the power to CCS opportunity. On Slide 11, Francisco, you alluded to the hub concept of you have multiple power plants that’s sitting all on top of a growing carbon storage. The — can you just expand on what are you seeing in the market on that front? What do we need to see from the market in terms of demand or other maturations to crystallize this opportunity for CRC?

Francisco Leon: Yes, Betty, it’s clear now that the industry that’s going to lead the efforts to decarbonize is the electricity sector, the utility sector. And in California, in particular, that’s going to be a requirement in order to be able to build data centers, in order to be able to source incremental demand, we see it as being — having to be decarbonized. Now we missed out in California from the first wave of data center growth, which is more focused around training. Pretty obvious, we have high power prices here in California, so not the best place to site training data centers. But we’re really excited about the second wave that’s coming through inference and edge compute, where you really have to be close to the user.

So if you look at the map, Elk Hills power plant, CTV I, CTV VII now are right at that intersection of 2 of the most attractive use cases for content, for virtual gaming. So whether that’s — it’s Los Angeles, Las Vegas, these are where we see this very high demand center. So it’s a very compelling outlook as we look out into the next few years. So the things that we’ve done to date, which some of them we highlighted, some of them are new is, first, we wanted to have this power now concept that allows a customer data center more than likely to be able to look at scale. And the scale comes initially from our Elk Hills power plant, but also from the partnership that we made with power plants around our site. We’ve highlighted La Paloma, we’ve highlighted Sunrise, overall, 2 gigawatts of portfolio that ultimately you can scale the data center to.

A more recent update is we’ve been advancing the — what we call the Land Now concept, which is permitted and powered land. We’re working closely with a leading data center developer. We’re in early stages of design and permitting together. We think this is going to be the most compelling and exciting site in California to build a data center. So making good progress along those lines. And as you have line of sight to permits, as you have line of sight into a data center build-out, the hyperscalers we’re picking up more and more interest on people that want to establish a foothold into the California market. The injection of CTV I is also an important milestone by being able to take CCS from a concept to a clean hourly matched energy offering in the PPA negotiation really becomes a differentiator with the rest of the state that’s solely relying on renewables and batteries.

So putting all these things together, so power at scale, site design and permitting and a CCS derisked opportunity is what we ultimately think will be the best path to create durable contracted cash flows and ultimately a good way to unlock shareholder value. So we’re making really good progress.

Operator: The next question comes from Zach Parham with JPMorgan.

Zachary Parham: First, just wanted to ask on cost reductions and your confidence in the Berry synergy capture. In the slide deck, you’ve got an interesting slide that shows incremental cost reductions going out to the 2027, 2028 time frame. Can you just give us a little bit more color on what’s driving those continued cost reductions?

Francisco Leon: Thanks, Zach. Really appreciate the question. So we’re applying the same integration playbook to Berry as we did with Aera. We’re simplifying. We’re standardizing and integrating the business. As we’ve announced, we have — we’re targeting about $80 million to $90 million of synergies. We were able to close the Berry merger earlier than expected. So we’re right now in full execution mode. The areas of focus are around field efficiencies, overhead redundancies, leverage on supply chain, but we also now have the ability to optimize well services through our C&J company. So that on top of the refinancing that we did last year, these are all very controllable, high confidence levers that we’re going to be able to pull.

Ultimately, we still feel good about that $80 million to $90 million. But what’s been really impressive to watch as you step back and that’s the point of the slide is that we’re on a glide path to about $0.5 billion of cumulative structural savings between our 2 deals. So I’m going to let Clio go through some of the details, but the track record of this team, our operations team, in particular, has been outstanding in terms of achieving those synergies and getting to a lower cost structure for the future. But Clio, do you want to take it away?

Clio Crespy: Thanks, Francisco. Zach, yes, so our synergy and our cost reduction journey, if you look at that graph that we shared with you all, since 2023, we’ve delivered $300 million of structural cost reductions, and those are primarily driven by the Aera integration. That was around $235 million, and we achieved those ahead of schedule. What’s most important is that those savings are durable. They came from our field level operating improvements from the infrastructure rationalization exercise, our workforce consolidation, of course, the centralized procurement as well as our system integration. So these are really permanent changes to how we operate. They’re not service cost deflation or temporary timing benefits here.

It’s also worth noting that these savings were realized during a period of permitting constraints and industry cost inflation. So we’ve already been tested here. We’ve tested those in a challenging operating environment, which reinforces the durability point. Scale matters in our business. We’re now operating at a scale where procurement, infrastructure and field operations, those can be optimized in ways that were not available to us historically. And that industrial scale advantage it’s really now embedded in our cost structure. So as a result of all these actions we took, our current run rate total operating expenses, those are $550 million lower than the pro forma premerger baseline. And that’s not incremental optimization. That really is a structural reset of our cost base.

And Francisco mentioned the path. We’re on that path. We’re targeting $450 million of cumulative savings by year-end ’28. And I’ll add that that’s a meaningful portion for CRC. That’s getting close to 10% of our market cap in 5 years. So we are really well on our way to execute that target of $0.5 billion. And if you look at it, that’s 80% already executed or action. So excited to see the new and improved CRC.

Zachary Parham: For my follow-up, I wanted to ask on how you’re thinking about capital allocation over the longer term. You mentioned getting back to a steady state in 2027. But how do you think about maintenance versus potential production growth and balancing those versus free cash flow generation?

Francisco Leon: Yes, Zach. So we’re certainly dealing with a lot of volatility in the commodity prices, and we want to have a disciplined outlook to growth. That’s whether the markets are running hard or pulling back. We’re really building this company that works well throughout the cycle, right? It’s a commodity business. You’ll have those ups and downs, but we — predictable returns, predictable cash flows is what we’re after. So we’re really trying to stay very flexible. And the way we’re thinking about the year, we’ve been running 4 rigs since the beginning of the year. we’re thinking about what incremental activity would be that ultimately gets us to from about a 2% year of — entry to exit decline to more of a flat steady state, and that’s going to require more activity.

So we’ve been thinking about that incremental FIB rig. Certainly, there’s a lot of things to think about what’s happening in the geopolitics today, but we have a lot of flexibility to increase activity. And that comes not only from the running room that we talked about, the inventory, the projects are there. We also control 100% of all of our fields we operate, all of them and we have all the services and rigs that we need for the year. So it’s really a matter of timing and when can we get delivered those high returns for the investor. We invest to make high returns, not invest to keep production flat, right? So if we see high returns, it’s the opportunity to lean in. Maybe I’ll let Clio talk about more of the go-forward plan in 2027 and beyond.

Clio Crespy: Yes. Thanks, Francisco. So when we look at beyond ’26, we’ve outlined what a maintenance framework would look like. That’s holding production flat at the ’26 exit rate, and that would require 7 rigs and about $485 million of D&C and workover capital. So that’s approximately 20% less capital than legacy CRC needed to sustain a similar production level and a real meaningful improvement there. And at that activity level, our oil and gas breakeven is about $58 Brent, or $54 WTI. If you look at it on a fully burdened corporate basis, so that includes power, carbon management, corporate costs and the dividend, that corporate breakeven is roughly $60 Brent. And that’s an important point. A $60 Brent breakeven reflects a structurally more resilient business, one that can sustain flat production, fund the dividend and preserve balance sheet strength.

And of course, above that level, we generate incremental free cash flow. One thing I’d like to add as well is operating within a maintenance framework, that doesn’t mean static economics. We continue to see opportunities to structurally lower our breakeven over time through the Berry integration, through incremental capital efficiency gains and also through portfolio high grading. So as those improvements take hold, the capital required to hold that production flat should decline. And our objective really remains straightforward. It’s durable cash flow, resilient margin and our sustainable returns through the cycle here. So we’re excited about the breakeven progress.

Operator: The next question comes from Kalei Akamine with Bank of America.

Kaleinoheaokealaula Akamine: My first question is on gas. So just kind of looking at the screen, very low natural gas in California is trending below hub. Wondering if low natural gas is a net benefit at the operating level, noting that you guys sell and consume natural gas. And as you prosecute this year’s drilling program, wondering if there’s going to be a gas production benefit that could emerge when that could help begin insulating operating costs, especially at the acquired assets?

Francisco Leon: Kalei, thanks for the question. So as a reminder, California is — we think about it as an energy island, very regional market. You see sometimes the movements of gas price in California that are in the same direction as Henry Hub, but they’re not really very well correlated. So ultimately, what you have to look at is the specific California dynamics. First of all, we bring, we import a lot of our gas, a lot of it from Texas and the Rockies. So we’re literally at the end of the pipe or price takers as a state. So then you look at what are the underground conditions and what’s local demand, what’s the storage, what’s the capacity on the gas pipes moving gas West. And right now, those storage levels, in particular, are very — are elevated.

They’re high. The weather, there hasn’t — there’s been kind of tempered weather for the last few weeks. So the build-out of hydro and battery continue to add and that puts pressure on natural gas. So that’s why you’re seeing a dip in those realizations. But as a reminder, it’s pretty obvious in days like today, but you have asymmetric risk. When demand exceeds the seasonal norms or where the infrastructure gets stretched or fails, California gas prices can spike dramatically, and that volatility tends to favor the producer. So we’ve taken obviously a lot of steps in terms of our hedging strategy to protect our gross margins. But the setup where oil prices are increasing and gas prices are decreasing is favorable. That oil to — gas-to-oil ratio ultimately means higher margins for our business, and we protect the consumption of that gas through hedging.

So right now, the focus is more on oil, but we will be looking at gas opportunities in the year. Part of our mix of projects this year has natural gas projects because this asymmetry in the market means that we need to be very well positioned when conditions shift, and we believe they will be shifting in the near term.

Kaleinoheaokealaula Akamine: Got it. I appreciate that. My very quick follow-up is on Elk Hills power. That business receives a benefit from the state’s resource adequacy program. Can you simply quantify the benefit for ’26?

Francisco Leon: Yes. Resource adequacy, the capacity programs in the state, very highly, highly regulated from the procurement of power. So as the state started making their capacity requirements for 2026, they came in well below expectations. So pricing pullback. I think we’ve been signaling this since last November, where we can see where the contracts were heading. We really had a period where we — we had really big spikes and now we’re seeing much more of a normalized level as historical — much more historical in a lot of ways. So what we’re seeing for this year is a $25 million to $50 million annually RA under current conditions. We’re looking to, as we discussed, layer in contract the revenue to the PPA. But we’re well set up, right.

Ultimately, there’s a lot of things that could happen in a market like California. There could be plant retirements, demand that is beyond expectations, which is likely the case. You can have some reserve margin adjustment. We don’t underwrite those scenarios in our base case, but they’re real optionality over time. It’s going to be really interesting to watch. California grid is now very heavy on solar and wind that just have never been tested under stress conditions. If those resources underperform during extreme heat or there’s a failure somewhere in the system, the value of reliable dispatchable capacity could shift quickly. So we’re well positioned for the RA market if that were to happen.

Operator: The next question comes from Josh Silverstein with UBS.

Joshua Silverstein: I wanted to ask on the Uinta Basin. Now that you have it in-house, how are you thinking about the asset? Is it viewed as noncore or something you want to develop? And then maybe just a little bit more details on it, higher or lower cost relative to the California operations and what inventory depth looks like?

Francisco Leon: Thanks, Josh. So yes, [ Ute ] came through our acquisition and merger with Berry, oil-weighted, a lot of stacked reservoir as well. We like the position. It’s 100,000 contiguous net acreage. The Berry drilled 4 horizontals in the Uteland Butte that are all tracking around type curve, which gives us conviction around the repeatability and technical merit of the asset. We also see some promising benches, the Castle Peak and the Wasatch to name 2 incremental areas of interest. So it’s a nice asset. We see it strategically as a high-quality option. Right now, we’re focusing on optimization, well designed ways where as we take control of the assets where we can improve the capital efficiency. Ultimately, though, it will have to — in order for us to scale it, it has to compete with full cycle returns across the broader portfolio and against the California assets.

And that’s a really high bar. As we mentioned, we see about 4x money on invested capital for California. So Uinta will have to compete for capital in that way. So we’ll continue to evaluate it. We’ve only been operating it for a couple of months and whether that’s scaling it through development or partnership, or other value-creating pads, we don’t know yet, but we’re keeping all options on the table. And ultimately, it’s going to be returns and value creation that will guide the decision.

Joshua Silverstein: Got it. And then I also wanted to ask just on the Huntington Beach asset. Any update there in terms of how you guys are thinking about kind of optimizing the value of that?

Francisco Leon: Yes, 90 acres of Beach run property in one of the most expensive ZIP codes in California. So it’s an asset that we continue to advance. It’s exciting to own this asset in the portfolio, and we’re executing our plan. A lot of the plugging and abandonment well it’s been happening as we continue to produce, it’s a cash flow positive asset. So we are effectively paying the P&A with that production. We have made good progress in terms of working with the City of Huntington Beach, advancing the entitlements. We expect formal review in late 2026. And then that will be followed by approximately 2 years of review by the Coastal Commission. Once the entitlement is approved by the City and Coastal Commission, then we have — we will do the site redevelopment and remediation.

We expect to have about 80 wells, active wells remaining to plug at that stage. And we will look to — ultimately, we’re looking to optimize value. And we see, if you look at comparables and the scarcity of land and high-quality development areas in the state, we see the — some of the comparables going higher. So we like where we sit, and we will go through the process, obviously, look for ways to accelerate the process to the extent that we can. But we’ll monetize it when we see the value, right? And right now, the value as we abandon and entitle shifts to the developer, we would like more of the value to accrue to our shareholders. So we’re working diligently and putting things forward, but we see a lot of significant value creation opportunity in a few years related to this asset base.

Operator: I understand there is time for one last questioner. We have Nate Pendleton with Texas Capital.

Nathaniel Pendleton: Congrats on the strong quarter. Referencing Slide 10 and the potential storage of up to 1 billion tons of CO2 with the 350 submitted for CTV VII and more in the works. How do you think about the time line to develop the additional projects to reach that 1 billion ton marker? And then should we think about that total number representing total potential or just what the team has derisked at this point?

Francisco Leon: Nate, thanks for the question. Yes, our CTV business continues to be a really bright spot in terms of the way the state is progressing through their net 0 targets. And we’re seeing not only we talked a lot about today about the data center opportunity and how that part of the business can unlock CTV. The one area we didn’t highlight today is through what we call what is called the RCPPP, which is the reliable and clean procurement of the state. There’s advanced discussions happening and a lot of advocacy trying to add carbon capture into the mix for procurement. So whether it’s data centers or the state making it a requirement, we think CCS will be the solution for the state, and that will bring the market forward.

So it’s going to be important to watch both progress this year. We have 2 very, very large markets, one behind the meter, one in front of the meter that we’re going to tap. And if that were all to come into fruition, we would — that would fill up every single reservoir that we have. So we continue to work on incremental capacity and bringing those permits forward. And that’s been a core strength of our team is to advance those permits better than anyone else can in the state. So we’re well situated for those market updates and for that market to unfold, and we think this is the year where it all comes together.

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

Francisco Leon: Thank you so much for joining us today. We really look forward to connecting with many of you in the coming weeks. Thanks, and have a great day.

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