California Resources (CRC) Earnings Transcript

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DATE

Monday, March 2, 2026 at 1 p.m. ET

CALL PARTICIPANTS

• Chief Executive Officer — Francisco Leon
• Chief Financial Officer — Clio Crespy

TAKEAWAYS

• Adjusted EBITDAX -- $251,000,000 in the quarter and $1,250,000,000 for the full year, with the annual figure the highest since 2021.
• Free Cash Flow -- Reached $115,000,000 for the quarter and $543,000,000 for the year, reflecting a record since 2021.
• Net Production -- Averaged 137,000 barrels of oil equivalent per day in the quarter and grew to 138,000 barrels per day for the year, a 25% increase.
• Oil Realizations -- Achieved 97% of Brent pricing before hedges in the quarter.
• Capital Spending -- Totaled $120,000,000 in the quarter and $322,000,000 for the year, all within guidance.
• Shareholder Returns -- Returned nearly $1,600,000,000 since 2021 and in the latest year, 94% of free cash flow distributed via dividends and share buybacks.
• Share Repurchase Program -- Board approved a $430,000,000 increase and extended authorization through 2027; remaining buyback capacity now stands near $600,000,000.
• Leverage and Liquidity -- Ended the year at 1.0x leverage and $1,400,000,000 of total liquidity.
• Berry Merger Synergies -- On track to capture $80,000,000–$90,000,000 through integration initiatives; $300,000,000 of structural cost reductions since 2023, mostly from synergy with prior deals.
• 2P Inventory Disclosure -- Reported nearly 1,200,000,000 barrels of oil equivalent in 2P reserves, representing 23 years of inventory at current production rates.
• Production Outlook -- 2026 guide projects a 12% increase to 155,000 barrels per day, with oil composing roughly 81% of total volume.
• Oil Hedges -- Approximately two-thirds of anticipated 2026 oil volumes hedged at $65 Brent.
• Drilling and Capital Plan -- D&C and workover capital for 2026 planned at $280,000,000–$300,000,000 with a four-rig program.
• Corporate Maintenance Breakeven -- "Mid-$50s WTI" including all business segments, support, and hedges; upstream-only breakeven cited as "low to mid-$50s WTI."
• CCS Project Status -- Construction finished for California’s first commercial-scale CCS at Elk Hills, now in commissioning and testing; first CO2 captured, final EPA approval for injection pending.
• Resource Adequacy Payments -- For 2026, resource adequacy revenue projected at $25,000,000–$50,000,000, reflecting current market tightening.
• Permitting -- Majority of required permits secured to execute 2026 capital program; cadence of approvals returned to normal, expanding planning flexibility.

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RISKS

• Resource adequacy revenues decreased as "So as the state started making their capacity requirements for 2026, they came in well below expectations. So pricing pulled back. I think we have been signaling this since last November, where we could see where the contracts were heading. We really had a period where we had really big spikes, and now we are seeing much more of a normalized level, much more historical in a lot of ways."

SUMMARY

California Resources Corporation (NYSE:CRC) reported record operational and financial metrics, citing the Berry merger as a major driver of scale, structural cost improvements, and capital efficiency. Management attributed 23 years of 2P inventory and a low-decline production profile to enhanced asset quality and permitting recovery, asserting this underpins both future value creation and durable free cash flow. The company announced completion and start of commissioning for California’s first commercial-scale CCS project at Elk Hills, marking a key transition from concept to execution and suggesting significant potential for low-carbon solutions as the market develops. Capital deployment will shift in 2026 toward high-return reinvestment opportunities, as increased permitting enables more drilling, while shareholder returns remain anchored by a durable dividend and expanded buyback authorization. Regulatory progress on permits and CCS, along with integration cost savings, equip the balance sheet for resilience as the company targets a four-rig development and oil production materially hedged at $65 Brent.

• The board extended its share repurchase authorization through 2027, giving management the discretion to allocate excess capital as market conditions evolve.
• Discussion revealed that future production maintenance at 2026 exit rates would require seven rigs and $485,000,000 in annual D&C and workover capital from 2027 forward.
• Expansion of CCS storage capacity is proceeding, including the filing of CTV7 for a further 27,000,000 tons of permitted storage contiguous to Elk Hills infrastructure.
• The Huntington Beach asset’s entitlement process will not begin formal city review until late 2026, with at least two further years of regulatory review before potential site redevelopment and monetization.
• Management noted a "50% reserve replacement ratio" on 1P reserves and a current 1P value of $9,000,000,000 at SEC prices, enabled by improved base declines and the Berry transaction.
• The Uinta Basin asset acquired via Berry offers technical promise but will have to compete with core California projects due to higher return thresholds; capital allocation decisions remain pending based on relative returns.

INDUSTRY GLOSSARY

• 2P Reserves: The sum of proved plus probable oil and gas reserves, used as an indicator of long-term resource base and development potential.
• CCS (Carbon Capture and Storage): A process for capturing CO2 emissions from industrial sources and storing them underground to reduce atmospheric greenhouse gases.
• Resource Adequacy Payments: Compensation utilities pay to generators for maintaining available capacity to ensure grid reliability, regardless of energy dispatched.
• PUD (Proved Undeveloped) Inventory: Reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required.
• D&C (Drilling and Completions) Capital: Investment directed at well drilling and completion activities for hydrocarbon recovery.

Full Conference Call Transcript

Francisco Leon: Thank you, Daniel, and good morning, everyone. I will begin with our 2025 results, then highlight what differences you are seeing today, including our unique position in California's energy and decarbonization landscape, and how that translates into long-term value creation. I will 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 returned 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 $1,600,000,000 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, maintaining the flexibility to invest through the commodity cycles. As we enter 2026, California Resources Corporation is 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 California Resources Corporation today. First, 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 at lower risk than shale-focused peers. Our expanded 2P disclosure of nearly 1,200,000,000 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 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 ERA 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 the resumption of new drill permitting and the steady flow of approvals through the system represent a step change from where we have 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 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 California Resources Corporation. We are 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 Teravolt has moved from concept to execution. Construction is complete on California's first commercial-scale CCS project at Elk Hills, and we are 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 this step in the process materially de-risks 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 state 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 are not focused on speed; we are focused on getting the fundamentals right, 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 California Resources Corporation as we look ahead for the long term? What defines us is durability of inventory and returns. We are investing in 2026 from a position of strength, with 2027 marking the point where we return 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 Teravolt, 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 peers.

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 will 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 California Resources Corporation. 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 $251,000,000 and free cash flow of $115,000,000, 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 $1,250,000,000 of adjusted EBITDAX and $543,000,000 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 $120,000,000 within guidance, bringing full-year capital deployment to $322,000,000.

Capital allocation remained returns-focused throughout the year. In a permitting-constrained environment, we directed investment 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 enhanced per-share cash flow. The Board recently approved a $430,000,000 increase to our share repurchase authorization and extended the program through 2027, bringing remaining capacity to approximately $600,000,000. 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 1.0x leverage with total liquidity of $1,400,000,000. During the year, we completed a refinancing transaction associated with the Berry merger, redeemed our 2026 senior notes, expanded lender commitments, and received improved outlook 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 $1,000,000,000 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 $450,000,000. Drilling, completions, and workover capital is projected at the $280,000,000 to $300,000,000 range, supporting a four-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 the midpoint of our guide, with oil representing roughly 81% of volume. Two-thirds of our expected oil production is hedged at $65 Brent, providing meaningful cash flow protection. We enter 2026 with a stronger balance sheet, an expanded inventory of high-return projects, and improved visibility into sustainable production and cash flow growth. With that, I will turn it back to Francisco for closing comments.

Francisco Leon: As we look to 2026 and beyond, our priorities are clear. We are 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 California Resources Corporation’s future. Carbon Teravolt 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. California Resources Corporation 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 Californians’ demand for secure, lower-carbon energy evolves, we see our integrated model as part of the solution. I will now turn the call over to the Operator to begin the Q&A.

Operator: We will now open for questions. At this time, we will pause momentarily. The first question comes from Scott Hanold with RBC Capital Markets. Please go ahead.

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

Francisco Leon: Hey, Scott. Thanks for the question. We really appreciate you leading with this question. Important that we convey the potential of the business. I have a few things to say. We have a great foundation that is well-known—conventional assets with low declines, repeatable inventory, actually have really good rock that actually flows. It is an asset base that has been built to outperform through any cycle. But really three things to highlight. In terms of the runway, the inventory, as I said in my remarks, we have permits in hand to execute 2026. We are 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—50% 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 is about $9,000,000,000 at SEC prices. But what really stands out is the running room beyond that. We said we have 23 years of inventory on the 2P basis. On the 2P basis, our disclosure, we operate about four of the largest oil fields in the U.S. You can add three more, so seven. You have each oil in place that exceeds 3,000,000,000 barrels of oil in place. These are fields that have been producing for decades and have many, many decades ahead.

Recovery factors of 40% plus in waterfloods, 75% plus on steamfloods. And that just gives you a sense of how much resource remains to be captured. But on top of the resource, we also have very low surface 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 de-risk every dollar that we deploy. A lot of the activity that we have on new wells is infill drilling, so low geological risk, and this 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 is truly an opportunity set with stacked optionality and returns. We have thousands of feet of stacked pay across multiple producing horizons, 2,000,000 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 for Belridge is it is 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: Yeah. Yeah. Absolutely. Appreciate the context. And just staying on kind of a similar theme, if you step back and think about the 2026 program, it looks like 4Q flattens. Just wondering, is that a good forward rate to utilize for that building to maintenance 2027, and also maybe a little bit about the capital efficiency that appears to have improved as well? So any color there, and I know if it is the type of wells you are drilling or what other factors might have helped the capital efficiency?

Francisco Leon: Yeah. We are extremely proud of the work the team has done to improve the capital efficiency. We have seen tremendous progress year-over-year and continue to work on it. I will turn it to Clio to give some of the highlights around efficiency and the mix.

Clio Crespy: Thanks, Francisco, and hi, Scott. Yes. On our 2026 program, it is really designed to materially reduce our corporate net decline to roughly 2%. So as you alluded, it really equates to a 0.5% glide path quarter-over-quarter. That is effectively flat production throughout the year while generating substantial free cash flow. And so we are operating four rigs. We are deploying $280,000,000 to $300,000,000 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 is really focused on PUD inventory. We have roughly two-thirds of activity on sidetracks and one-third on new wells. That is 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 are reinvesting less than 50% of cash flow. We are maintaining our leverage around 1.0x. You are really seeing disciplined capital allocation at work here. And you were asking, Scott, around our capital efficiency. We will think about it through two lenses—on project-level returns, but also on corporate capital intensity. If I start with our project-level returns, our 2026 program is highly competitive on a standalone basis. At $9 per BOE of development cost, the program generates just shy of 4.0x multiple on invested capital.

It generates mid-40% returns at $65 Brent and roughly a three-year payout. The portfolio is also oil-weighted—it is 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 have 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 is most notable is that we are delivering this very low decline on a materially larger portfolio without increasing our structural capital intensity.

We absorbed 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 is a meaningful demonstration of our improved capital efficiency and our integration synergies. We are generating those strong marginal returns on our new capital, and we are 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. Please go ahead.

Betty Jiang: Hello. Thank you for taking my question, and 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 this 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: Hey, Betty. Thanks for the compliments. 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, running it through the immune system, and we are working closely with the EPA through the final operational readiness and compliance steps. We are excited. This first injection is really a big de-risking of the CCS business model and really brings a lot of confidence to the business that we are building.

As we wait for market adoption—and there are many moving parts to it, but it is coming quickly—being able to have decarbonized molecules and electrons in California is where we think wins the day. We have a state requirement under cap-and-invest to 2045 to decarbonize. So we are bringing a market solution. They 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 CTV7 with the EPA. That is another 27,000,000 tons of capacity. It is adjacent to CTV1. So it is bringing the hub concept to 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 two to three 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 is a lot more to go, and excited to share the news as it comes, but 2026 is a big year for us.

Betty 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 are sitting on top of a growing carbon storage. Can you just expand on what you are seeing in the market on that front? What do we need to see from the market in terms of demand or other maturation to crystallize this opportunity for California Resources Corporation?

Francisco Leon: Yes, Betty. It is clear now that the industry that is going to lead the efforts to decarbonize is the electricity sector, the utility sector. And in California in particular, that is 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 having to be decarbonized. Now, we missed out in California on 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 are really excited about the second wave that is 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, CTV1, CTV7 now, are right at that intersection of two of the most attractive use cases for content, for virtual gaming. So whether that is Los Angeles or Las Vegas, these are where we see these very high-demand centers. So it is a very compelling outlook as we look out into the next few years.

The things that we have 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 have highlighted La Paloma, we have highlighted Sunrise, overall two gigawatts of portfolio that ultimately you can scale the data center to. A more recent update is we have been advancing what we call the Land Now concept, which is permitted and powered land.

We are working closely with a leading data center developer. We are 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 buildout, the hyperscalers—we are picking up more and more interest on people that want to establish a foothold into the California market. The injection of CTV1 is also an important milestone.

By being able to take CCS from a concept to a clean hourly match energy offering in a PPA negotiation really becomes a differentiator with the rest of the state that is solely relying on renewables and batteries. So putting all these things together—power at scale, site design and permitting, and a CCS de-risked 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 are making really good progress.

Operator: The next question comes from Benjamin Zachary Parham with JPMorgan. Please go ahead.

Benjamin Zachary Parham: Thanks for taking my question. First, just wanted to ask on cost reductions and your confidence in the Berry synergy capture. In the slide deck, you have got an interesting slide that shows incremental cost reductions going out to the 2027, 2028 timeframe. Can you just give us a little bit more color on what is driving those continued cost reductions?

Francisco Leon: Thanks, Zach. Really appreciate the question. We are applying the same integration playbook to Berry as we did with ERA. We are simplifying, we are standardizing, and integrating the business. As we have announced, we are targeting about $80,000,000 to $90,000,000 of synergies. We were able to close the Berry merger earlier than expected, so we are 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 we are going to be able to pull.

Ultimately, we still feel good about that $80,000,000 to $90,000,000. But what has been really impressive to watch as you step back—that is the point of the slide—is that we are on a glide path to about half a billion dollars of cumulative structural savings between our two deals. I am 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. Hi, Zach. Yes, on synergy and our cost reduction journey, if you look at that graph that we shared with you all, since 2023 we have delivered $300,000,000 of structural cost reductions, and those are primarily driven by ERA integration—that was around $235,000,000. And we achieved those ahead of schedule. What is most important is that those savings are durable. They came from our field-level operating improvements, from the infrastructure rationalization exercise, workforce consolidation, of course the centralized procurement as well as our system integration. So these are really permanent changes to how we operate. They are not service cost deflation or temporary timing benefits here.

It is also worth noting that these savings were realized during a period of permitting constraints and industry cost inflation. So we have already been tested here. We have tested those in a challenging operating environment, which reinforces the durability point. Scale matters in our business. We are 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 is 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 $550,000,000 lower than the pro forma pre-merger baseline. And that is not incremental optimization.

That really is a structural reset of our cost base. And Francisco mentioned the path—we are on that path. We are targeting $450,000,000 of cumulative savings by year-end 2028. And I will add that is a meaningful portion—getting close to 10% of our market cap in five years. So we are really well on our way to execute that target of half a billion dollars. And if you look at it, that is 80% already executed or actioned. So excited to see the new and improved California Resources Corporation.

Benjamin Zachary Parham: Thanks, Clio. Thanks, Francisco. My follow-up, I wanted to ask on how you are 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. We are certainly dealing with a lot of volatility in the commodity price, and we want to have a disciplined outlook to growth. That is whether the markets are running hard or pulling back. We are really building this company that works well throughout the cycle, right? It is a commodity business. You will have those ups and downs. Predictable returns, predictable cash flows is what we are after. So we are really trying to stay very flexible. The way we are thinking about the year, we have been running four rigs since the beginning of the year.

We are thinking about what incremental activity would be that ultimately gets us from about a 2% year-over entry-to-exit decline to more of a flat steady state, and that is going to require more activity. So we have been thinking about that incremental fifth rig. Certainly, there is a lot of things to think about—what is 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 is really a matter of timing and when can we deliver 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 is the opportunity to lean in. Maybe I will let Clio talk about more of the go-forward plan in 2027 and beyond.

Clio Crespy: Yes. Thanks, Francisco. When we look at beyond 2026, we have outlined what a maintenance framework would look like. That is holding production flat at the 2026 exit rate, and that would require seven rigs and about $485,000,000 of D&C and workover capital. That is approximately 20% less capital than legacy California Resources Corporation needed to sustain a similar production level—a real meaningful improvement there. And at that activity level, our oil and gas breakeven is about $58 Brent, or $54 WTI. You look at it on a fully burdened corporate basis—so that includes our carbon management, corporate costs, and the dividend—that corporate breakeven is roughly $60 Brent. And that is 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 would like to add as well is operating within a maintenance framework does not mean static economics. We continue to see opportunities to structurally lower our breakeven over time—through the Berry integration, through incremental capital efficiency gains, 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 is durable cash flow, resilient margin, and our sustainable returns through the cycle here.

So we are excited about the breakeven progress.

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

Kalei Akamine: Hey, good afternoon. My first question is on gas. So just kind of looking at the screen, daily natural gas in California is running below Hub. Wondering if low natural gas is a net benefit at the operating level, noting that you sell and consume natural gas. As you prosecute this year's drilling program, wondering if there is going to be a gas production benefit that could emerge when that could help begin insulating operating costs at the acquired assets?

Francisco Leon: Hey, Kalei. Thanks for the question. So it is 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. They are not really very well correlated. Ultimately what you have to look at is the specific California dynamics. First of all, we import a lot of our gas, a lot of it from Texas and the Rockies. We are literally at the end of the pipe—we are price takers as a state.

So then you look at what are the on-the-ground conditions—what is local demand, what is the storage, what is the capacity on the gas pipes moving gas west. And right now those storage levels in particular are elevated; they are high. The weather—there has been kind of temperate weather for the last few weeks. So the buildout of hydro and battery continue to add, and that puts pressure on natural gas. So that is why you are seeing a dip in those realizations. But as a reminder, it is pretty obvious in days like today, 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 have 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 the 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 we need to be very well positioned when conditions shift, and we believe they will be shifting in the near term.

Kalei 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 2026?

Francisco Leon: Yeah, resource adequacy, the capacity programs in the state—very 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 pulled back. I think we have been signaling this since last November, where we could see where the contracts were heading. We really had a period where we had really big spikes, and now we are seeing much more of a normalized level, much more historical in a lot of ways. So what we are seeing for this year is a $25,000,000 to $50,000,000 annual RA under current conditions. We are looking to, as we discussed, layer in contracted revenue to the PPA.

But we are well set up, right? Ultimately, there are 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 do not underwrite those scenarios in our base case. But they are real optionality over time. It is 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 is a failure somewhere in the system, the value of reliable, dispatchable capacity could shift quickly.

So we are well positioned for that RA market if that were to happen.

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

Josh Silverstein: Yes. Thanks, everyone. I wanted to follow up on the Uinta Basin. You know, now that you have it in house, how are you thinking about the asset? Is it viewed as non-core? I mean, do you want to develop? And then maybe just a little bit more details on it—higher or lower relative to the California operations and what inventory depth looks like? Thanks.

Francisco Leon: Thanks, Josh. So, yeah, you take it through our merger with Berry. Oil-weighted, a lot of stacked reservoir as well. We like the position. It is 100,000 contiguous net acreage. Berry drilled four horizontals in the Ute Buttes 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 two incremental areas of interest. So it is a nice asset. We see it strategically as high-quality option. Right now we are focusing on optimization, well design, ways where as we take control of the assets where we can improve the capital efficiency.

Ultimately though, 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 is a really high bar. As we mentioned, we see about 4.0x money on invested capital for California. So Uinta will have to compete for capital in that way. We will continue to evaluate it. We have only been operating it for a couple of months. And whether that is scaling it to development or partnership or other value-creating paths, we do not know yet, but we are keeping all on the table. And ultimately, it is going to be returns and value creation that will drive the decision.

Josh 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: Yeah. Ninety acres of beachfront property is one of the most expensive zip codes in California. So it is an asset that we continue to advance. It is exciting to own this asset in the portfolio, and we are executing our plan. A lot of the plugging and abandonment well has been happening as we continue to produce as 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 two years of review by the Coastal Commission.

Once the entitlement is approved by the City and Coastal Commission, then 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 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 some of the comparables going higher. So we like where we sit and go through the process, obviously look for ways to accelerate the process to the extent that we can. But we will 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 are working diligently and putting things forward, but we see a lot of significant value creation opportunity a few years out related to this asset base.

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

Nate Pendleton: Good morning and congrats on the strong quarter. Referencing Slide 10 and the potential storage of up to 1,000,000,000 tons of CO2 with the 350 submitted for CTV7 and more in the works, how do you think about the timeline to develop the additional projects to reach that 1,000,000,000-ton marker, and then should we think about that total number representing total potential or just what the team has de-risked at this point?

Francisco Leon: Hey, Nathan. Thanks for the question. Our CTV business continues to be a really bright spot in terms of the way the state is progressing through their net zero targets. And we are seeing not only—we talked a lot about today about the data center opportunity, how that part of the business can unlock CTV. The one area we did not highlight today is through what is called the RCPPP, which is the Reliable and Clean Procurement of the state. There is advanced discussions happening and a lot of advocacy trying to add carbon capture into the mix for procurement.

So whether it is 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 is going to be important to watch both progress this year. We have two very, very large markets—one behind the meter, one in front of the meter—now we are going to tap. And if that were all to come into fruition, 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 has been a core strength of our team, to advance those permits better than anyone else can in the state.

So we are well situated for those market updates and for that market to unfold, and think this is the year where it all comes together.

Operator: 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.

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