Good day, and welcome to the California Resources Corporation Fourth Quarter 2025 Conference Call. 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.

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.

Thank you, Daniel, and good morning, everyone. I'll begin with our 2025 results, then highlight what makes CRC unique today, including our 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 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 $1.6 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, while maintaining the flexibility to invest through commodity cycles. As we enter 2026, CRC 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 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 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 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 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 derisks 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 provides a structural advantage as demand grows 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 to the long-term? What defines us is the durability of inventory and returns. We're 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 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.

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 enhanced 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 the midpoint of our guidance, with oil representing roughly 81% of volumes. 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 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.

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 costs, 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.

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

I was hoping 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.

Scott, thanks for the question. Really appreciate you leading with this question. It's important that we convey the potential of the business. 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 flows. It's an asset base 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're building line of sight into 2027. Now that permitting is back to normal cadence, it allows us to focus on the resource. We grew our 1P reserves, achieving a 350% reserve replacement ratio on the back of the permits coming in, stronger-than-expected base decline, and the Berry acquisition. 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 have 23 years of inventory on a 2P basis in our disclosure. We operate about four of the largest oil fields in the U.S., and you can add three more, so seven, which have each well in place that exceeds 3 billion barrels of oil in place. These fields have been producing for decades and have many, many decades ahead. Recovery factors of over 40% on waterfloods and 75% on steamfloods. This gives you a sense of how much resource remains to be captured. We also have very low subsurface risk that makes capital allocation very predictable. We have a lot of well control across all our acreage. Much of our production is about 2,000 feet deep, so very shallow. We have a lot of data that helps us derisk every dollar we deploy. A lot of the activity we have on new wells is infill drilling, so low geological risk. 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'd like to highlight that 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, and an average working interest of 89%, which means really strong netback. Belridge is probably the best example; we look at Belridge in terms of development as we saw Elk Hills about 20 years ago. So we have an extremely long runway with low risk. One highlight of Belridge is it's less than a 5% royalty burden, yielding amazing netbacks. We're really excited about the setup we have for the company going forward. I think you had a second question?

Yes, absolutely. I appreciate the context. Regarding your 2026 program, it looks like 4Q flattens. I'm just wondering if that is a good forward rate to utilize for building the maintenance of '27? And also maybe a little bit about the capital efficiency, which appears to have improved as well.

Yes, we're extremely proud of the work the team has done to improve capital efficiency. We've seen tremendous progress year-over-year and continue to work on it. I'll turn it to Clio to highlight some of the improvements around efficiency and the well mix.

Thanks, Francisco. Scott, yes, so on our '26 program, it's really designed to materially reduce our corporate decline to roughly 2%. As you alluded, this equates to a 0.5% glide path quarter-over-quarter, effectively maintaining flat production throughout the year while generating substantial free cash flow. We're operating four rigs and 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 low-risk development, focusing on PUD inventory. We have roughly two-thirds of our activity on sidetracks and one-third on new wells, supplemented by a very robust workover program. The sequencing here is deliberate, with more sidetracks and workovers in the first half, then transitioning into new wells as permit inventory builds throughout the year. A couple of points: we're reinvesting less than 50% of cash flow, maintaining our leverage around 1x. You're really seeing disciplined capital allocation at work. Regarding capital efficiency, we analyze it through two lenses: project-level returns and corporate capital intensity. Starting with project-level returns, our '26 program is highly competitive on a stand-alone basis at $9 per Boe of development cost. The program generates just shy of a 4x multiple on invested capital, mid-40% returns at $65 Brent, and a roughly 3-year payout. The portfolio is also oil-weighted, around 90%, supporting strong cash margins and durable economics across the cycle. These metrics reflect the quality of our inventory Francisco highlighted and the structural improvements captured over the past several years. At the corporate level, the impact of the Berry integration is clear. Notably, we're 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 a 2% decline without an increase in our capital or rig count compared to our earlier November guide, which was built in a much smaller footprint assuming no Berry. This demonstrates our improved capital efficiency and integration synergies. We're generating strong marginal returns on new capital and lowering the capital required to sustain the broader base. This combination supports our durable free cash flow generation.

The next question comes from Betty Jiang with Barclays.

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 more broadly, as the CCS business is finally moving into execution, what are the key milestones you are targeting this year from a business development or permitting perspective?

Betty, thanks for the compliments. In terms of our CCS business, we're making good progress and are near the finish line to deliver a fully integrated end-to-end capture to storage solution. Construction is complete, and commissioning and final approvals are underway. We successfully captured our first CO2 from the plant through the amine system and are working closely with the EPA through final operational readiness and compliance steps. We're excited; this first injection is a significant derisking of the CCS business model and instills confidence in the business we're building. As market adoption continues, we aim to decarbonize gas and electrons in California, which we believe wins the day. We have a state requirement under cap and invest to decarbonize by 2045, and we're bringing a market solution that may differ from what's happening elsewhere in the country. We're seeing progress from our team regarding permits; we just filed for Carbon TerraVault VII with the EPA, adding another 27 million tons of capacity adjacent to CTV I, bringing the hub concept into the Elk Hills area to accommodate growth. 2026 will also be a year where we see many permits from two to three years ago beginning to come in the form of draft permits. Overall, we're excited about our progress, and 2026 is a big year for us.

Great. For my follow-up on the power to CCS opportunity, on Slide 11, you mentioned the hub concept with multiple power plants over growing carbon storage. Can you expand on what market conditions you need to see for this opportunity to crystallize for CRC?

Yes, Betty, it's evident now that the electricity sector will lead decarbonization efforts, particularly in California, where meeting decarbonization goals is critical for building data centers and sourcing incremental demand. We missed out on the first wave of data center growth due to high power prices, but we're enthusiastic about the second wave focusing on inference and edge compute where proximity to users is crucial. Elk Hills power plant, Carbon TerraVault I and VII are positioned at the intersection of two attractive use cases for content and virtual gaming in areas like Los Angeles and Las Vegas. We've made progress on the power now concept to allow data centers to scale and have partnered with power plants around our sites, highlighted through a portfolio of 2 gigawatts that can ultimately scale the data center. We've also been advancing our Land Now concept, which includes permitted and powered land, collaborating with a leading data center developer. As permits come into view, interest from hyperscalers wishing to establish a foothold in California is increasing. The injection of CTV I will also signify a major milestone, allowing us to transition CCS from concept to a clean, hourly matched energy offering during PPA negotiations, setting us apart from competitors reliant solely on renewables and batteries. So, integrating all these elements, we're focused on creating durable contracted cash flows and unlocking shareholder value.

The next question comes from Zach Parham with JPMorgan.

I wanted to ask about cost reductions and your confidence in Berry synergy capture. The slide deck shows incremental cost reductions extending to the 2027-2028 timeframe. Can you give us more color on what’s causing these continued reductions?

Thanks, Zach. Really appreciate the question. We're applying the same integration playbook to Berry as we did with Aera. We're simplifying, standardizing, and integrating the business. As we've announced, we're targeting about $80 million to $90 million of synergies, and we were able to close the Berry merger earlier than expected, so we're in full execution mode. Focus areas include field efficiencies, overhead redundancies, leverage on supply chain, and optimizing well services through our C&J company. These manageable, high-confidence levers will aid in achieving those targets. We still feel good about $80 million to $90 million, but what's particularly impressive is that we're on a glide path toward approximately $0.5 billion of cumulative structural savings from both deals. I'll let Clio discuss some specifics on this.

Thanks, Francisco. Zach, our synergy and cost reduction journey, according to the graph shared with you all, shows that since 2023, we've delivered $300 million of structural cost reductions, primarily driven by the Aera integration totaling around $235 million, ahead of schedule. Importantly, these savings are durable; they result from operational improvements, infrastructure rationalization, workforce consolidation, and centralized procurement, representing permanent changes to our operations rather than temporary benefits. Moreover, these savings were real during a period of permitting constraints and industry inflation, strengthening their durability. Scale matters in our business: we're now operating at a scale where optimization in procurement, infrastructure, and field operations is achievable in ways previously unavailable. Thus far, our current run rate total operating expenses are $550 million lower than the pre-merger baseline, marking a structural reset of our costs. We are targeting $450 million of cumulative savings by year-end '28, equivalent to almost 10% of our market cap in 5 years. We're really on track to execute this target of $0.5 billion in savings, with over 80% already actioned, so we're excited about the progress we've made.

For my follow-up, on capital allocation over the longer term, how do you balance maintenance versus potential production growth and free cash flow generation?

Yes, Zach. We're navigating significant volatility in commodity prices, and our goal is to maintain a disciplined growth outlook whether markets are tightening or easing. We're building this company to perform well throughout cycles, focusing on predictable returns and cash flows. We're flexible in our operations; we've been running four rigs since the year began and contemplating what incremental activity could eventually enable us to maintain steady production. We're considering an additional rig, but we are continuously evaluating the geopolitical landscape. However, we have substantial flexibility to ramp up activities, as we control 100% of our operated fields and all necessary services and rigs for the year. Timing is key, and we expect to deliver high returns for our investors, not merely maintain production. I'll let Clio expand on plans for 2027 and beyond.

Thanks, Francisco. Beyond 2026, we've outlined what a maintenance framework would look like, holding production flat at the '26 exit rate, requiring 7 rigs and approximately $485 million of D&C and workover capital. This represents around 20% less capital than prior operations needed to maintain similar production levels—improving efficiency. At this activity level, our oil and gas breakeven stands at about $58 Brent, or $54 WTI. On a fully loaded corporate basis, including power, carbon management, corporate costs, and the dividend, the corporate breakeven is roughly $60 Brent. This reflects a more resilient business structure capable of sustaining flat production, funding dividends, and preserving balance sheet strength. At higher prices, we generate incremental free cash flow. Additionally, operating within a maintenance framework does not prevent us from discovering opportunities for ongoing lower breakeven costs through Berry integration, capital efficiency gains, or portfolio refinement. As we implement these improvements, the capital needed to maintain flat production should continue its downward trend, with our objective remaining centered on durable cash flow, resilient margins, and sustainable returns through varying cycles.

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

My first question is on gas. California natural gas is currently trending below the hub. Is low natural gas favorable for your operations, considering that you sell and consume gas? As you pursue this year’s drilling program, is there potential gas production that could help mitigate operational costs, particularly at the acquired assets?

Kalei, thank you for your question. California is considered an energy island with regional market peculiarities. Movements in California gas prices, while sometimes mimicking Henry Hub, don't usually align well with it. The specifics of California's dynamics reveal that we import much of our gas from Texas and the Rockies, making us price takers in the state. Local demand, storage considerations, and capacity on gas pipelines are vital in shaping the prices. Currently, gas prices are dipping due to elevated storage and tempered weather. Hydro and battery growth continues to apply pressure on natural gas prices. However, as we've taken significant steps regarding hedging strategies to safeguard our margins, the current combination of increasing oil prices and decreasing gas prices is favorable. We aim for high margins while ensuring gas consumption through effective hedges. While we prioritize oil, opportunities for gas won't be overlooked, and our project mix this year includes natural gas projects to strategically position ourselves as market conditions shift.

I appreciate your response. My quick follow-up is on Elk Hills power. Can you quantify the benefit from the state's resource adequacy program for '26?

Yes. The resource adequacy capacity programs in our state are highly regulated. As the state planned its capacity requirements for 2026, they came in significantly lower than anticipated, leading to a pricing pullback. We indicated last November that we foresaw where contracts were heading. We now expect for this year a $25 million to $50 million annual resource adequacy benefit under current conditions. We'll be layering contract revenue to the PPA. Overall, we're positioned well; many outcomes could impact California's market. Plant retirements and demand exceeding expectations could enhance our resource adequacy value, although we don't underwrite these factors in our base case. This situation presents optionality; the California grid, heavily reliant on solar and wind, may face stress conditions. If these renewable resources underperform amid extreme conditions, the demand for reliable, dispatchable capacity could shift rapidly, positioning us well for the potential market dynamics.

The next question comes from Josh Silverstein with UBS.

I wanted to ask about the Uinta Basin. Since you have it in-house, how are you evaluating this asset? Is it deemed non-core or a potential development target? Additionally, can you provide insights into cost and inventory depth?

Thanks, Josh. The Uinta Basin was acquired through our merger with Berry, featuring oil-weighted assets and abundant stacked reservoirs. We value the position, operating 100,000 contiguous net acres. Berry drilled four horizontals in the Uteland Butte, all tracking near-type curves, affirming our confidence in the asset's technical merits. We also see potential in the Castle Peak and Wasatch benches as additional areas of interest. It's a solid asset. Currently, we’re focused on optimizing capital efficiency as we gain operational control. Ultimately, for us to scale Uinta, it needs to compete with full-cycle returns across our portfolio, particularly our California assets, which currently generates around 4x returns on invested capital. We'll continue to assess options for Uinta development—whether through partnerships or other value initiatives—and our decisions will hinge on returns and value creation. Regarding Huntington Beach, we have about 90 acres in a high-value California ZIP code, which is an exciting asset for us. We're advancing our plan, conducting plugging and abandonment operations while maintaining cash flow positivity from the asset, effectively funding P&A activities. We've progressed in collaborating with the City of Huntington Beach to advance entitlements, expecting formal review in late 2026. Following that, we anticipate about two years of review by the Coastal Commission. Once the City and Coastal Commission approve the entitlements, we’ll move to site redevelopment and remediation. We foresee around 80 active wells remaining to plug by that stage. Our goal is to enhance the asset's value: high-land scarcity and quality development areas in the state support increasing comparables. We feel confident about where we are and intend to utilize all avenues to optimize the process and accelerate delivery to our shareholders.

I understand there's time for one last question. We have Nate Pendleton with Texas Capital.

Congrats on the strong quarter. Referring to Slide 10, regarding the potential storage of up to 1 billion tons of CO2 with the 350 submitted for Carbon TerraVault VII and other projects upcoming, what is your timeline for developing these additional projects to reach that 1 billion ton marker? Should we consider that total number a target or just your current derisked capacity?

Nate, thanks for the question. Our CTV business remains pivotal as the state progresses toward net-zero targets. We're not only discussing data center opportunities which could unlock CTV; but our focus is also on physical and legislative discussions that press for carbon capture in procurement strategies. Thus, we're positioned well for both markets. If this culmination occurs, we'd fill all our reservoirs. We're continuing to work on capacity enhancement while progressing our permits—advancing quicker than anyone else in the state is a core strength. We're well-prepared for market updates, and we believe 2026 will see those developments come together. Thank you so much for joining us today. We look forward to connecting with many of you in the coming weeks. Thanks, and have a great day.

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