California Resources Corp Aktie

Good day, and welcome to the California Resources Corporation Third Quarter 2026 Conference Call. [Operator Instructions] Please note this event is being recorded.

I would now like to turn the conference over to Daniel Juck, Vice President of Investor Relations.

Good morning, and welcome to California Resources Corporation third quarter 2026 conference call. I hope you had a good chance to review our earnings materials, which include our non-GAAP reconciliation. Today's call includes forward-looking statements, and actual results may differ due to factors described in our earnings release and SEC filings. Following prepared remarks, our leadership team will be available to take your questions. As a reminder, please limit your questions to one primary and one follow-up.

I'll now turn the call over to Francisco.

Good morning, everyone and thanks for joining us. We delivered another strong quarter and took important steps to sharpen our California focus. We closed Crimson, signed a deal to sell the Uinta, announced a strategic collaboration with Bloom Energy, and raised our dividend again. As we head into year-end, we're pushing hard on the strategic priorities that will drive CRC's long-term value.

This morning, I want to highlight four areas. First, how our core E&P business is positioned to deliver long-term value. Second, the next chapter of CRC's strategic evolution from acquisition integration to optimization. Next, progress in our carbon and power businesses. And finally, our continued commitment to deliver strong shareholder returns. Clio will then take you through our results, our fourth quarter outlook, and some early thoughts on 2027.

First, we're investing in our core E&P business and integrating midstream infrastructure to expand market access and improve oil price realizations. We're running our largest drilling program in a decade and preparing for 2027 with most permit applications already submitted and a deep inventory of high-quality drilling opportunities to meet California's continued need for locally produced oil.

Our Crimson acquisition took our strategy one step further. With roughly 2,000 miles of pipeline plus Line 100 and its storage, we now control critical infrastructure running through the heart of our production. Our first priority is restarting the San Pablo Bay pipeline in the first quarter of 2027. Reopening northbound access will let us deliver California produced barrels to the highest value markets and strengthen flow assurance across our portfolio.

As we work to bring San Pablo Bay back online and restore flows through both our Northern and Southern systems, we expect our oil price realizations to improve towards normalized levels in the mid-90s. Longer term, the KLM corridor and its right of way could potentially anchor a statewide CO2 pipeline network, a key link to our carbon business.

Second, we're moving from integrating our acquisitions to optimizing how the combined company operates. Three years ago, we set out to build California's leading energy infrastructure company. Building scale came first, and our Aera and Berry mergers roughly doubled our production. These were timely deals made when oil prices were far lower than today.

Since 2023, adjusted EBITDAX has grown about 15% a year. Cash flow before working capital has nearly doubled, and we returned nearly 75% of our free cash flow to shareholders. Over the past 4 years, we have implemented more than $400 million of cumulative synergies and structural cost reductions across G&A, operating cost and capital, ahead of schedule and above our initial targets for both Aera and Berry.

With our integration work substantially complete, we're accelerating towards a new phase of our larger integrated enterprise, an organization-wide review centered on organic cost reductions over 2027 and 2028. Our goal is to lower our controllable cost base while maintaining safe, reliable operations, and our ability to grow production. We plan to further optimize our foundation by standardizing and connecting core systems, removing redundancies and using AI and digital tools to improve productivity. These actions will strengthen our leading energy infrastructure platform, and we plan to share updated targets during our next earnings call.

Third, power and carbon. Decarbonized power is a key constraint on economic growth in California. We continue to advance natural gas-fired generation with carbon capture and storage through the RCPPP. Today, we added another opportunity by signing an MOU with Bloom Energy to enable the development of 1 gigawatt or more of clean firm power using fuel cells with carbon capture and storage capabilities.

The collaboration will combine Bloom's fuel cell technology with CRC's land, natural gas infrastructure and carbon storage. We expect third-party power developers to own and finance the fuel cells. These efforts position us to meet growing demand for decarbonized power from utilities, community choice aggregators, and behind-the-meter data centers.

At our Golden Valley Technology Hub with Beacon, we submitted our application for the project permit to Kern County and remain on track to complete and submit technical studies for the related environmental review by year-end. The project will leverage our unique industrial acreage, existing infrastructure, and firm power from our Elk Hills plant to help meet rapidly growing demand from hyperscalers.

This demand raises our confidence in the commercial viability of the Golden Valley Technology Hub and the strength of our differentiated power solution. On the carbon side, we continue to expand CTV, one of the country's leading carbon management businesses. We submitted a new Class VI permit application to the EPA for our CTV VIII project, bringing our total submitted volumes to more than 400 million metric tons.

Our focus remains on delivering value to shareholders. As we invest in our E&P, power, and carbon businesses, we will continue to allocate capital with discipline, investing in organic growth and strategic opportunities, maintaining a strong balance sheet, growing our dividend and opportunistically buying back shares. Consistent with that approach, we increased our dividend by 4%, our fifth consecutive annual increase and continued buying back shares during the quarter, reflecting the exceptional value we see in CRC.

With that, I'll turn it over to Clio.

Thank you, Francisco and good morning. We delivered a strong third quarter with solid operating performance and cash generation ahead of expectations that supported both reinvestment and shareholder returns. But beyond the quarterly results, what stands out is how the underlying economics of our integrated business continue to improve.

We're generating more value from our existing assets, lowering the capital required to sustain production and creating additional opportunities to deploy capital at attractive returns. I will cover our results, our fourth quarter outlook, and the capital allocation priorities shaping our plans for 2027.

Net production averaged 152,000 barrels of oil equivalent per day, with oil representing 80% of the mix. Production increased 2% quarter-over-quarter and was ahead of expectations. Adjusted EBITDAX was $341 million, above the top end of guidance and consensus. Operating cash flow before changes in working capital was $300 million and free cash flow on that same basis was $142 million.

Total capital spend of $158 million was within guidance. Oil realizations were 91.3% of Brent before hedges, at the low end of our guidance range as short-term contracts repriced and transportation constraints limited our access to higher-value markets. As our commercial and logistics actions take effect, we expect oil realizations of about 92% in the fourth quarter.

Now three quarterly topics are worth highlighting today. First, the connection between Belridge and Elk Hills, our two largest oil fields, is a good example of how integration is creating value beyond traditional cost synergies. Since early July, we've been processing additional Belridge gas at our Elk Hills cryogenic plant, supported by our first CCS project. This has increased NGL production by approximately 1,000 net barrels per day or about 10% quarter-over-quarter.

What's important here is the broader opportunity by connecting our upstream processing and carbon management assets, we can generate incremental cash flow from infrastructure we already own. And we're evaluating additional opportunities to apply that same approach across our portfolio.

Second, our gas and power assets contributed meaningfully to the quarter. Natural gas realizations were about 119% of NYMEX Henry Hub and stronger power demand supported an electricity margin of $35 million. Both exceeded guidance, demonstrating the value of our gas and power assets and the ability of our power plant to capture favorable market conditions.

Third, operating costs were $386 million, up $39 million from the second quarter with higher energy costs accounting for the majority of the increase. SoCal Border gas prices more than doubled quarter-over-quarter and diesel prices increased fuel costs across our operations. We continue to make progress on G&A, which declined 16% from the first quarter to $89 million, including $1 million from Crimson. Adjusted G&A declined 20% to $79 million as various synergies took hold.

Looking to the fourth quarter, our cost initiatives are expected to reduce operating costs by approximately $10 million. G&A will increase as we incorporate a full quarter of Crimson, establishing the cost base for the expanded business. We are also accruing performance-based compensation based on our current full year outlook with the final amount dependent on year-end results.

We returned $66 million to shareholders, nearly half of free cash flow before changes in working capital, $36 million in dividends and $30 million in buybacks. We continue to see a material discount between our share price and our assessment of CRC's long-term value. At the current valuation, we expect to remain buyers as opportunities arise with the amount and timing reflecting valuation, overall cash availability and our investment requirements.

Our financial position is another source of competitive strength. We ended the quarter at 1x net leverage with $1.3 billion of liquidity. Earlier this year, we made a deliberate decision to address our debt maturities proactively rather than wait for refinancing to become a necessity. We locked in long-term fixed rate funding and extended our senior note maturities to 2034 and 2035, insulating our borrowing costs from subsequent increases in market rates.

In October, we also extended a $1.5 billion credit facility to 2030, supported by a broad group of relationship banks. The result is a balance sheet that gives us the flexibility to invest in our business, pursue strategic opportunities, and return capital to shareholders without being constrained by near-term financing requirements.

Turning to the fourth quarter. Our outlook includes the Uinta assets pending the sale by year-end. At $102 Brent, we expect net production of about 151,000 barrels of oil equivalent per day, including the effect of production sharing contracts at higher prices and adjusted EBITDAX of about $316 million.

We expect total capital of approximately $120 million, including $8 million for 2027 drilling preparation, and we expect to remain within our full year guidance. Drilling activity remains on plan, funded from cash flow and pace to our operating capacity. We plan to stay disciplined, calibrating activity to long-term prices and returns as we head into 2027.

For the full year, we are targeting adjusted EBITDAX of roughly $1.34 billion at $92 Brent with net production averaging about 152,000 barrels of oil equivalent per day. That will be a record for CRC, reflecting both our larger portfolio and structurally improved economics.

Looking to 2027, we plan to run the 6-rig California maintenance program we outlined last quarter, targeting flat gross production from entry to exit on $450 million to $475 million of D&C and workover capital. We expect production to be second half weighted, reflecting volumes from recent activity and our 6-rig build.

Stepping back, we're building on the structural improvements we've delivered over the past several years, which continue to strengthen the underlying economics of our business. We've reduced the capital required to sustain our production base, strengthened our balance sheet, and expanded the opportunity to generate value from our integrated infrastructure. These structural improvements give us a stronger foundation to navigate different market conditions and greater flexibility in how we allocate capital.

Ultimately, our objective remains the same, to deploy capital where we see the most attractive risk-adjusted returns and create sustainable long-term value per share.

I'll turn it back to Francisco.

Thanks, Clio. We're firing on all cylinders, making disciplined investments and strengthening California's leading energy infrastructure platform. We have built a strong foundation. Now we're focused on getting more value from it.

Our integration work delivered more than $400 million of synergies and cost reductions, and our new organization-wide review will build on that progress. Three years ago, CRC, Aera, and Berry were three separately managed producers, all operating along Crimson's pipeline network. We brought these businesses together, lowered costs, and combined the best people and practices from each. As a result, today, we have high-quality inventory, infrastructure and the team to deliver our next stage of growth.

Now we have the opportunity to do more with those assets as one integrated company. So why now? Because the pieces are in place. We have the state's largest mineral acreage position, shallow PDP declines with multi-decade oil and natural gas inventory, a large midstream network connecting us to the highest value markets, 1 gigawatt of power generation to serve a growing front or behind-the-meter markets, a nationally leading carbon business and a Huntington Beach property moving towards entitlement.

We have more ways to create value, better tools to put these assets to work and a team that knows how to execute. As we advance those opportunities, we're also growing cash returns to shareholders and continue to see exceptional value in our shares. The value proposition is what makes CRC a different kind of energy company.

Operator, we're ready for your questions.

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

The Bloom collaboration looks like a really good opportunity. And I think it's a fast path to maybe monetizing your gas land and CO2 storage. Would you be able to walk us through how that 1-plus gigawatt opportunity gets developed? Who the customers would be? And how are your economics, what do those look like?

Scott, happy to answer the question. So we're seeing tremendous demand for clean, reliable power in California. There's a need for the grid to grow the load. You have cap and invest through 2045 that supports the demand. And we're really pursuing two ways to help meet the needs of the state. We've talked about in the past a lot about retrofitting of natural gas power plants with CCS including opportunities under RCPPP.

Now we get to talk about the second element of the strategy, which is to develop new fuel cells projects with carbon capture. So this partnership with Bloom is, as you said, it combines their fuel cells, which they manufacture with our natural gas, our land infrastructure, carbon storage. So one way to think about it is we get molecules out of the ground, electrons onto the grid and then carbon back into the ground, and we add value every step of the way.

This MOU is a framework that develops gigawatt plus across multiple projects. We're considering sites across the CTV platform in both the southern and the northern parts of California. We're seeing interest from investor-owned utilities, municipal utilities, community choice aggregators, hyperscalers, a lot of excitement around this fuel cell technology. And Bloom just brings a very mature fuel cell technology that they've deployed in many parts of the U.S. They can get to market very quickly. And the fuel cells, basically, the way they work is they generate power around the clock without combustion, very low air emissions and minimal water use.

They're modular. So that means, again, we can get to the market quickly. And importantly, for us, they have a very concentrated CO2 stream, which makes the carbon capture more efficient and also has a pretty good economics. So it's an ideal technology we see for California and, in particular, a nice way to deploy more power into the northern part of the state where we have a lot of the CTV reservoirs.

The business model is pretty straightforward. Bloom is the supplier of the fuel cells. That's their business. We're going to have third-party power developers or private equity that would own and operate the projects, and CRC would supply the gas. We would happy to host them in our land. We'll provide infrastructure that's connected to the grid. And then CTV would transport and permanently store the CO2. So it's a nice combination, a partnership that really enhances a lot of the power sector in the state of California.

Yes, I appreciate that. It's the several bites at the apple, which I know you've talked about before. And my follow-up question is it's good to see that Crimson transaction closed to help the full integration to California and you've highlighted, I think, that the third quarter marks the low point for oil realizations. And could you walk us through the San Pablo Bay restart time line? What's left to do? And when are we going to start seeing the benefits show up in some of the numbers with realizations and cash flows?

Yes. Thanks, Scott. I'll cover the first part of the question and the strategy aspect of it, and then Clio will talk through some of the financial benefits. So simply, Crimson just gives us a lot more control on how we get our barrels to market. We have to reopen San Pablo Bay, which is part of Crimson, and that restores the northbound outlet.

It expands the universe of prospective buyers. And it importantly also has -- establishes the flow security, not just for our production, but for the entire California market. We're targeting a restart of the San Pablo Bay pipeline in the first quarter of 2027. The pipeline is ready to restart. I mean it could really -- we can get it going in very short notice. We do not need additional permits. We don't need any additional capital to bring it back into service.

The work that we're doing right now is to finalize the various logistical and commercial flexibilities that are needed so that we can have potential options and many different pathways to sell our crude. For example, we are considering waterborne access through the Bay Area terminals as one of the options that we're pursuing.

Once we restart, we'll complete typical catch-up maintenance and integrity work on the first 12 months of operation. Our integration team has been in place in September when we closed the deal, and we've been working closely with our regulators to ensure a smooth start. As a reminder, it's a common carrier pipeline. So Crimson recovers the costs and earns a return through the published tariffs. So we expect, once San Pablo is open, to have Crimson be self-funding without large capital costs from CRC.

And finally, on my part, we acquired Crimson for about $63 million, about 4x EBITDA, projected '27 EBITDA. But it's a good transaction, but it's also a critical infrastructure for the state that it's impossible to replicate. So the value of CRC and other producers goes beyond the pipeline earnings. It extends to our production, the production of other California producers, and then also gets us to the downstream markets that are seeking native California production as well. So that's a little bit of the backdrop, but I'll let Clio take from here.

Thanks, Francisco. So Scott, to add on the financial perspective around the Crimson transaction, the benefits really come through better oil realizations, lower transportation costs and earnings from moving those third-party barrels. The largest opportunity here is really in our upstream business. To put some scale around that, at approximately 120,000 barrels of oil a day, that's net and $90 Brent. Each percentage point improvement in realizations, that represents roughly $40 million of annual EBITDA, and that doesn't include the transportation savings or third-party midstream earnings in addition to that.

And frankly, we're already seeing progress even ahead of the San Pablo Bay restart. So our fourth quarter outlook, that assumes realizations improved by approximately 1 percentage point to 92% of Brent alongside further transportation savings you see there. So together, that's approximately $11 million of improvement compared with the third quarter. And we continue to view the transportation disruptions as temporary. We've now filed a complaint, a formal complaint with the CPUC, and we also intend to pursue recovery of the associated losses. None of that potential recovery is reflected in our outlook.

If you look ahead here, reopening San Pablo Bay will build on the progress we're already making and the financial contribution will build as shipments ramp up and commercial agreements here take effect. So we expect a more meaningful contribution in the second half of 2027. The real opportunity isn't just what the pipeline system earns on its own. It's really the incremental value it unlocks across our combined businesses.

The next question comes from Betty Jiang with Barclays.

I want to start off with a question on the Golden Valley data center update. It's certainly a unique project. So if you could just give us an update on where you are on the permitting front and how the customer conversations are going? And then that project, there's -- it's a combination of you have power, land, and carbon management, a variety of things on that site. So just wondering how you see that as a proof of concept for future projects or even future expansion around that site.

Betty, thank you for the question. We're really excited about our site, the project, Golden Valley. As you mentioned, it's pretty unique and we already have the power plant. We have the land that we own. We have the gas supply in place. This is not a project where we're waiting to build a power plant from scratch or we're in the queue for turbine. So it's a differentiated project and that it has a lot of the components already there. So we're really focusing on the permitting.

We submitted the conditional use permit application earlier this year. And yesterday, we reached a significant milestone with the California Office of Land Use and Climate Innovation. They issued a notice of preparation for the permit. What this means is it's a big milestone because it means that the permitting clock has started. And now there's a clear path forward that should bolster the attractiveness of the project.

As a reminder, we're developing initially a 275-megawatt campus at Elk Hills behind-the-meter power from our operating plant. We also have an existing PG&E interconnection for backup and the preliminary engineering study that they did found that there's sufficient standby capacity without upgrades to the existing infrastructure.

We've also done a lot of work with the community. We're meeting with them early and incorporated any concerns that they might have into the design of the project, including closed-loop water cooling.

On the commercial side, we're working with Beacon, our co-developer, and we're engaging with target customers directly, certainly keeping everybody updated on the permitting progress and the engineering work as those are important aspects for hyperscalers to evaluate the site and ultimately see what the delivery schedule will be.

Those hyperscaler discussions really centered on when that power can be delivered, the reliability and, of course, the long-term power purchase agreement. So at this point, what we're targeting is an MOU with a hyperscaler in early 2027, and that should put us on track to do a draft PPA later in the year.

Right now, Beacon is funding the early-stage development. They're doing a lot of the construction work and the capital capabilities. And again, we bring -- we contribute the firm power, the land, the infrastructure, the permitting experience. So our objective is to capture value through all those elements, including a long-duration PPA with the value that reflects the value of firm power that's so scarce in the data center space we have.

That's really good to hear about the notice. If I could just ask on the, when you said permitting clock has started, is there a time frame on when that -- they would expect to provide that permit?

It should be about 12 to 18 months.

Favor of well stimulation treatment in California. That seems like it could be something meaningful to reopen development opportunities for CRC, maybe something that we haven't talked about for a while. Could you just talk to the implication of this ruling? How meaningful could it be? And what area, if any, will benefit from this?

Yes, the impact could be meaningful, but we're still early. So in fact, I'll cover 2 aspects of -- 2 litigation updates that you'll see in the 10-Q. I'll just cover each of them briefly. One, as you said, steadied some WST, which is the well stimulation treatment. So a few weeks ago, the Kern County Superior Court issued a tentative ruling setting aside the CalGEM denial on certain well stimulation treatment permits. And an all-in CalGEM subsequent 2024 rule prohibiting the approval of WST permits.

California has had a long history of safely undertaking WSTs, and CalGEM, the regulator itself has included -- has concluded that the WSTs are safe and effective production method. We really welcome this encouraging development and look forward to this permitting process getting back on track. The case is subject to appeal, so the timing of the outcome is uncertain, but we'll be sure to brief the investors as that continues -- that process continues, but it could be a meaningful win for producers in California.

Separately, yesterday afternoon, the Kern County Superior Court issued a ruling setting aside the county's certification of the environmental impact report and its approval of the CTV I project. The ruling is not yet final and the impact to existing operations at CTV I is uncertain. We intend to aggressively pursue legal actions to protect and advance our CTV I project. We do not expect the ruling to have a material impact on our results of operations or financial condition, and we're developing multiple other CTV projects that do not rely on this report. So look for more information in the 10-Q on both of these matters.

The next question comes from Josh Silverstein with UBS.

You talked about creating a lot of value through kind of the integrated asset base here. The Belridge gas connection help kind of drive, serve up the NGL this quarter, as you mentioned. What does that tell you about the other repatriation opportunities across the asset base and how much incremental capital would those require?

Yes, Josh. What's interesting here about this project is that it's actually a 2-way integration between our two largest oil fields. So we're moving liquids-rich gas from Belridge into our Elk Hills cryogenic plants. That's where we're recovering additional NGLs.

And in the other direction, we're supplying from Elk Hills back to Belridge to fuel our steam generation and really reduce purchased gas requirements there. So the results are tangible. You mentioned it, Josh. We're recovering approximately 1,000 additional barrels of NGLs a day, and that's really double our initial expectation. And it's true, it's not an isolated opportunity. We're evaluating many more across our portfolio.

On the gas side, we're looking at bringing more liquids-rich gas into our existing processing infrastructure. And then on the power side, we're looking at connecting generation capacity that we acquired through Aera and Berry to demand that we have elsewhere in our fields. And obviously, that would reduce our purchase power costs. And we also see further opportunities on the facility side, future consolidation there, and really improve the reliability of our systems across the footprint.

You asked about capital. The requirements there, I'd say, vary. Some projects need relatively modest investment to connect those assets we already own, but others require really more substantial capital. So we're evaluating them individually. We aren't ready to put an aggregate number around the opportunity yet. What really matters here to us is the incremental cash flow relative to the investment required as well as the execution risk. And so that's how we're prioritizing these projects. But ultimately, it's about making the assets we already own productive together and more productive than they were independently.

And maybe just thinking about cash flow allocation. And then obviously, you did the Uinta sale this past quarter. Can you just walk through potential use of proceeds on that? Obviously, you don't have any near-term senior maturities. Just how you're thinking about allocation on that front?

Josh, I appreciate the question. We felt that Uinta was a good asset, but our California opportunities are just better and a better use of CRC's capital. As a reminder, when we acquired Berry, the main reason we did the deal was for the California business, conventional reservoirs next to our operations with significant integration upside.

Uinta came with the transaction, and we attributed very little of the purchase price to it. We started the year, we evaluated with an open mind. We were considering development, partnership or sale as we started the year, we drilled 4 wells. They came in ahead of schedule, below budget, good results. But as you look at the assets and you see a California business that keeps getting stronger, and with our permitting improvements and returns that we're seeing in our wells, it was just very tough for Uinta to compete for capital, has very steep declines.

It has higher transportation costs, has a discounting pricing for this waxy crude. So we said we -- timing made sense, and we were able to run a process and get good value for the assets. So the base price is around $90 million. Once you go through all the post-closing settlement adjustments, we expect about $100 million to come in on a net basis. And that covers part of the -- that covers the Crimson acquisition is one way to think about capital allocation.

But at the end of the day, the proceeds will be used between a combination of higher return California investment and shareholder returns. We'll just -- we always, as we do, evaluate the vast value for the deployment of capital, and we certainly intend to do that as we get the proceeds from Uinta in a few weeks and towards the end of the year.

The next question comes from Arun Jayaram with JPMorgan.

You guys have largely delivered on Phase 1 of your organizational kind of improvement program with the $400 million of improvement, including getting there in Berry within 6 months. I was wondering if you could talk about Phase 2 of that program. Why is this the right time and potential tailwinds from Phase 2 of that program?

Yes, I appreciate the question. We -- definitely, I should say, we delivered $400 million of synergies, and we've been good about showcasing to the market the progress that we made and those reductions on structural cost reductions that we made. But the merger targets completed does not mean the job is done.

We will continue to improve the business and look to enhance value. So one way to think about it is, the Phase 1 brought the companies together. Phase 2 is about designing how the combined company should work. And with the scale that we have, we have the ability to do things differently. And certainly, there's much better tools in place to make the changes very effective in the kind of a new way for running an E&P company.

As I step back and think about what success looks like for E&P companies and, ultimately, how do we compete for relevance with shareholders, I think there's really 2 things that matter. One is the resource base, decades of inventory, and we certainly have that. We have over 20 years of drilling inventory, and that really just includes our oil project with our natural gas on top of that. But the second piece is earning the highest netbacks from your production.

So we have the assets. The next step is to bring the cost down of running our business and improve the margins. We're particularly well suited for this. We manage, as a conventional company, we manage thousands of wellbores. We have a large footprint. And small improvements that are repeated across that many wells can have a meaningful difference. And you'll see it in the slides. We're focusing really on standardizing systems, and it's -- data is critical to make sure it gives us the right decisions.

But we're also going to work on how -- align how the work gets done across the business, removing any duplication and that may be remaining after the mergers. And ultimately, we're going to incorporate AI and digital tools. There's clearly a way to reduce a lot of the manual work that historically has been the case with the E&P companies. And our view is we can make our employees much more productive and our decisions better.

The good news is we're already started. I mean we're seeing some early wins at Belridge, which is a field we acquired from Aera. Our systems monitor production around the clock, and they flag any drops in production within the hour, which helps the team respond sooner. In the past, that would have taken a lot longer to get to it. But also piloting tools that screens wells around workover candidates, allowing the engineers to make the decisions, but really speed up the time evaluating the opportunities.

So there's a lot of work to do, but it could be very impactful. What I would expect is for the savings to build to 2027 and most of the impact to be reflected in 2028. We'll share the cost reduction targets and be more specific when we talk about our 2027 guidance. And as we did with the synergies, we'll keep giving an update to the market. And I would expect those improvements to show up in operating costs, G&A, and capital efficiency.

At the end of the day is to have a leaner, more productive CRC that maintains our high standards on operations, supports our growth, and ultimately competes for capital given the strong position that we have already.

Yes. And my follow-up, the company looks to be entering 2027 with a 6-rig program, call it, $450 million to $475 million of D&C and workover capital, which is obviously a lot less than you did on CRC from a legacy perspective. How should we think about the production shape in 2027 and thoughts around what this means for capital efficiency in '28?

Yes, I appreciate the question. We're back to being a California pure play, and we've been talking about it takes 6 rigs to keep our production flat. So we are below that level of investment today as we exit the year. So '27, as we go to 6 rigs, the shape is important to discuss. So let me first highlight, as a reminder, with conventional wells, these conventional wells come online very quickly. It takes about 30 days from spud to production. But because it's conventional rock, it takes about 6 to 12 months to reach a peak, right? So very different shape that you would see in the shales.

I've described it in the past as a slow rising tide. So a steady program builds production over time and then the low decline PDP helps sustain it. So as we enter 2027 with 6 rigs, we're targeting flat gross production from entry to exit. The way I would think about it is because it's going to take some time to ramp up on that 6 rig, we would see more of that production buildup in the second part of the year.

So small -- flat to slightly declining in the first part of the year and then a buildup back in the second half of the year is kind of the shape I would describe as we go through next year and the planning. In the U.S., remind also to talk a little bit about our capital efficiency and how much of that has improved. Legacy CRC before the acquisitions, we would have needed about 8 rigs and about $150 million more to get to those same outcome. We're drilling 25% faster with our dedicated rigs and crews.

And our base decline has shallowed. We're now averaging a corporate decline before capital at 8% to 13%. And then the new production costs are about $27,000 per flowing barrel. So it's below what we paid for Aera and Berry. So not only did we buy the assets at the right time at the right price, but the inventory that we're drilling, which is primarily Aera and Berry, is coming in a very efficient way.

So I'll turn it to Clio for additional color on some of the numbers around our capital program.

Thanks, Francisco. Let me build on that with some perspective on the investment economics and what that means for '27. So as Francisco mentioned, we've refreshed our '26 California D&C workover program using really our actual results to date and end of October strip pricing for future production. And that's where you're seeing that we're developing the new production at approximately $27,000 per flowing, and those are also expected IRRs of about 70% and as on a MOIC basis, 4x.

So very compelling. It's a meaningful competitive advantage in how we're replacing production here. And if you look at '27 and what we've done this year and where we're moving to, we've spent about $355 million, I would say, this year on D&C and workover in California only. That's where we're tracking. And we're ramping that up to next year to $450 million to $475 million.

And so that increase really reflects us moving from an activity pace where this year, we were at about 4.3 rigs on average to a full year of 6 rigs and a larger workover program. So really an increase in activity, not a deterioration in our capital efficiency here. And of course, we'll provide more details with our '27 outlook, and that will be with our fourth quarter results.

The next question comes from David Deckelbaum with Stifel Financial.

Maybe for Clio, I wanted to get a little bit more color on your outlook on just the electricity margin for '27. 3Q, you guys had a nice beat and see the guidance for fourth quarter. But just the value of dispatchable power now going into '27, ahead of the PPA that you guys have talked about in Golden Valley. How do you see that market kind of firming up around the power business for next year?

David, yes, definitely on the power side, we've seen some changes and a very strong third quarter. But I would say, on an annual electricity margin, and that's before any new PPA or contribution from Golden Valley or RCPPP, I would use really approximately $30 million to $40 million of annual electricity margin and use that as our normalized reference for the existing business.

This year has demonstrated the value of us having reliable dispatchable power available really when the market needs it. This quarter, obviously, we generated $35 million of electricity margin, and that was supported by favorable summer market conditions as well as we've seen additional support really here in October. But I wouldn't use those as an annualized rate. I think our 30 to 40 base case is something that we've seen in historical support for.

The bigger opportunity for us here is to convert that earnings potential into long-term contracted cash flow. That's what we're pursuing through Golden Valley, through other opportunities across our power platform. And we've got a real focus there on attractive economics and greater cash flow visibility.

And maybe just to stay on some of the other line items ex E&P. Especially considering Crimson is not closed, you're talking about San Pablo pipeline coming back on in the first quarter of '27. How is that going to be flowing through at all to your marketing margins for next year outside of maybe just the gas opportunities on the marketing side, but are you seeing increased opportunities on the oil side as well that would sort of enhance that line item for you all?

Yes. So on the marketing side, it's important to distinguish really what we're doing on the existing gas marketing activities from the broader oil commercial opportunity you mentioned. So when we talk about our reported margin from purchase commodities, that's primarily our gas marketing currently. And I'd say a reasonable normalized reference -- annual reference there is approximately $30 million to $50 million. That does not include transportation costs.

But yes, Crimson, Line 100, everything we've put in place this year, that really expands what our commercial team can do on the oil side. We can be more deliberate about when and where we move our barrels, how we use storage, and how we aggregate and blend volumes to really meet customer needs. And so those capabilities, they allow us to improve the net economics of how we market our production, and we're very focused there.

I'd say, importantly, not all of that value will show up on the reported marketing margin line. We really look at the economics across the entire business for CRC.

The next question comes from Nate Pendleton with Texas Capital.

Congrats on the strong quarter. You returned nearly half of your free cash flow this quarter, raised the dividend again, and the transaction calendar is now largely behind you. So how should we think about buyback pace in the fourth quarter and into '27, especially with the Uinta proceeds coming in?

Yes. So we bought back $30 million of shares this quarter, and that was at an average price of $53.5 million. And we continue to see a meaningful gap between where our shares trade and what we believe the business is worth. We're seeing compelling value in our shares, and we're prepared to act on that.

Nate, if you look at our track record, we've repurchased roughly 470 million over the past 2 years. We've been quite deliberate there, I'd say, about when we step up activity, particularly during periods of market weakness. And I think the important point here is that we can reinvest in the business and buy back shares, and we're doing both. We just talked about the returns on our drilling and workover program. Those offer very attractive returns, but we also have compelling opportunity right now on our shares and where those valuations are.

So I think when you look at Q4 and into 2027, we're going to continue to weigh the valuation of our shares against the investment opportunities in the business, against our cash generation, against our balance sheet strength. We still have approximately $570 million remaining under the authorization on the buyback side, and that's valid through the end of '27. And we also just increased our dividend really for the fifth consecutive year. So our focus is clear. It remains on growing long-term value per share and buybacks are very much a part of that equation.

And perhaps as my follow-up, Huntington Beach looks like one of the most valuable undeveloped coastal sites in Southern California. With the city process in its final stages, can you walk us through the remaining milestones and how remediation is progressing?

Yes, Nate, sure. Thanks. Yes, so 90 acres of beachfront property at 1.2 miles with the Pacific Coast Highway and the Pacific Ocean in front, right? So it is a very unique site. We're making really good progress. We are finalizing -- the planning commission of Huntington is finalizing the study sessions this month. There's a hearing expected in December and then a city council vote will be targeted in January.

The proposal that we have in front of the commission and the council is a mixed-use community with up to 800 homes, 350 hotel rooms with retail, dining, and public open space. And we've had very constructive engagement with the city and continue to work closely with the community.

After the city approval, we would submit with the -- for approval with the Coastal Commission. We've already engaged with their staff and incorporated their perspective into our proposal. We continue to expect about a 2-year review, so running through 2028. Coastal certification is a key milestone for unlocking the redevelopment value.

In parallel, we've been making good work on progress on the plugging and abandonment of the idle wells. Since 2024, we completed about $30 million of abandonment cost and are on track to plug all the idle wells by year-end 2028. What that means is we'll still have about 80 active wells that will remain to be plugged when the redevelopment begins. But that's because the field continues to produce about 3,000 barrels a day gross. And obviously, that cash flow will fund the work going forward.

So our approach is to continue to advance the entitlement, the remediation before monetizing. Each step brings the site closer to redevelopment and builds its value, and we want the CRC shareholders to capture that upsell.

And the last questioner today will be Scott Gruber with Citigroup.

So you've discussed a broad range of opportunities in front of you across upstream oil and gas to the associated pipelines to now broadening power strategy and your carbon management opportunity set. As you think about this opportunity set, how do you decide where to commit CRC's own capital versus bringing in third-party partners? And how should investors judge value creation across this opportunity set? What would you recommend we watch for?

Yes, Scott, I think the key here is selectivity. Our opportunity set is expanding, being disciplined about where we commit capital becomes even more important here. And we don't need to fund every opportunity that we help create. Every investment has to compete with the reinvestment in our existing business, share repurchases, and other uses of capital while preserving really our balance sheet strength.

But there's another important dimension on how we think about this. CRC brings valuable asset capabilities to these projects, whether it's land, gas supply, power, infrastructure, carbon storage, and operating expertise in the state. So those assets have real economic value even when contributing them today requires very little new cash. And so we expect to be compensated for that contribution, whether or not we invest additional capital from there.

So for us, it's really two separate questions. First, how do we capture the value of what CRC already brings to the table, and that could be through commercial agreements, partnerships, ownership participation. And second, does it make sense for us to make an additional investment here? And so that investment has to earn an attractive return relative to what we could achieve without committing the capital.

We're really going to be deliberate about choosing partners. We have been partners who bring complementary capabilities, financing, expertise. The objective for us isn't to maximize ownership percentages, but really to maximize the value we retain relative to the capital and the risk we're taking on. So ultimately, our investors, you ask what they should judge us on, really on the value we create, the capital we commit, and the cash flow that these opportunities are set to generate. So our objective there continues to be grow cash flow per share and grow long-term value, not simply the size of CRC.

I appreciate that perspective, Clio. And then a follow-up here. Are you seeing more interest from external capital across these different verticals? And linked to this, how do you think about California energy investment broadly over the next few years and how that could evolve under the next administration? Curious whether you think we could see a broader inflection here.

Yes, Scott, thanks for the question. So we've -- we spent many years now assembling this asset base with very long-life oil and gas reservoirs. We now have critical pipelines, power, and carbon storage. We have 200,000 surface acres, 2 million mineral acres, and we talked about Huntington Beach. So these are critical assets, hard to replicate, very attractive. And you can see how we've been building this partnership model at the same time.

Brookfield has been working on carbon storage. We have Beacon at Golden Valley. We're going to bring partners in to help fund the fuel cells with Bloom. And we're working on other ways to enhance value and bring capital -- bring returns forward for investors. So we see this as a business that we can grow and we can grow in a very capital-light way to bring differentiated returns to our shareholders.

So the next couple of years, we'll continue to unlock that value and bring that value forward. We're very optimistic about the next administration, regardless of who wins tonight, obviously, election night. And what we see is both candidates for governor, very data-driven approach and going to be very -- making very practical decisions. We've seen a real change in the last 18 months with the current administration. So we expect that to continue going forward. I know both candidates on the ballot today are talking about affordability and protecting California's critical energy infrastructure. That's all very encouraging.

I mean the reality is California needs energy for 40 million people, and that doesn't change the politics. I mean that's just a reality. So we're in the right state with a very attractive competitive advantage to anybody else that wants to come in and play in California has to learn to do better than CRC, and that's going to be a tough ask. And the state continues to rely heavily on foreign crude on refining capacity from elsewhere. The refining capacity has declined. The electricity demand is growing, and we see reliable local supply as the answer going forward.

So we're very encouraged about the backdrop and the opportunities, and we expect that to continue as the next administration takes over at the beginning of next year.

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

Thank you. Thank you. Thank you, everybody, for joining us today and for your continued interest in CRC. We look forward to updating you on progress in the months ahead.

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

Good day, and welcome to the California Resources Corporation Second Quarter 2026 Conference Call. [Operator Instructions]. Please note, 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 Second Quarter 2026 Conference Call. We hope you've had a chance to review our earnings materials, which include our non-GAAP reconciliations. Today's call includes forward-looking statements, and actual results may differ due to factors described in our earnings release and SEC filings.

Following prepared remarks, our leadership team will take questions. [Operator Instructions]. I will now turn over the call to Francisco.

Good morning, everyone. We delivered a solid quarter in our oil and gas business, driven by strong operational execution, continued synergy capture and sustainable drilling efficiency gains that strengthened our outlook. We also made good progress on our emerging carbon management and behind-the-meter power platforms and announced two important midstream transactions that build on our long-term strategy to generate shareholder value from our California assets.

Let me begin with some comments on our strategic plans. Clio will then walk through our quarterly results and outlook. While focused on near-term execution, our team is also looking to the future. The state's regulatory environment, once seen as an impediment to our industry is now supporting local onshore production to the benefit of all Californians.

Events in the Middle East have caused ripple effects throughout energy markets. Here at home, California's reliance on imported crude and refined products has created temporary transportation and price challenges across the state, highlighting the need for energy security and reliable, stable sources of local supply. That's precisely the need CRC is built on.

For the last several years, CRC has been intentionally building a stronger and more integrated California Energy platform. Our Aera and Berry mergers created scale and new avenues to profitably grow our business. As the largest producer in the state, the expansion of our midstream infrastructure and marketing capabilities was a logical step to bolster our long-term strategy.

Greater control of critical infrastructure will provide options to enhance the commercial capabilities of our business and stability of our operations. This benefits CRC as well as other producers working to move more local product to local markets and ultimately supports California's energy security and affordability.

Last quarter, we took the first of two steps to strengthen our midstream position purchasing the Line 100 pipeline from P66 for a nominal amount. The deal added about 120 miles of crude pipelines connecting key Central Valley production hubs along with over 1 million barrels of storage capacity in gathering, transportation and truck loading infrastructure. That brings us to the Crimson acquisition we announced today. Crimson's midstream platform covers roughly 2,000 mile network of California crude oil pipelines that run through the heart of our producing fields.

The transaction advances our long-term strategy and connects our production directly to California's highest value markets. As the state's largest producer, our integrated platform will provide greater flexibility to move both CRC and third-party volumes, improve price realizations, generate more diversified cash flows and drive new efficiencies.

The all-cash deal is financially accretive and is priced significantly below prevailing midstream sector valuation multiples. Because certain Crimson assets operate as a common carrier, the transaction requires PUC approval. We recently received tentative approval with no conditions attached, and we expect the final decision later this month. Recent market conditions have illustrated the strategic value that Crimson adds to our platform.

Takeaway capacity over the last quarter was constrained due to what we expect to be temporary marketing disputes with a pipeline operator and certain offtakers, limiting our ability and that of other local producers to transport barrels to previously contracted markets and pressuring oil price differentials on replacement sales.

We have taken proactive strategic steps to broaden our transportation and marketing options and improve the reliability of our market access through new agreements and partnerships. We fully expect these actions, together with the resolution of the ongoing disputes to strengthen differentials and bring realizations in line with historical levels.

Now let me focus on the expansion of our growth businesses. On carbon management, we recently commenced CO2 injection and achieved first revenue at California's first CCS project at Elk Hills. This places us on an esteemed list of commercial scale sequestration operators globally. We have demonstrated our ability to permit, construct and operate an EPA Class VI project. The start-up showcases our operating, technical and regulatory competencies, all of which can be applied and scaled across the state.

We are tracking the CPUC's Reliable and Clean Power Procurement Program, or RCPPP, as a potential market for natural gas with CCS. Updates from the state are expected this fall.

This could be meaningful for CRC as we're well positioned to support California's growing demand for reliable, lower carbon power. California has the potential to decarbonize approximately 17 gigawatts of power. For our CTV platform, this includes a near-term opportunity of approximately 2.4 gigawatts in the Central Valley.

Using our Elk Hills Power Plant and adjacent infrastructure, we recently partnered with Beacon data centers, an energy-focused North American data center co-developer, to advance the Golden Valley Technology Hub. The proposed 275-megawatt campus would span 100 acres adjacent to Elk Hills and combine our proven permitting and operating experience in California with Beacon's data center expertise.

With our co-developer partner funding early stage development, the project will leverage industrial acreage, existing infrastructure and firm power from our Elk Hills plant to help meet rapidly growing demand for power and AI. The proposed behind-the-meter design is expected to minimize power and water usage. We have submitted the conditional use permit and expect the environmental review process to advance later this year.

Our ongoing discussions with a handful of global hyperscale data center operators have accelerated and reinforce our confidence in the commercial viability of the Golden Valley Technology Hub. We look forward to reporting on our progress in the coming quarters.

With that, I'll turn it over to Clio.

Thank you, Francisco. Let me cover our second quarter results and our outlook. Net production averaged 149,000 barrels of oil equivalent per day with oil representing 81% of total volume.

Oil realizations were approximately 95% of Brent before hedges within our second quarter guidance range. Operating costs were in line with guidance at $347 million. As expected, G&A declined nearly 9%, reflecting Berry-related efficiencies.

Second quarter adjusted EBITDAX was $338 million, while operating cash flow and free cash flow before working capital were $300 million and $151 million, respectively. We have implemented more than 100% of our 2026 Berry synergy target 6 months ahead of schedule, representing approximately $103 million of annualized savings.

Across our integration and broader cost reduction initiatives, we now expect up to $470 million of cumulative synergies and structural cost reductions through 2028. This reflects the quality of the combined portfolio and our ability to translate integration into durable margin improvement. Execution continued to improve during the quarter.

In California, time-to-market improved approximately 25%, allowing us to complete more wells sidetracks and workovers than planned. In the Uinta, we drilled four wells ahead of schedule. We reduced cycle times and our D&C costs were below plan. The team continues to target first production in the fourth quarter as planned. These efficiency gains allowed us to pull activity forward into the second quarter resulting in total capital of $149 million for the period.

As a result, we have streamlined our development program reducing planned 2026 D&C and workover capital by $10 million. We are redeploying those savings into targeted facilities investments, which is why our total capital guidance range remained unchanged. More importantly, we believe the underlying drilling and capital efficiency gains are sustainable. We now expect to operate an average of approximately 5 rigs in California during the second half of 2026, compared with 6 in our prior plan while maintaining nearly flat gross entry to exit production.

Faster time to market is only half of the story. We have also materially improved well productivity. Approximately 80% of the wells drilled year-to-date have outperformed the type curve with average initial production more than 10% above expectations.

As you know, production from our conventional wells peak within 6 to 12 months after coming online and recent activity will benefit our 2027 volumes. Together, accelerated cycle times and stronger well productivity are a powerful combination and have meaningfully improved our long-term maintenance capital outlook.

We now estimate that California production can be maintained with 6 rigs on a normalized annual basis. One fewer than previously projected and approximately 5% lower D&C and workover maintenance capital. Both represent meaningful structural improvements in the capital efficiency of the business.

During the quarter, we refinanced our remaining 2029 Senior Notes with new Senior Notes due 2035. This extended our weighted average debt maturity from 5.5 years to 8 years, reduced annual expenses by $5.5 million and achieved the lowest credit spread in CRC's history.

Our capital allocation priorities remain unchanged: invest in high-return organic growth and strategic opportunities, maintain a strong balance sheet and return meaningful capital to shareholders through a sustainable dividend growth model and opportunistic buybacks.

Temporary takeaway constraints during the second quarter related to marketing disputes and subsequent operational needs required us to temporarily build inventory of approximately 1,500 barrels of oil per day during the quarter increasing operating costs and negatively impacting our differentials.

Absent these temporary impacts, production would have exceeded guidance while adjusted EBITDAX and operating cash flow before working capital would have each been approximately $25 million higher. We are actively addressing this matter while executing on alternative logistics and marketing solutions.

By the end of July, we had sold the substantial majority of this inventory. As a result, we expect third quarter oil price realization of approximately 93% of Brent. We think it is a prudent assumption based on current market conditions. To be clear, we do not view that as a new long-term run rate. We expect realizations to improve as the commercial and logistics actions already underway take effect. Those actions will give us a broader slate of alternatives to move CRC and third-party barrels to California's highest value markets while strengthening our cash flow outlook.

Turning to guidance. We target full year net production to average approximately 153,000 barrels of oil equivalent per day, while maintaining our full year capital guidance of $520 million to $560 million.

Including Uinta, our outlook continues to reflect approximately 1% gross entry to exit production growth. Importantly, we continue to see our full year realizations at about 94% within our original 94% to 98% range. We expect to enter 2027 at the normalized California 6-rig pace contemplated in our long-term maintenance framework.

Updated 2026 guidance will be provided following the close of the Crimson transaction. Disciplined execution, lower costs, including synergy capture, and strategic actions are supporting margins.

Ultimately, stronger well performance and sustained operating efficiencies are enhancing free cash flow while lowering the long-term maintenance capital required to sustain our unique low decline California production base.

I'll turn it back to Francisco.

Thanks, Clio. Let me close with a quick summary before opening the line for questions. First, today's midstream transaction strengthens our California platform, reinforcing market access, improving margins, and increasing our ability to move local barrels to the state's highest value markets.

Second, we're executing very well better wells, lower cost and sustained efficiency gains are reducing long-term maintenance capital and rig requirements while reinforcing free cash flow resilience.

Third, we're advancing our carbon and power platforms. The start of CO2 injection and revenue generation of California's first CCS project were great milestones and our new planned project with Beacon data centers at the Golden Valley Technology Hub is leveraging growing demand for firm power and data center capacity. Together, these actions make CRC more integrated, more efficient and better positioned to create durable value in California.

Operator, we're ready for questions.

[Operator Instructions]. The first question today comes from Betty Jiang with Barclays.

I want to start off with Crimson. Francisco, you mentioned earlier that the company has been intentionally building an integrated California energy platform over the last few years that includes the expansion of midstream infrastructure. So can you just frame this Crimson acquisition within that broader strategy. What role does the asset play in that vision? And how long you guys have been thinking about this opportunity?

Yes, we've been thinking about midstream integration for some time. We started thinking about Crimson in particular about 3 years ago. But the first story of our business was to acquire Aera and Berry, gave us a lot of scale, a lot of remaining oil and expanded our footprint considerably. And as that footprint was growing, we felt critical infrastructure around those barrels was going to be key to step into -- and it was truly a natural step. We already managed a lot of pipe in California.

So we understand the systems really well. So now we're getting into common carrier, which adds contracted revenue, which we really like. And these are assets that are very difficult to replicate. If you think about our playbook, it really hasn't changed.

From an acquisitions perspective, we're looking for high-quality assets at attractive values and assets where we have an advantage and with that integration that comes into our hands, becomes even more valuable. So we think we have a good track record of doing that and Crimson fits that pattern.

In terms of the asset, so 2,000 miles system, it connects to most of our key fields and across multiple basins support certainly our production, but also improves market access and it strengthens the connectivity to some of the highest value markets in the state.

Restoring capacity for this pipe was important too from a state perspective. It addresses a real constraint from other producers and ultimately, that flows to consumers in the state -- this pipeline system is needed. And I think you're seeing that reflected in a supportive regulatory process. As I mentioned on the script, we have a tentative CPUC approval with no conditions and expect to receive final approval later this month.

So if you step back, Crimson is doing exactly what an acquisition should be doing for us. It's adding more stable contracted cash flow and makes the broader California platform even stronger.

Got it. That makes sense. And maybe tying that to the differentials and the transport constraints that we are seeing right now. Can you just help us understand it better on just what's driving the current bottleneck? Maybe more color on this pipeline legal case that you mentioned earlier -- what gives you the confidence that this pressure is going to be alleviated soon and just maybe some outlook into 2027, how this differential improves from here?

Sounds good, Betty. I'll give you some high-level perspective and Clio can talk about some of the impact in the quarter, but we see this impact as being temporary. And to start, maybe I'm going to give a little context on what we're seeing in California because a lot has changed over the last year, and in our view, a lot of things are improving significantly.

We're running about 7 -- and there are 7 rigs that are being run in the state today. 5 of those rigs are CRCs. That's the highest level of activity that we've seen in the state since 2023. If you heard the second quarter earnings from some refineries, they're starting to make significant capital investments back in the state.

On top of that, production has been increasing and the pipes in the southern system are running full. If you take it as a whole, you'll see that the signs of a market significantly improving. Now you couple that with the Middle East conflict and it is leading to some near-term conditions that are favoring refiners. And on top of that, we're dealing with a pipeline operator that's behaving in a manner that we feel is inconsistent with established tariffs.

But we do view those as temporary conditions and not structural changes to the California market. Again, we see the market as improving drastically. Our team has done a great job. And it's between our marketing organization, the relationships we have with refineries.

We have multiple transportation connections. We did a timely acquisition of Line 100 that provided 1 million barrels of storage and gave us a lot of options. So where you're seeing that reported differential impacts for some producers in the basin are approaching about $20 a barrel we limited that impact to CRC to about $2 a barrel. And we see -- we think we've seen the worst of the impact and are working really hard to improve -- to get back on track to historical levels.

The other way to think about it is we're also thinking beyond the noise and the disruption. Going forward, we see a potentially fragile global energy supply chain where reliable barrels produced under stable governments are going to become increasingly more valuable, which makes owning this California infrastructure even more important. So that's where Crimson came in.

So as we move into 2027, we like the greater control of Midstream. We like the multiple market connections and storage -- we have strong marketing capability that actually allow us to move our barrels to the best markets and ultimately capture value.

So with that, maybe I'll turn it to Clio for her context.

Thanks, Francisco. So from a financial perspective, I think the key point here is that we view this as a temporary commercial issue rather than a change in the underlying earnings power of our business. And there are really 3 things to highlight here. First, operationally, this was a strong quarter.

And despite the temporary disruptions during the quarter, we still realized approximately 95% of rent which was within our second quarter guidance range of 94% to 96%, and we had established that at the beginning of the quarter before these transportation and marketing issues emerge. And that really speaks to both the strength of the underlying business as well as to the execution of the team, of course, and Francisco mentioned this, but they really adapted quickly found alternative solutions, and ultimately, that allowed us to deliver within guide.

Second, the total financial impact during the quarter, that was approximately $25 million or less than $2 per BOE and roughly half of that was timing related from the temporary inventory build while the balance was primarily weaker differentials while also transportation costs represent a smaller component.

The substantial majority of those inventory barrels, those were sold during July. So that timing impact, it's largely behind us. And those sales that are already reflected in our guidance.

Third, we are guiding for the third quarter of oil realization to approximately 93% of Brent. Now to be clear, we don't view that as a new long-term run rate. As we said in our remarks, we think that's a prudent assumption while the commercial and logistics actions that we've already put in place that those take effect.

We expect the third quarter to represent the low point of realizations this year with our implied fourth quarter guidance that reflects the beginning of the recovery. So stepping back, we currently expect full year oil realizations of approximately 94%. That remains within the original 94% to 98% framework that we had established back in March and that was before these temporary disruptions emerged.

The next question comes from Nitin Kumar with Mizuho.

I want to start on the Uinta, you mentioned a lot of the improvements in efficiencies in California. But if I remember correctly, you have 3 wells coming online by the end of this year. Can you maybe give us an update on the drilling in the asset? And what are your plans for the asset longer term?

Nitin, yes, it sounds good. We're actually drilling 4 wells. And we've been very pleased with the drilling performance to date. We're actually currently drilling the fourth well which should be done in the next few days. So we're running ahead of schedule. Then we move in the completion rig in early September, and we expect to have online and producing all 4 wells before the end of the year.

On the cost side, these wells are roughly about $11.5 million. And based on what we're seeing today, we expect to complete the wells ahead and below the AFE. So good progress on the drilling.

Now in terms of what's next, we're evaluating our strategy in the Uinta. It's a very large position, 100,000 acres with good resource potential but it's largely undeveloped. And it requires a pretty significant amount of capital to develop the scale that we need for a second asset. So as we do a side-by-side and we compare the Uinta assets with California, Uinta has higher capital intensity, higher breakevens, lower crude quality, waxy crude that is famous for but also has higher transportation and operating costs and steeper declines.

Ultimately, it's a drag of about 1% on realization. So putting it side by side with the California assets that have very low decline and generate better returns. It's hard to see us allocating a lot of dollars back into the Uinta -- so I would say it's a noncore asset to core asset -- noncore asset where we're taking CRC, and we will continue to evaluate the best way to maximize the value of that asset going forward.

As of today, I don't see it competing for long-term capital in our portfolio.

Got it. Okay. And so maybe just to clarify, does that mean that with the 4 wells you've tested enough to say that maybe this is something that doesn't belong in the portfolio? And is there a time line for the asset to be sold? Or are you going to wait for the results?

Yes, I wouldn't say there's anything around the drilling. Ultimately, we need the completion crews to come in based on what we've seen, we like the well performance it's more around the type of assets, right? It's unconventional high decline asset and one that's going to require a significant amount of capital.

So -- like I said, we'll see how the rest of the program goes. But if you think -- if you want a long-term answer, I don't think it's core to our business.

Got it. And I'm sorry, I want to sneak one more in, just quickly. You talked a lot about the integrated platform with this purchase of Crimson. Clio, maybe looking at Slide 10, from a capital allocation standpoint, -- how does the Crimson asset fit in? And what was attractive about this specific asset?

Thanks, Nitin. And yes, that's a great question. I actually think the important distinction here is how we evaluate investments. So every dollar competes for capital, whether we're drilling well, acquiring an asset, refinancing debt or returning capital to shareholders. We apply exactly the same investment framework to every capital allocation decision. And from that perspective, Crimson met every one of our investment criteria.

We've been building toward an opportunity like this for a while. We were patient and when strategy really met opportunity at the right valuation we acted. So strategically, it strengthens an integrated California platform that we believe has significant long-term competitive advantage.

And Francisco mentioned, that's a key part of our long-term strategy. Financially, we're acquiring the asset at approximately 4.4x estimated 2027 EBITDA. And so that represents a very attractive entry point valuation relative to comparable public midstream assets. We also believe it's a highly accretive use of capital particularly when you consider the CRC specific synergies and the commercial opportunities here.

And finally, we've already demonstrated our ability to create value by integrating acquired assets within CRC's existing infrastructure. A good example of this is the integration of our 2 largest fields, so connecting Belridge to our Elk Hills processing system. That project immediately increased gas and NGL production while improving the economics of the combined asset base.

So Crimson gives us another opportunity to apply that same playbook. We don't evaluate Crimson solely on the cash flows generated by the pipeline itself. We also evaluated based on what it does for our broader California platform. It's improving market access, increasing commercial flexibility, enhancing realized pricing and ultimately creating more value across the integrated business. If I put it simply, we believe Crimson, it's worth more inside of CRC than it would as a stand-alone midstream company.

And we've been very deliberate about where we want to build the business but also equally disciplined about the price we're willing to pay. So we're very comfortable passing on opportunities until they meet both our strategic and also our financial objectives. And that's really ultimately how we think about capital allocation. It has to be the right asset at the right valuation and at the right time.

The next question comes from William Barber with UBS.

My first question is just around the Golden Valley Tech Hub. If you could just walk us through how the partnership with Beacon data centers came about? And then with the conditional use permits submitted an environmental review expected to advance later this year, can you outline like the critical path forward from here? How should we be thinking about the sequencing of hyperscaling commitments, power agreements, permitting and obviously, FID?

Billy, thanks for the question. So -- we talked to a lot of developers and ultimately, Beacon was the best fit for us. They're doing a lot of very large projects in North America with data centers. So they bring great engagement and current engagement with the potential hyperscalers and the tenants. They're doing construction, they're capitalizing the project.

So if you look at what they bring to the table over and then it's a nice complement to our land position our power infrastructure and ultimately, our ability to permit and execute in California. So we think it's a strong combination. And at the end of the day, we look at data center development, maybe a little bit different from what you're seeing from other E&Ps. We're very comfortable starting with project development and not with the headline, because that's ultimately what gets projects done in California, and that's our advantage.

E&P companies are talking about acquiring land and ordering turbines or building power plants from scratch. We already have all of that. And so then our focus is on derisking the project and around what the hyperscalers actually need. So in our direct conversations with hyperscalers, the perspective is that the procurement -- the power procurement cycle is evolving.

The [ Easy electrons ] that were readily available are gone. So as you're thinking about what comes next, they're focusing back on cleaner and reliable electrons and they really care about the date certainty and ultimately, when you have the business operating. And they are focused on project community relations. So we think Project Golden Valley is really well positioned for that.

As you said, we filed the conditional use permit, is a public permit. And what you can see in that permit is on the power side that we designed a triple redundancy into the power solution. It will be a behind-the-meter solution. So we're not dependent on waiting years for new grid interconnection and we also designed around 2 of the major friction points, which is water and community support.

The project has a very low water use. It's using closed loop cooling system. And on the community side, we have documented support from over 100 local residents and business owners. So we're doing a lot of the groundwork, a lot of what's needed to deliver the project, so from here, the work stream really is to advance many things in parallel.

It's the hyperscale engagement and the commercial agreements. They certainly are the next value we can unlock but we'll continue progressing permitting, engineering and financing. That's how projects get done in California. You start with the project development and you advance multiple pieces together, and that's something our team knows how to do.

Got it. Maybe switching over to the E&P business. You guys have improved execution enough to run California on 5 rigs through year-end and then 6 going forward with the 5% lower maintenance capital required in 2027 and beyond while your 2026 wells drilled are also coming in ahead of expectations. I guess just what were some of the key drivers and initiatives here, how durable are they? And ultimately, what does this mean for capital efficiency and your production cadence heading into 2027?

Yes. We've talked a lot about acquisitions and how those assets are going to be better in our hands. And I think you're seeing a lot of that coming through on the operating results. Our team is doing a great job operationally. The days to total depth are down roughly 25% and -- we now have a continuous drilling campaign, which is helpful and dedicated rigs and crews. And we also have good coordination with the CRC operating team and C&J altogether reducing the idle time and getting wells online faster. So it's -- that's one of the elements.

But then if you look at the portfolio, about 2/3 of the wells we're drilling are in fields previously operated by Aera. So we're seeing the benefit of applying the combined organization's operating practices across the portfolio. On top of that, nearly 80% of the wells we drilled to date are outperforming the type curve. So about 10% above expectations. So every rig dollar is buying more production than we underwrote on the deal. So those efficiencies translated into maintenance capital. We expect to be at five rigs in California until the end of the year. And we want to add a sixth rig for the beginning of 2020.

Now the 5 rigs are delivering the Same well count, but roughly with $10 million savings for 2026. So that sets up well for 2027. On a normalized basis, the go-forward maintenance drilling and completion and workover capital is dropping about 5%. So the range is $450 million to $475 million. There's always additional upside that team keeps looking for further ways to integrate and optimize, but we won't put that into the outlook until we demonstrated and able to sustain it.

The next question comes from Arun Jayaram with JPMorgan.

I had a question on capital allocation. Your framework has been built on kind of balanced. And in this quarter, you obviously funded the Crimson acquisition with cash, but didn't do share repurchases this quarter. How should investors think about this trade-off?

And what is your appetite for share buybacks going forward, just given the valuation of the stock and some of the unique growth opportunities that you highlighted today.

Yes. So I actually wouldn't frame it as a trade-off. Our framework is indeed intentionally balanced rather than sequential and we allocate capital to the opportunity, we believe, creates the greatest long-term per share value for our shareholders.

So this quarter, we concluded that Crimson represented one of those opportunities. But that said, I wouldn't interpret the absence of share repurchases this quarter. Has any change in our philosophy or in our view of the intrinsic value of CRC, quite the opposite, and we continue to see compelling value in our shares at current prices.

And as you'd expect, while we're actively executing strategic transactions there are naturally periods when our ability to repurchase shares opportunistically that, that is more limited. But those are timing considerations, not capital allocation considerations. So opportunistic buybacks, they remain an important part of our capital allocation framework, and nothing about this quarter changes our view of the attractiveness of our shares.

Importantly, we have the balance sheet to support that flexibility. We're operating at approximately 1x leverage. We have no meaningful debt maturities for the next 7 years, and our revolving credit facility remains undrawn. So that gives us the flexibility to invest in those strategic opportunities like Crimson, but also maintain the capacity to be opportunistic across all of our capital allocation priorities.

Great. And my follow-up is just on synergy capture. -- you're ahead of plan on the Berry synergies already over 100% of your targeted synergies for the year. How should we think about broader savings beyond 2026, maybe through 2028. So maybe you could help us think about what's left to go in terms of G&A, operating costs and capital efficiency? And what can -- do you think we can underwrite in the model even next year?

Yes. So it's actually helpful to distinguish between the integration synergies and the structural operating improvements because we're increasingly talking about the latter. So the Berry integration itself, that's substantially complete, delivering more than 100% of our target 6 months ahead of schedule really demonstrates that.

And those implemented Berry synergies, they now represent more than $100 million of annualized savings. So that's approximately 14% of the deal value, which I think speaks to both the quality of the acquisition but also our ability to execute.

So more broadly, now we're entering the next chapter. We've already delivered about $400 million of the roughly $470 million target of cumulative synergies, but also structural cost reductions that we continue to see into 2028. So we're already about 85% or so of the way there. And what's changed is really the nature of the remaining opportunity -- the first phase was largely about integration, about eliminating duplicative costs. And the next phase, it's increasingly about optimizing the combined footprint operating these assets more efficiently together than independently.

And some example is really focused on infrastructure consolidation. So connecting additional Berry fields to our cogeneration facilities to reduce our purchase power costs, bringing stranded gas into our central processing facility to increase NGL recovery also optimizing oil blending and transportation, and we also continue to improve capital efficiency across the portfolio.

So we already demonstrated some of that playbook through the Aera integration, and now we're applying the same approach across the Berry assets. And many of those opportunities simply weren't available before those assets were connected.

If you think Arun about '27 and '28, I'd increasingly view the remaining synergies, the structural improvements to the economics of our platform rather than your traditional merger synergies. So those improvements really focus on lowering operating costs, on reducing our maintenance capital. And ultimately, that's improving our long-term cash flow generating ability for the business.

The next question comes from Octavian Jordan with RBC.

So for the first -- for our first question, -- so with CTV I now injecting CO2 generating revenue, how does the -- how does this milestone change the commercial outlook for the broader CTV platform? And how could programs like the reliable the RCPPP help accelerate future CCS and power opportunities in California.

Look, Octavian, thanks for the question. So yes, we're proud that our first-of-a-kind project in the state is now operational. So we're capturing and injecting about 270 tonnes of CO2 per day, converted to MCFs about 5 million cubic feet per day. And everything is performing as expected. We are on target to have an annualized number of about 100,000 tons per year of capture and storage.

So having this project live and operational really changes the conversations. So now potential customers, partners are not just evaluating our permitting know-how and our ability to move things down the line with the EPA. But also has a project that works and people can see and takes a lot of the mystery as to what CCS is.

So the way I would -- I would mention that the change in the conversation is really an increase in engagement. That's with technology providers with emitters. And you were starting to see some of these potential partners come to the table willing to fund portions of the pre-FID developments. So that's helpful, helps us be more capital efficient, ways to advance project, having many different potential customers trying to look for solutions to decarbonize their plans which is needed given that we're in a cap and invest market and it's very punitive to have any form of emissions.

The very encouraging progress has been on the RCPPP. It's a great front of the meter power market to decarbonize. It's a framework that recognizes natural gas generation and paired with CCS as clean and firm power. So the procurement for the state and ultimately what can be servicing the grid will be a way to add both reliability and low emissions, so that's a potentially really important step that expands the opportunity for us.

And we see a near-term opportunity of 2.4 gigawatts of power in the Central Valley that can be decarbonized. And that's just in the kind of the focal area that -- where we have our first permit, but we're working on permits throughout the state. So we see both the RCPPP as a big market signal and the operations of CTV I is really key to advance our carbon management strategy.

Got it. And just for a follow-up, you obviously highlighted the big -- the debt refinancing this quarter. How should we think about the capital structure going forward? And also why refinance now?

Thanks, Octavian. And you're right, we didn't have to refinance we chose to. Our philosophy is really to access capital markets from a position of strength rather than waiting until refinancing becomes a necessity. So the question for us wasn't whether we needed to refinance. The question was whether we could make an already very strong balance sheet even stronger.

And we believe the answer was yes. So the fact that we achieved the tightest credit spread in CRC's history that reinforced that we were executing from a position of strength.

And more importantly, we eliminated our only meaningful medium-term maturity and created a clean, long-dated maturity profile. So none of us know what financing markets will look like several years from now and we choose to remove that uncertainty and rather than carry it forward. So the result is a stronger balance sheet today than before the transaction and really greater financial flexibility.

At this point, I'd say our objective is to preserve the strength we've built. That allows us to spend less time managing the balance sheet and more time allocating capital to create long-term shareholder value.

The next question comes from Nate Pendleton with Texas Capital.

Congrats on the acquisition. Is there any update you can provide on Huntington Beach and how you're thinking about structuring that opportunity? I guess more specifically, what role could partners play there? How would a structure work -- and how do you expect to capture value from that asset?

Nate, thanks for the question. So we're making really good progress at Huntington Beach, and we remain on track to get a response from the city in terms of reentitlement sometime before year-end. So then the process goes to the California Coastal Commission and we expect that to run through 2028. So -- that is the key to unlocking value for Huntington Beach. We started the project in 2023. What we said is we're going to continue operating and producing the oil. It's about 3,000 barrels a day gross on that field and then systematically start the abandonment process. So we've done that.

But at the end of the day, it's the entitlement, that's the unlock the value. And so it's premature to talk about developer or capital structure we really want to wait until we get the reentitlement before we talk about that because otherwise, we're giving value away to the developer and want that value to stay with the CRC shareholders. So more to come, but we are making progress.

Understood. And then as my follow-up, perhaps for Clio, I wanted to go back to a prior question. You've talked a lot about capital efficiency and capital allocation as it relates to Crimson, but as you evaluate where to deploy capital across your growing portfolio internally, what metrics are you using to inform your decisions? And what metrics should investors really focus on externally?

That's a great question, Nate, because I do think some of our investors sometimes focus on different metrics than we do internally. And so one of the metrics people naturally compare across E&P companies is operating cost per barrel. And while that's certainly an important metric, it's not how we think about capital allocation. We spend much more time focused on the full cycle cost of replacing production and on the returns generated on every dollar of capital deployed.

And ultimately, that's really what drives long-term value creation. I also think it's important to step back and look at what's happening across the broader industry. High-quality upstream inventory is really becoming increasingly scarce. We're seeing that reflected both in recent M&A valuations as well as acreage transactions and whether companies choose to acquire inventory or develop it organically the cost of replacing production continues to increase, and that's where we think CRC is differentiated.

Today, our California drilling program is delivering new production at roughly $22,000 to $27,000 per flowing barrel, and that's actually below what we paid to acquire production through the Aera and Berry transactions. Those were already highly attractive at approximately $28,000 to $30,000 per flowing barrel. And it's materially below where many recent public transactions have completed.

So of course, replacement costs, it's only one part of the equation. And ultimately, what matters is the return generated on that capital. And that's where the economics here become really compelling. We continue to see those program level returns of approximately 4.5x MOIC, very high IRRs in the 60s and 70s percent.

And so those metrics capture the full cycle economics, they include our operating costs and they continue to comfortably exceed our investment thresholds. I'd say that's also why today's announcement on capital allocation and about spending less than what we're able to do is structurally improving really the economics of the business.

Every year going forward, a larger portion of our cash flows become discretionary rather than maintenance capital and it gives us greater flexibility to allocate capital where it creates the greatest value. So there's one framework I'd encourage investors to use is to focus on our full cycle economics of replacing production on the returns that is generated on that capital and ultimately on the free cash flow produced after sustaining the business.

And I think that's where CRC has become materially stronger over the last several years.

We have time for 1 more question from Emma Schwartz with Jefferies.

So where I wanted to start is stepping back, how do you think about CRC's long-term growth vision across E&P, midstream power and CCS. Can you talk a little bit about what your vision is for this company going forward? And then -- what is your position in California that specifically makes this integrated strategy really difficult for others to replicate.

Great question to wrap up. So the simplest way to think about it is we're building an integrated California energy platform with very high-quality assets that are nearly impossible to replicate. And we're finding ways to generate and grow cash flow on a contracted basis that ultimately grows the cash flow per share of the business. That is all wrapped around an improving outlook for California.

So the diversification that you see is not just diversifying for the sake of it. We're extending what we see as a market advantage. So let me break it down. California is the biggest economy in the U.S., a massive energy market, and it has significant barriers to entry.

We already own a lot of the critical infrastructure and assets, and we did so, again, with the purchase of Crimson we announced today, and we know how to operate here. So I wouldn't think about our business as four independent companies in E&P, midstream power and CCS, they really reinforce each other.

So every barrel that we produce, every pipe we control every megawatt we generate and every ton we sequester or is to strengthen the underlying asset position and builds a competitive advantage.

The other part of our strategy is that we're going to grow cash flow, but we're not going to -- we're not going to need to fund all the growth ourselves. We're taking a capital-light approach. So in areas like data centers and CCS, we bring a lot of the scarce assets -- and then we use third-party capital to grow around that base. So if you look at our portfolio and you look at every asset that we own, as you said, very difficult to replicate.

We spend time building close to 2 million-acre mineral position. We have over 200,000 surface acreage. We have a leading position on pore space multi-decade inventory for both oil and gas and now a significant midstream footprint, power assets, first Class VI CCS project, so it's that collection of assets that -- and the combination, that is our strength and the advantage. So we see this as a growth asset that is a great growth platform.

And beyond oil and gas, midstream data centers and CCS. These businesses command a higher multiple and typically command a higher multiple. So we see as a potential expansion in the re-rate of the multiple -- and that is what ultimately brings value to the shareholders.

Now in the meantime, because we're building a lot of these platforms, will continue to grow the dividend and being opportunistic on buybacks. We believe there's some meaningful gap between where our stock is trading today and the value of the business we're building. So that makes share repurchases a very attractive use of capital in the near term.

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

Thanks, everybody, for joining us. We look forward to connecting at some of the upcoming investor conferences. Have a great day.

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

Good day, and welcome to the California Resources Corporation First Quarter 2026 Conference Call. [Operator Instructions] Please note, 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 CRC's First Quarter 2026 Conference Call. Following prepared comments, members of our leadership team will be available to take your questions. I hope you have had a chance to review our earnings release and supplemental slides. We have also provided information reconciling non-GAAP financial measures to comparable GAAP measures on our website 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.

[Operator Instructions]

I will now turn the call over to Francisco.

Thanks, Dani. Good morning, everyone. We're off to a solid start in 2026 with unprecedented energy market volatility creating meaningful tailwinds and opportunities for our business. Before getting into the quarter, let me share a few thoughts on the macro environment and why CRC's business is well positioned to create value through the cycle.

Events across the Middle East have reminded the world of the importance of oil and energy security. Global supply chains have shown to be vulnerable and countries have been forced to seek reliable, diversified sources of energy.

While the United States has been relatively insulated due to our strong domestic production, California faces a unique and precarious position. Today over 60% of the oil consumed in California comes from foreign sources. In recent weeks, our state's inventories have been reduced by more than 20% as oil destined for California has been diverted to Asia at substantial premiums. The importance of in-state production has never been more critical, both to ensure supply and preserve affordability.

As the Golden State's largest producer, CRC is positioned to be the solution. Delivering local barrels that shorten the supply chain, lower transportation costs and associated emissions, and helping keep gasoline affordable for Californians.

CRC has a deep, primarily Brent-linked, high-quality inventory of oil development opportunities, and recent legislative efforts to improve permitting are proceeding as expected. Our recent mergers were well timed with transactions priced well below today's strip, and set a strong foundation for future growth. We're now deploying capital into these assets to drive disciplined long-term value.

California is starting to recognize that local production is essential to affordability, reliability and the state's climate objectives. And CRC is ready to support all three.

Today we're moving decisively to accelerate development. We are increasing drilling cadence this summer by three rigs: two in California and one in Utah. This will allow us to return to our long-term production maintenance capital program ahead of schedule and accelerate high-return projects to unlock value. In California, we're drilling new wells and adding capital-efficient workovers that will translate quickly into production. And in Utah, our highly contiguous acreage position provides meaningful upside that we have only begun to capture.

Let me spend a moment on the Uinta acreage because this opportunity is compelling. Since 2020, production in the basin is up 100%, reflecting both improved results at the well level and expanded more mature regional infrastructure. Recently drilled CRC and offset wells have substantially derisked our acreage, and we're planning to perform additional appraisal work. With over 200 gross Uteland Butte locations already in the portfolio and additional benches under consideration, we have considerable running room to support a scalable growth platform.

Our planned acceleration in activity to seven rigs will meaningfully enhance our financial outlook. For the full year, we are now targeting approximately 1% entry-to-exit gross production growth, and raising our adjusted EBITDAX guidance by over 40%, outpacing the expected rise in Brent. We're also increasing our Berry merger synergy target, which Clio will cover in detail in a moment.

Our carbon management business, CTV, is on the cusp of a historic milestone. We completed the construction and commissioning of California's first commercial-scale carbon capture and storage project at our Elk Hills cryogenic gas plant, and we expect to receive final notice of the determination from the EPA any day now.

That approval will clear the way to first CO2 injection, marking the first time in California's history that carbon emissions are permanently stored. It will also place CRC among a small group of U.S. oil and gas companies with active CCS operations. Put simply, this is a defining moment, not just for CRC, but for California's ability to deliver on its climate objectives while preserving energy reliability and affordability.

We expect carbon capture at our Elk Hills cryogenic gas plant to be the first of many more projects to come. Our storage reservoirs sit within reach of approximately 17 gigawatts of baseload power generation across California that we believe has the potential to be retrofitted for CCS. And we have submitted over 350 million metric tons of carbon storage capacity to the EPA, with additional reservoirs tracking for draft permits through 2026.

Our data center conversations continue to gain momentum. As previously announced, a top-tier national data center developer is investing several million dollars to accelerate early-stage site readiness and permitting at Elk Hills, a clear vote of confidence in the opportunity.

As AI transitions from training to inference and other states face mounting power constraints, tech's appetite for scaled clean power in California is growing. CRC is uniquely positioned to meet that demand. We can permit, deliver firm gas supply, offer available land adjacent to existing infrastructure and pair it all with CCS. Power is the binding constraint for AI growth, and we are one of the few platforms that can solve it.

On the Reliable and Clean Power Procurement Program, or RCPPP, we expect the next major update in the second half of 2026. Natural gas with CCS is not yet eligible, but support is building and 3 of 5 CPUC commissioners have publicly endorsed inclusion. California already offers some of the highest stackable CCS incentives globally. RCPPP eligibility would make the economics even more compelling.

Our enhanced 2026 outlook reflects the positive impact of these developments as well as the continued execution of our strategy. With that, I will turn it over to Clio to walk through our first quarter results and updated 2026 guidance. Clio?

Thank you, Francisco, and good morning. We delivered a strong first quarter with adjusted EBITDAX of $304 million, approximately 17% above the midpoint of our guidance, and we are raising our full year guidance. The combination of disciplined execution, higher oil prices and accelerated activity has improved our outlook for 2026.

In the first quarter, operating cash flow before changes in working capital was $247 million, ahead of our expectations and reflecting the stronger Brent backdrop relative to our previous guidance. Net production averaged 154,000 BOE per day, with oil at 81% of the mix and realizations at 96% of Brent pre-hedge, in line with plan. Adjusting for PSC effects, underlying production was in line with our quarterly guide.

G&A for the quarter was above guidance due to the timing of legal expenses and a higher cash settled equity compensation, reflecting share price appreciation. G&A is already trending down with further reductions driven by Berry synergies, which we expect to capture in 2026.

Total capital deployed in the quarter was $131 million, at the high end of guidance. The increased spend was by design as we pulled forward pre-spud timing on development wells and accelerated facility spend to support the activity ramp Francisco outlined. Even with that accelerated capital deployment, free cash flow before changes in working capital was $116 million, a strong start to the year.

In March, we priced a $350 million add-on to our 2034 notes. We upsized from $250 million with a book more than 5x oversubscribed and used the proceeds to redeem our 2029 notes. This extends our weighted average maturity to approximately 6 years, lowers our interest expense and further strengthens the balance sheet.

Net debt ended the quarter at $1.3 billion, with net leverage at 1.1x last 12 months EBITDAX.

We returned $46 million to shareholders during the quarter, including $36 million in dividends and $10 million in share repurchases, bringing cumulative returns since mid-2021 to more than $1.6 billion, a track record that reflects the consistency and the durability of this business.

Current conditions across domestic energy markets arguably provide the most constructive backdrop for our business and the industry that we have seen in quite some time. For the second quarter, we expect net production of 149,000 BOE per day, reflecting the impact of PSC effects at higher prices and a planned short maintenance window at our Elk Hills power plant. We expect capital deployment of approximately $130 million, reflecting increased drilling activity in June, G&A of $95 million, and adjusted EBITDAX of $390 million, assuming an average Brent price of $105 per barrel.

As usual, we provide both quarterly and full year sensitivities to Brent to help frame the impact of commodity price volatility. For the full year, we are raising our outlook across the board. We now expect 2026 exit gross production of 175,000 BOE per day, roughly 1% entry-to-exit growth and building momentum into 2027.

To deliver this growth, we are increasing full year midpoint of total capital guidance to $540 million. D&C and workover capital is $100 million above our prior plan, reflecting a second half ramp to a peak of seven rigs. Partially offsetting this increase is a reduction to facilities capital of $10 million, reflecting ongoing field level facilities rationalization.

Allow me to pull all of this together in one important comparison. We previously forecasted that our maintenance capital framework to hold production flat required seven rigs and approximately $485 million of D&C and workover capital. This year, and given our portfolio's flexibility, we are expecting to deliver entry-to-exit growth with an average of five rigs and D&C and workover capital utilization of less than $400 million. Fewer rigs, less capital, and we are now growing.

The return profile on our full year 2026 capital program is compelling. At current strip prices, we expect a multiple of approximately 4.5x on invested capital, up from 3.8x previously. And IRR is approaching 70%, roughly 40% higher than our prior estimate. We now expect full year free cash flow before changes in working capital to exceed $800 million.

Turning to Berry merger-related synergies. We have already implemented over 80% of our original target and are now raising that target by 12% or an additional $10 million. That's driven by field consolidation and contractor-to-crew conversion across the combined footprint. Our cumulative synergy and structural cost reduction target through 2028 now stands at upwards of $460 million.

We expect full year adjusted EBITDAX at a midpoint of $1.45 billion, assuming an average Brent price of $91 per barrel. This increase reflects both higher commodity prices and underlying margin expansion. Brent is up approximately 38% while our EBITDAX outlook has increased by approximately 42%, with a positive difference driven by high-return drilling, structural cost discipline and incremental synergies, all supporting higher cash flow per share. That gap between commodity upside and EBITDAX upside reflects the value of our integrated strategy compounding, and it is the kind of outperformance we can sustain through the cycle.

Cash flow per share growth, high-return reinvestment, a derisked balance sheet and structural margin expansion, that is 2026 in a nutshell. With that, I'll turn it back to you, Francisco.

Thanks, Clio. Before we open the line for questions, let me share a few closing thoughts. CRC remains a different kind of energy company. And this distinction could not be more evident. Our integrated strategy is delivering on three fronts at once: a low-decline conventional business accelerating into a stronger price environment, California's first commercial-scale CCS project on the doorstep of CO2 injection, and a power and data center opportunity gaining traction.

The path forward is clear. We're scaling activity across California and delineating the Uinta. We're converting structural margin expansion into cash flow growth. We're returning capital through a durable dividend and opportunistic buybacks. And we're advancing our leading carbon management platform.

Our priorities are unchanged: develop our resource base responsibly, unlock the full value of our portfolio, maintain a premier balance sheet, and allocate capital with discipline. That is how we create durable long-term shareholder value.

Operator, we're ready for questions.

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

Looks like you have it all coming together. You got the permit reform, you identified the inventory, now you've got the price. So this growth path, I think, looks pretty attractive. But I was wondering if you could walk us through the 2026 program as it is now, just give us a sense of when the rigs are coming on and how that translates into when the production actually shows up throughout the year. And if you can give a little bit of context too on the permits, whether or not you've got the permits in hand to execute it at this point.

Scott, thanks for the question. Yes, we came into the year looking to reestablish the permitting process, showcase the inventory and then the highly capital-efficient program. We think the updated 2026 guide reflects the progress on all these objectives. Let me explain.

So we're going to be drilling a total of about 357 new wells and side tracks for the year. Happy to report that we have all permits for all seven rigs now on hand and are working on our 2027 plan. Not only that are permits flowing, but the process overall is getting better. So with the permitting process being squared away, that allows us to focus back on more dynamic capital allocation.

And that's where we see an advantage versus maybe the shale peers in the rest of the country. We have a lot of flexibility to deploy capital and have very short time to market. So time to markets are very quick, from spud to production is roughly 30 days on average, although we can beat that number. And we don't have the same level of service intensity or competition for equipment and crews. So we can try to connect to a window of price opportunity and deliver incremental production that way. So we're lining the incremental rigs to be ready in the summer and start producing in the -- early in the second half of the year.

So then that allows us to focus on the overall picture, which is returning production to maintenance. We talked about and showcased that we have significant running room, 24 years of inventory. Our wells are performing extremely well. We're beating the type curve.

And you can see that in the numbers that Clio highlighted. Our entry production is 174,000 BOEs per day. Our exit is estimated at the midpoint to be 175,000 BOEs per day at the midpoint of the guide, and that's on a gross production basis.

Why do I mention gross production and not net? Because that's a cleaner measure of reservoir performance. Gross is unaffected by PSC cost recovery variability. We have the contract in Long Beach where it's subject to PSC mechanics. So you look at growth in terms of being able to measure that efficiency. So now you can also back out the PSC effects from net production and you get to the same shape; you're staying flat to slight growth.

But the really exciting thing that we're seeing come through as our team is executing is that we're staying flat with less rigs. So the improvement on capital efficiency has been significant. So let me turn it to Clio to highlight the capital efficiency and the returns of the program as well.

Scott, really on the efficiency point, the comparison here is really compelling. So on how much our program has improved relative to what we outlined just last quarter. We had talked about the seven rig program with about $485 million of D&C and workover capital. That would be needed to hold production flat next year, so in 2027.

And today what we're outlining is we're delivering that flat to modest growth with roughly five rigs throughout the year and under $400 million of D&C and workover capital. So that's a meaningful step up in the capital efficiency. We're getting more out of fewer rigs, less capital, and we're bringing that forward in time.

And most importantly there, that improvement is also showing up in our returns profile. And so the program-level returns, you're looking at roughly 4.5x MOIC, nearly 70% IRR, that's meaningful further increase from our prior program, which was already highly attractive.

I'll unpack that just a bit further. It's coming from a few places, three things really: well economics, cost structure and portfolio sequencing. So first, we're seeing better capital productivity at the well level, both in terms of cost and also early time performance. Second, we've structurally lowered our cost base and particularly on the field and facility side. And third, sequencing and timing here. We're simply deploying capital more efficiently across the year and across our broader portfolio.

So this isn't just one lever. It's a multiple of improvements compounding at the same time. And as you think about our activity increase here, Scott, the key is that it's tightly price-gated. So we remain capital disciplined at current strip free cash flow before working cap. That is expected to come in above $800 million this year. And we're also anchored to long-term pricing rather than near-term spot.

So at around $65 Brent, our four rig program was fully supportive and generates strong returns. And each incremental rig from there requires roughly $5 Brent increase and long-term pricing to maintain those returns. So what effectively does here is create a clear decision framework internally. Every step-up in activity has to meet our return threshold. So even in a stronger tape that we're seeing today, we're not chasing volumes. We're scaling only where returns justify it.

And as you move towards six rigs in California, we're underwriting that against something closer to a $70 or $75 Brent long term, which is broadly where the strip sits today.

And tying back to what Francisco was mentioning earlier, that framework, it's really enabled by the flexibility in the program. We can adjust activity quickly without putting really the base at risk. So key takeaway here, Scott, is it isn't a change in strategy; it's stronger execution and better economics.

Yes. I appreciate all the color. That was very helpful. My follow-up question is, is on Uinta Basin. And then maybe if you could step back for us and talk about why invest in Uinta, and how do you look at the long-term strategy of that asset?

Yes, Scott. So we're still in the evaluation stage of Utah. We have four wells that we want to drill before the end of the year. We have -- when we acquired Berry, we booked about 200 locations in -- but as you look at the stacked acreage and the horizontal development and what offset operators are doing, there's a lot more running room to go.

But ultimately, we're looking to unlock the best value. And the way to think about it going forward beyond the four rigs is we are considering full development, but we're also considering monetization. So I'd say we are not in a holding pattern anymore. We're going to make a decision coming up. But we see some compelling opportunities to delineate and advance the evolution and the understanding of that asset base. I wouldn't call it a core asset, our core is California, but we're still in that evaluation stage. We see the rest of the country struggling to find high-quality inventory. We think the Uinta will provide that.

And the nice thing for us is we attributed very low value to Utah in the very acquisition. So that leaves us with meaningful upside to unlock that best value. So more to come. For now, four rigs. We're still evaluating. Sorry, four wells, not four rigs.

The next question comes from Betty with Barclays.

I want to start first on the upstream and maybe unpack a bit on the capital efficiency improvement that you're seeing in '26 and how that's impacting 2027. 2026 guidance is a bit noisy just with the PSC effects, but you guys spoke to a lot of those investments is really showing up in the second half, and Uinta is not going to peak until first quarter of next year. So I'm wondering how much of the 2026 investment is going to show up in growth in 2027.

And then just on the CapEx side as well, is it fair to say that if you are at five rigs this year growing on the lower CapEx, is maintenance CapEx now lower than the $485 million before?

Yes, Betty. And yes, it's early to guide and to start locking in 2027, but I get the logic behind your question. We are definitely seeing capital efficiencies improve and lower the maintenance capital. I think that is evident in the guide today. We do see longer term seven rigs as the table stakes for the business. What that means is that is the view we have on the forward long-term baseline at mid-cycle pricing. Have, as Clio said, a lot of flexibility and we can adapt to market conditions, but from a planning perspective, we see seven rigs as what we want to invest in given the quality and duration of our inventory.

So in terms of the investment that we're making now, yes, the -- in conventional assets, you will see the shape of the wedge that peaks -- in this year, we invest, we peak next year, right? So a lot of the investment that we're making is not for 2026 exit, it's really for the benefit of 2027. And having a view towards the long-term price curve and seeing -- and also with our strong hedge book, that gives us confidence to deploy capital thinking into 2027.

Ultimately, 7-rig pace also yields a very resilient free cash flow profile. That allows us to have durable returns for shareholders. Ultimately, we'll have to look at a lot of elements as we start thinking about the rig deployment in 2027. So we have a great portfolio, a different mix of wells, different commodities that we can go after. I would not assume that we would -- seeing the split of 6 in California and 1 in Utah. That's still to be determined. But a total of 7 rigs is what we think as the long-term guide on baseline investment for the business.

Great. That's helpful. For my follow-up, I want to ask about the data center development. You spoke to you're working with a top-tier data center developer to find sites or develop sites in Elk Hills. Can you just speak to the scope of that partnership? Is it fair to think about the value accrued to CRC long term could be on multiple fronts from the value of surface acreage, gas supply, CCS, et cetera? And then just how are the conversations going in general to move the project forward?

Yes, Betty. So we're making really good progress. We have previously discussed the concept of land now, which means land that's permitted, it's powered, shovel-ready co-developed and, ultimately, adjacent to our Elk Hills facility. So we're getting the site ready and our data center partner is putting real capital behind the opportunity, investing several million dollars to accelerate the early-stage work.

So we see a lot of people chasing headlines trying to talk about hyperscalers and data centers. We're really focused on project delivery and accelerating durable contracted cash flows. So it's a good way to think about it as we have an integrated view on data centers, from natural gas supply, which we have at Elk Hills, to land, which we have over 200,000 net acres of surface and a lot of it is around Elk Hills, to also being able to provide power and then decarbonize those electrons. We think it's a very compelling one-stop shop opportunity. And we're focused on the delivery.

So you'll see more progress on the permitting, you'll see more progress on the advancement, and that's all coming together in a very nice way. We've developed a very strong core competency in being able to kind of navigate the California regulations. We've done it with oil and gas effectively, we've done it really well with carbon capture, and now we're going to do the same thing with data centers.

So our partner is adding a lot of value in that design in anticipation of what hyperscalers need. So it's a real and exciting project we're developing. And we'll be ready to announce the specifics a little bit further along, but we're seeing really good progress.

The next question comes from Josh Silverstein with UBS.

Nice update on the Berry synergy front here. And I like that you guys give the three different bars there to help kind of break those out, where they're coming from. Can you just talk about how these are starting to trickle in through the course of this year? Will you start to see it in 2Q? Or is it later on this year where those benefits really start to show up?

Josh, so yes, the integration with Berry is going extremely well. At this point, we've captured about 80% of the targeted synergies. We increased our target by $10 million, primarily in OpEx, and trending really well towards the cumulative target of $460 million of annual synergies between Aera and Berry. So the trajectory, the trend is all going very well.

So why the raise in OpEx? I'll give you a couple of examples. Our team is doing a fantastic job in field consolidation. So what that means is we're merging overlapping water and oil treatment facilities and ultimately also consolidating supplier contracts by leveraging our CRC infrastructure and vendor relationships. So that's going really well, probably better than anticipated.

We also have a big opportunity for automation. Both Aera and CRC were much stronger in automation than Berry. So now we can integrate the legacy Berry fields into our operational control center, which creates the scale and the automation that we need in the operating model.

I'll turn it to Clio to talk about more of the specifics. But one thing to also note, I see a lot of oil companies talking about AI and how they're incorporating AI into operations. We're working on the same things and same efficiencies, but those numbers -- those impacts are not quantified yet in our numbers, right? So there is some upside assuming technology advancement and implementation works, but everything else we're really doing is more physical movement and placement of facilities alongside with reductions in G&A. But I'll turn it to Clio to provide a little more context on the synergies.

Josh, I'll frame it from a broader financial perspective to start really on how those synergies benchmark and then look at your timing question and unpacking that. So on the benchmarking side, while the $10 million increase we announced today on the various synergies, that might look incremental in terms of absolute terms, it's actually quite significant relative to the size of the transaction. We're now roughly at 13% of deal value, which is well above what we typically see in the sector, where most of those transactions are in the mid-single digits, and more recently, we've seen deals trend even lower. So this is clearly a differentiated outcome. And importantly, it's consistent with what we delivered on Aera. So we view this as a repeatable playbook for us.

On the trajectory, we're largely through a lot of the action items. So we laid out last quarter that we had already delivered roughly $300 million of structural cost reduction and that ahead of schedule. This quarter, we've captured the 80% that Francisco was mentioning of our original Berry synergy targets. So we're well on our way.

And the durability of the model is really proven on the synergy capture. And that is what gives us confidence in the path forward on the longer term and our ability to get close to that $0.5 billion of cost reduction.

I'd say the remaining synergies that we're looking for are less about those one-time actions now and more about continuous improvement of the business, and you could expect those to come through more steadily over time. If you put it all together, it's really a sustained structural margin expansion story that's continuing to build. And you're already seeing that in our outlook where EBITDAX is growing ahead of the commodity price rise.

Got it. I was hoping to shift over towards the power business for you guys. And I wanted to see how you guys are thinking about the evolution of this business for you? Is it something that could grow? I know it's definitely being integrated with other parts of the business, but how are you thinking about this? And then maybe just kind of a broader overview of what you're seeing in the California markets.

Yes. California is fascinating. We keep seeing the same message. We just need more power in the state. And it needs to be clean, it needs to be reliable, it needs to be around the clock. And we're one of the very few companies that can go from molecules in the ground to electrons on the grid to carbon back on the ground. We think that's a big differentiator, and the geology and their expertise on subsurface is what makes it really difficult to replicate.

If you then look at the interconnection queues in California, it just takes longer than anywhere else in the country. And so that puts a scarcity premium, capacity that's already tied to the grid. So having those assets, it's very meaningful. We have close to 1 gigawatt of power under our portfolio.

But we're seeing some regulatory improvements. So the CPUC just started the procurement process of 6 gigawatts of new clean capacity by 2032. But what we really like to see is that 1.5 gigawatts of that is clean and firm. So that's the energy that we can provide, right, always on, dispatchable, zero emissions. So these are solar and batteries can fill that, it's gas, natural gas with CCS.

So in terms of the dynamics that we're seeing, we see a resource adequacy payments that are compressed today because you have a lot of this intermittent supply solar and wind that's flooding the market. But this new clean, firm requirement creates a structural demand for what we operate. So then the resource adequacy pricing is expected to follow and get stronger over time.

So ultimately, what we see in terms of power is the future natural gas with CCS. It's very California-specific solution. You might not be seeing that in other parts of the country. And you're expecting the CPUC to address it this year and moving forward. So we're well positioned either way, but we see a significant business opportunity as we think about California power dynamics.

The next question comes from Zach Parham with JPMorgan.

I wanted to ask on the buyback first. Buybacks were relatively smaller in 1Q at $10 million, and you bought back around $45 per share. So those buybacks were done mostly early in the quarter. The stock's moved quite a bit higher since, but so is the commodity, so you're going to still generate quite a bit of free cash flow this year. Can you just talk about how you're thinking about the buyback going forward?

Yes, Zach. So the first priority for this quarter was to get the activity production back to maintenance level. And the reason for that is that, that gets us to sustainable capital returns. And that duration is what we think the investor is really looking for. And you look at the track record, $1.6 billion of buybacks over the years. So very much a part of our portfolio to be able to distribute cash to shareholders.

So we continue to be very focused on that. It's just a matter of sequencing. So getting production back on track is -- was paramount, but the framework hasn't really changed since we started, right? So we want to be the company that you can own through the cycle, and that means good returns, steady returns as we go forward. So we will have to make the next decision right now that we're able to invest into a business to keep production flat, then the next opportunity to either grow from there or buy back shares or increase the dividend or ultimately accumulate more cash for that is something that we're going to have to continue to look at as we start thinking about the setup in 2027. But maybe let me turn to Clio to recap that framework and provide a little more of the specifics.

The way I'd frame it is higher prices don't really change our framework, but they do shift the mix of where capital goes with a lot of more naturally flowing towards high-return reinvestment in the base business, with us continuing to build that long-term optionality. But importantly, we're doing that within the same disciplined framework that we've held. So we're still running a sub-40% reinvestment rate on the E&P side. The business continues to generate significant free cash flow. And with our leverage that's already low, the balance sheet isn't a constraint. It gives us the flexibility to lean into those opportunities while generating meaningful excess cash.

And you asked about the buybacks, and I'll take a step back and saying shareholder returns more broadly, that remains a core part of our story. We've consistently grown the dividend over the past 4 years, and that yields around 2.5%, which we think is competitive both within the sector, but also more broadly.

And we'll continue to approach buybacks in a disciplined and opportunistic way. We think that's been very effective. If you look since mid-2021, we've returned via buybacks about $1.2 billion, $1.6 billion in total as Francisco was mentioning. And we executed that at a meaningful discount to the intrinsic value. So we repurchased shares at an average price of about $43.50, and that's roughly 30%, 40% discount to where we've been trading recently. And we've been able to also keep share count relatively flat even as our production has grown about 50% over that period of time. So you've seen us lean in and be opportunistic and be effective with that tool.

But even as we lean into our E&P investment, we're not stepping away from returns, we're simply delivering more. And we're really not making a trade-off here. It's a dynamic allocation. Capital flows to the highest-return opportunity, while supporting our shareholder returns and also maintaining our long-term growth options.

A follow-up I wanted to ask on the cost side. As you add back some activity, are you seeing anything on the inflation side? I'm sure you're seeing higher diesel prices have some sort of impact. But anything else you would flag from an inflationary standpoint?

Good question. I'd say at this point on inflation, it remains modest and really manageable for us within the business. So we saw minimal pressure in the first quarter. But you're right, as oil prices have moved much higher, we're starting to see some impact, primarily in oil-linked inputs.

But in terms of magnitude, we're estimating that's roughly $6 million to $8 million impact this year or $10 million on an annualized basis, so very manageable.

If you look at what's driving that, about 1/3 -- well, actually 3/4 is fuel related, so driven by higher costs across our field operations and logistics. And the balance of that, so 25% to 1/3, is oil-based products where we're seeing moderate supplier increases there.

But it's important to note that our team, we've done a significant amount of proactive work on the supply chain side, consolidating vendors, improving procurement, leveraging scale. And that really mitigates a lot of the exposure. So altogether, I'd say the level of inflation is modest so far and it's more than offset by the structural margin improvement we're delivering across the business.

The next question comes from Michael Furrow with Pickering.

I'd like to ask about risk management. Clearly it was a volatile quarter for pricing. It looks to probably continue in the second quarter. California market dynamics only add to volatility. When you look at the business today, the balance sheet is in a much healthier position than it's been previously. So does any of the market dynamic changes alter the company's hedging strategy moving forward?

Michael, so as I mentioned before, we want to build a company that the investors feel good about owning through the commodity cycle, the ups and downs of the cycle. So we see our hedging strategy as a great tool to deliver that and to ultimately lock in attractive economics so we can execute regardless of where prices go. I'll turn it to Clio for a little bit more details on the go-forward game plan.

So our hedging and our hedging program, it's really about being able to deploy capital with confidence. So it's about having the confidence in our returns in our capital program and our ability to really deliver through the cycle. It allows us to lock in attractive floor economics and also commit to higher levels of activity and participate in the upside.

Last quarter, we shared what the business generates at around $65 Brent, and that underpins how we think about both capital allocation and hedging. We did put these hedges in place in a different forward curve environment that was delivered at the time, protecting the base business, the capital program and the dividend and while retaining a lot of upside participation.

And if you look at our portfolio, that's how it's structured today. So in '26, roughly 2/3 of our volumes participate to the low to mid-80s Brent, and about 1/3 remains unhedged. So while we do have downside protection, we're not fully capped. Higher prices do translate into stronger margins and free cash flow across a meaningful portion of our portfolio.

And if you look beyond '26, that exposure increases. So there's about 40% in '27 and roughly 80% in '28 of our volumes that are unhedged.

I'd say stepping back, that visibility is what has allowed us to commit to the activity levels and to the returns we're outlining today. And the objective of that hedging program hasn't changed. It's about protecting the downside while maintaining meaningful exposure to the upside.

Staying on the topic, in the first quarter, volatility weighed on the post-hedge realized pricing, and at least for us, our numbers, negatively affected our EBITDA expectations. But looking forward, does that same timing dynamic that was a headwind for the first quarter act as a tailwind for 2Q?

So what you're looking at there in terms of GAAP is we're really settling our hedges on a monthly basis. And if I look at the Street, I think most analysts are doing so on a quarter basis. So an average quarterly price will not reflect what happened, for example, in Q1 where you had January and February in the high-60s and then March with the high 90s. So I believe that, that's what's driven most of the delta, if not all of the delta. If you do that average quarterly price versus the month-to-month, that yields, for example, a $30 million to $40 million delta in EBITDA alone for that quarter. So I do think that that's something that our IR team can work to make sure that we are closely calibrated.

And the last two questions today will come from Nate Pendleton with Texas Capital.

Congrats on the great update. Francisco, I wanted to go back to the RCPPP potential briefly. Could you provide a bit more detail about what the next steps are for that to be implemented and how that could impact demand for your CTV pore space and perhaps even your in-state natural gas volumes?

And if I may add one more part to that, with the potential program, are you already having conversations with companies trying to get ahead of implementation?

Nate, so yes, we see RCPPP as being a game changer if it passes. It's a very unique front of the meter opportunity. It's the recalibration of a grid that has been struggling to keep up over reliance on solar, wind and batteries when you really need that firm capacity to come back into play, and a state that focuses on decarbonization and reducing the carbon footprint very few ways to go and nothing really tangible other than carbon capture. So we see this as an incredible opportunity.

The policy rule-making is advancing. We saw, as I mentioned earlier, call for procurement, 1.5 gigawatts of firm and clean, which really limits the pool of opportunities that we think -- I said CCS is the most tangible one. But you look at -- you step back and you look at about -- California has about 40 gigawatts of power generated through natural gas-fired generation. I assume that not all of all them will be able to be retrofitted with CCS. So our view is about 17 -- call it, 15 to 20, 17 midpoint, gigawatts, would be good candidates for retrofit, right? So you can start scaling the magnitude of the program.

So we will have the ability to participate primarily in the transport and storage of CO2. But we also have the input, which is natural gas and we can grow that and have a dedicated natural gas flow of low-methane emission, very high-caliber or natural gas going in, that ultimately all goes into the calculation around carbon intensity. So we can provide a very scalable, big offering.

And then we've seen progress, as a reminder, the CO2 pipeline moratorium was lifted earlier this year. So that allows us to start thinking about that transport in a much more tangible way.

And then you come back to our Elk Hills project, we're at the doorstep of getting that permit from the EPA. We look at the project management dashboard, there's no red left in that dashboard, right? We're done, commissioned, we sent the samples into the EPA. They have been checked and confirmed to be adequate. So we're just waiting for that final approval.

I think that is the final signal to the market that CCS is here, that we were able to clear all permits and have been able to make it to commerciality, and we see demand follow. We are having conversations. We do see a lot of interest, as the CPUC considers CCS, we see a significant uptick in those conversations on how do we get the CO2 from the point source into reservoirs. So massive front-of-the-meter opportunity, very tailored towards a California solution, a unique business model and one we're extremely well positioned on.

Perfect. And then as my follow-up on the regulatory side, it seems you have been able to navigate the regulatory and permit process extremely well with the receipt of permits for the 2026 program and already working on '27. So can you comment on how your discussions with regulators have been to open up the permitting process? And could you share your views on the ongoing governor's race given the potential impacts to the industry more broadly?

The governor's race, okay. Yes. On the first topic, we -- it truly is an incredible team effort from our folks in State Capital in Sacramento to our permitting team in Bakersfield. And there's been incredible progress throughout.

Our view towards California is different than other energy companies. We're working to establish partnerships, to provide solutions, to be innovating alongside with the state. And that's giving us an opportunity to work very constructively with regulators and politicians. And ultimately, our track record really to deliver projects that no one else can really puts us into a place of -- or really good placement on a go-forward basis.

So really proud of what the team has been able to do. And it is a core competency. It's something that we do exceptionally well, better than most, and ultimately creates an incredible market opportunity if we continue being really good at it.

In terms of the governor's race, June 2 is the jungle primary, so the top two candidates regardless of the party move on to a general election in November. Ultimately, it's a fascinating dynamic with a lot of candidates that could ultimately end up as governor, so fairly open. Our view is we can work with all candidates. We support some campaigns and candidates that have a little bit more in tune with rational energy policy. We really want to focus the politicians on protecting and creating local jobs. And ultimately, we can partner and solve the affordability crisis in the state.

So exciting times to have an election, and we're watching it closely. And looking for leadership that will continue to collaborate and make the state better going forward.

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

Great. Thank you, everybody, for joining us today. We look forward to seeing many of you on the road at upcoming investor conferences in the coming weeks. So thank you, and have a great day.

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

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.

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 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?

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.

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.

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

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.

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?

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.

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.

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.

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 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?

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.

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?

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.

The next question comes from Zach Parham with JPMorgan.

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?

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?

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.

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?

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.

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.

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

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?

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.

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?

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.

The next question comes from Josh Silverstein with UBS.

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?

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.

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?

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.

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

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?

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.

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.

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.

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

Good day, and welcome to the California Resources Corporation Third Quarter 2025 Earnings Conference Call. [Operator Instructions] Please note, this event is being recorded.

I would now like to turn the conference over to Joanna Park, Vice President of Investor Relations and Treasurer. Please go ahead.

Good morning, and welcome to California Resources Corporation's third quarter 2025 conference call. Following prepared remarks, members of our leadership team will be available to take your questions. By now, I hope you have had a chance to review our earnings release and supplemental slides.

We have also provided information reconciling non-GAAP financial measures to comparable GAAP measures on our website and in our earnings release. We will also discuss our pending Berry merger. We encourage you to read our Form S-4 filed on October 14, 2025, as it contains important information. Copies of this and other relevant documents are also available on our website and the SEC's website.

Today, we will 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 1 primary and 1 follow-up as this allows us to get to more of your questions.

I will now turn the call over to Francisco.

Good morning, everyone. CRC delivered another strong quarter, reinforcing the disciplined performance and strategic focus that set us apart as a different kind of energy company and also positioning us at the forefront of California's energy revival.

We have a lot of good news to share this morning. Here's how we're going to structure the call. First, we will open with a list of accomplishments and summarize important recent events. Next, Clio will discuss our third quarter results. Lastly, we will share some early thoughts around 2026.

Let's start with the highlights. California's energy and regulatory environment is improving in meaningful ways and CRC is well positioned. The recent passage of key legislation has created the most constructive framework we've seen in more than a decade, strengthening oil and gas permitting, authorizing CO2 pipelines and extending the Cap-and-Invest program through 2045.

Together, these laws help support reliable in-state production while encouraging investment in the state's rapidly rising energy demand. CRC's E&P, CCS and Power businesses can support California's need for energy security and clean energy solutions. Our E&P business continues to perform exceptionally well. Our teams are executing safely, and our assets are demonstrating strong production performance and low base declines.

With our successful Aera integration behind us, we can now move our annual base decline assumption to 8% to 13%, which is down from 10% to 15% previously. This significant change strengthens our cash flow generation, improves our capital intensity and enhances the value of our large PDP reserve base. CRC's conventional reservoirs are advantaged with significantly higher estimated ultimate recoveries, when compared to shale resource plays. As many of the Lower 48 producers are moving towards lower quality locations, we are well positioned with long duration, high-quality, low-decline reservoirs.

We believe that this will allow us to effectively replace reserves, maintain production with less capital and deliver consistent results through the cycle. Strong execution and smooth integration remain key strengths of our operating teams. We recently announced our merger agreement with Berry Corporation. Like Aera, this deal was well timed is progressing as planned and will add assets that are adjacent to our current positions, creating meaningful synergies that further enhance our leading operational scale in California.

Through Aera, we demonstrated our ability to effectively integrate assets, improve operating efficiencies and rapidly capture value. We plan to apply that same approach to Berry. Turning to our Carbon TerraVault business. Momentum continues to build. We are well ahead of the competition and close to making history at Elk Hills with our first CCS cash flows.

Our first carbon capture and sequestration project at our Elk Hills cryogenic gas plant is advancing with construction underway and first CO2 injection expected in early 2026, pending regulatory go ahead. This will be California's first commercial-scale CCS project and a critical step towards realizing the state's decarbonization goals.

Now that the CO2 pipeline moratorium has been lifted, our strategically positioned CTV reservoirs across the state have the potential to provide storage solutions for existing brownfield emitters that don't have the benefit of colocation, creating a true statewide framework for emissions reduction. We are also advancing our regulatory efforts in permitting inventory to expand our statewide storage network.

We currently have 7, Class VI permits under active review with the EPA and are preparing additional applications totaling 100 million metric tons across Central California. As we focus on the most attractive markets for CCS, one thing is clear, California's biggest opportunity lies in delivering clean, reliable power.

The California Public Utilities Commission estimates that incremental power capacity in the state will need to double by 2035 to meet demand. Later on, the projected investment in AI inference targeting major population centers, and it's clear that California is heading towards a substantial power shortfall. While renewable resources and scalable battery storage have a role, they will not be enough to satisfy demand.

California needs clean, reliable baseload power to enable data center growth, while ensuring a reliable grid. State leaders recognize this challenge and have proposed several pathways to address it. With CCS, CRC and CTV are well placed to be part of the solution. Google recently announced plans to deploy natural gas generation with carbon capture for their Illinois data centers.

Here in California, the Energy Commission recently issued a report highlighting that pairing natural gas generation with CCS is a practical and scalable path to the carbonized baseload power across the state's legacy assets. It's clear that leading innovators share this vision, and so do we. CRC and CTV have an unequal portfolio of assets located in the heart of the nation's largest economy.

We can readily pair existing power generation with carbon capture to rapidly unlock firm, clean baseload power in proximity to major demand centers. We are evaluating multiple opportunities today in this rapidly expanding market. First, utility and wholesale markets, where front of the meter sales could provide decarbonized baseload power directly into the grid to support system reliability and reduce emissions under the CPUC's newly proposed reliable and clean power procurement program or RC BBB.

Second, we can help meet demand from existing large technology and data center operators. Based on PG&E's interconnection queue, data center request in California have now exceeded 10 gigawatts, reflecting surging energy needs tied to AI, cloud computing and electrification across the state.

As the AI revolution advances from training to inference, data center sites are expected to shift from prioritizing areas with cheap abundant electricity to low latency areas near major population clusters. As the largest state in the nation with nearly 40 million people and 4 of the top largest U.S. cities, California screens extremely well.

As we evaluate our options, it's important that we do the right deal at the right time to create the most value for our shareholders. We're focused on turning an evolving market opportunity into real progress. And earlier today, we took another important step in our natural gas power with CCS strategy in Kern County, as we announced a new partnership with Capital Power to develop carbon management solutions for the La Paloma power facility.

This builds on our previous announcements with Hall Street and our own project, CalCapture and Elk Hill. These partnerships validate market demand expand scale from front or behind the meter data centers and highlight CRC's ability to connect firm power generation with carbon storage.

With strong execution, disciplined growth and a constructive policy environment, CRC is well positioned to lead California synergy come back, one that values both reliability and responsibility. Clio, over to you.

Thanks, Francisco. This quarter's operating performance once again exceeded expectations, underscoring CRC's consistent execution operational strength and financial discipline, the hallmarks of our strategy. For the third quarter of 2025 we delivered net production of 137,000 BOE per day, 78% oil, roughly flat quarter-over-quarter on a $43 million D&C and workover capital program.

Realizations remained above national averages. Oil at 97% of Brent, NGL at 60% of Brent and natural gas improving to 113% of NYMEX. We generated adjusted EBITDAX of $338 million and free cash flow before changes in working capital of $231 million, reinforcing the durability and efficiency of our operating model. G&A and operating costs were within guidance and our hedge portfolio continued to provide downside protection, while preserving margins. Capital investment for the quarter totaled $91 million, squarely within plan.

In October, we raised $400 million on attractive terms to refinance Berry's debt ahead of the pending merger. This financing demonstrates our ability to quickly capitalize on favorable market conditions, strategically enhance our balance sheet by lowering costs and extending duration and maintain leverage below 1x.

These proactive steps kick start our synergy capture and position us well for a seamless integration once the merger closes. Our balance sheet remains a key strength. At quarter end, net leverage is at 0.6x and total liquidity exceeded $1.1 billion, including $196 million of cash and an undrawn revolver.

In October, we used available cash to redeem the remaining $122 million over '26 senior notes at par. Since then, we've rapidly rebuild our cash balance, ending October with more than $170 million, excluding the high-yield proceeds reserved for the very closing. We have no near-term debt maturities. The next comes due in 2029.

Rating agencies have taken notice. Moody's upgraded CRC's corporate family rating to Ba3 and Fitch assigned a positive outlook, citing our consistent cash flow generation, low leverage, disciplined capital allocation and the improving regulatory environment in California.

In addition, our borrowing base was reaffirmed in October at $1.5 billion, while existing and new lenders increased their elected commitments by $300 million to $1.45 billion, further enhancing our financial flexibility. CRC's balance sheet and capital framework remain among the strongest in our sector, giving us flexibility to fund disciplined growth, while sustaining meaningful shareholder returns.

During the quarter, we increased our dividend by 5%, reflecting continued confidence in our business and cash generation. Year-to-date, we returned more than $450 million through dividends and share repurchases. Under our current authorization, we have over $200 million of remaining capacity for share repurchases through mid-2026.

The fourth quarter is shaping up extremely well. We expect to benefit from continued stable production, lower costs and new efficiencies. Capital spend will be modestly higher than in the third quarter, mainly reflecting the catch-up of deferred projects and a strategic scope change to our CCS project at CRC's Elk Hills cryogenic gas plant.

As we've advanced this project, we've identified an opportunity to upgrade facilities to serve both Belridge and Elk Hills. Improvements that enhance NGL recovery and increase operational efficiency as we prime the facility for carbon capture. This once again demonstrates our team's innovative approach and our focus on value-enhancing initiatives through integration.

Importantly, full year capital expenditures are still expected to remain within our previously disclosed annual guidance range of $280 million to $330 million. As we look ahead, CRC is poised to enter 2026 with a premier balance sheet, a flexible capital structure and a resilient production base, all supporting durable free cash flow and long-term shareholder value.

Furthermore, roughly 2/3 of our expected 2026 production is hedged at a Brent floor price of $64 per barrel, ensuring the stability of our cash flow. Our preliminary 2026 plan assumes an average of 4 rigs supported by our strong hedge position and our inventory of existing permits. We plan to operate these rigs using both current permits and those expected following SB 237 enactment.

As always, we will remain disciplined and agile, adjusting our capital program as commodity prices and market conditions warrant. Importantly, our current outlook does not yet include the impact of the pending Berry merger, where we anticipate meaningful synergies once the transaction closes. CRC remains focused on consistent performance, disciplined growth and competitive shareholder returns as we move into 2026.

And with that, I'll turn it back to Francisco.

Thanks, Clio. 2025 is proving to be a remarkable year for CRC with strong momentum as we head into 2026. We're posting wins across multiple fronts. Robust reservoir performance, the structural improvements in our portfolio, lower cost, a more resilient capital structure and greater alignment between industry and the state to achieve common goals.

For the second consecutive year, we will grow our production through strategic transactions and disciplined reservoir management. More importantly, we expect these actions to position us for sustained cash flow per share growth in 2026 and beyond.

We're excited about what lies ahead from closing and integrating Berry to advancing Carbon Teravault and CalCapture and expanding our power and CCS partnerships. Together, these initiatives will allow us to unlock meaningful value for our shareholders. Our focus remains clear, creating considerable and sustainable value for shareholders.

We believe California is entering a new era for locally produced energy, one defined by abundance, affordability and sustainably produced solutions. California's energy landscape is improving and CRC intends to play a leading role in that transition. CRC is a different kind of energy company. Operator, we're now ready for your questions.

[Operator Instructions] Our first question comes from Kalei Akamine from Bank of America.

I want to start with the MOU on -- with Capital Power. It's been our view that brownfield emitters power plants in your vicinity would need to get involved to underwrite the CTV development. So yesterday's announcement in our view was a positive step.

My question concerns your PPA efforts from this going forward. 200 megawatts, one could argue that maybe it's not big enough, but if you're collaborating with others and presumably, there's more megawatts on offer. So as you think about developing in this business, there are others in the area that you can perhaps pull into this joint effort. So maybe just kind of stepping back, can you talk about maybe next steps for the PPA?

Kalei, thanks for the question. Yes, we -- the market is getting hot. We're seeing far more opportunities today than we did 12 months ago. And I think the -- as we mentioned in the remarks, having 1 of the hyperscalers, Google going into natural gas powered with CCS is similar to when you hear the hyperscale is going into nuclear, right?

So it's a big moment. It's a big market signal. So the vision that we've had for Kern County, which is on Slide 7 on our deck, is to build a hub for -- to serve their data centers or the grid but at big scale.

And yes, our CalCapture project, our excess power at our own plant is a big component to that. It's an anchor element to it. But now we're -- as we move with partnerships with both Capital Power and Hall Street, we're putting a significant scale on the map.

So as these hyperscalers are looking now for more inference, low latency you have a site here that can serve the LA market at scale and decarbonized. So it's coming together. It's coming together nicely and it's the story of not only building data centers or increasing power, which is what everybody is looking for. But we're particularly well positioned on both the gas supply, natural gas supply that we have in basin.

But also take away the CO2 emissions and store them on our side. So it's a nice integrated project and with great partners like Capital Power is a fantastic independent power producer. I think the signal is CCS is here, and this site is going to be an attractive place for us to grow that power demand.

So excited about the next steps. And yes, there's a lot more to come. I think the site continues to -- we continue to find ways to grow different power elements to it and the things are coming together nicely.

I appreciate that, Francisco. Maybe for the next question, going to your '26 soft guide you highlight a 2% entry to exit decline. When I think about your assets, projects like floods require some time to activate a production response. So I'm wondering about the cadence of that decline. Is it isolated to maybe the first half of the year, while second half of '26 firms up as those projects come to bear?

Yes. It's really been building an exceptionally good 2025 in terms of reservoir delivery and the team's performance in managing the assets. We will have -- our plan is to have 4 rigs on 1/1. So January 1, by then, we would have 4 rigs running and no, we expect that to be the entry to exit plan as we lower our base decline assumptions, we're putting capital back to work, primarily in the form of workovers and sidetracks permits that we have in hand. We expect that to be a fairly steady performance throughout 2026.

Our next question comes from Betty Jiang with Barclays.

It's really great to see the momentum across the portfolio. My first question is on the upstream side on the PDP decline. It struck me that your PDP decline improved from 10% to 15% to 8% to 13% since like this natural decline don't typically change. So can you just speak to what's driving that improvement? Is that a function of the portfolio or anything else you're doing operationally?

Yes, it's a combination of things. It really is an answer that has several components, Betty. But it's first of all, it's owning great assets and conventional assets are just good rock in assets that our team knows how to manage really well. So as we move the decline rates and now that we are a year plus with the Aera assets, and we can see that this team can really bring the most out of it, we feel comfortable changing the corporate assumption.

In terms of tangible things that the team is doing, if you look at 2025 and the composition of our activity, a lot of it was focused on injection and injection at Belridge. So with pressure support in these great reservoirs the oil flows nicely. So the Belridge field is performing extremely well, an asset that we acquired from Aera.

We also, on Elk Hills, it was more about technology, and it's about remote surveillance. So it's -- I mean, it's an AI component of being able to identify wells when they fail and quickly repair those wells, right? So any well that's down, it's cash flow. So our team has been seeing some improvements in that surveillance and that leads us to be able to manage the down list that you have in conventional assets and manage that more effectively.

So and those are the 2 biggest fields. So Belridge and Elk Hills, if you're able to move those reserves, those decline rates shallower that cascades to the rest of the portfolio, right? So -- and it's really just -- I mean, I really want to comment on the team's performance. I mean, they are just completely on the ball and doing the right things in terms of managing the asset base.

So that's how you get conventional assets to perform better. It's just this blocking and tackling, it's things like surveillance, things like injections that ultimately pay off big dividends.

Great. My second question is on the Kern County decarbonized power opportunity. As you highlighted in Slide 7, it's really great to see the capital power MOU. But what strike me also is this emerging hub of opportunities that's in Kern County with multiple power plants on top of the CO2 reservoir.

So can you speak to the vision that you see that's emerging in this area? How could a potential hub decarbonized power scenario could look like? And what needs to happen to really catalyze that development?

Yes, Betty. So a lot of things have come together very nicely. So -- but it's also a reminder that the California market operates different than other parts of the U.S. Here, you have a lot of the infrastructure already exists. And it's been -- natural gas fired generation has been sidelined as more and more renewables have come in.

But then if you take the growth expectations of California power, right? So where we're looking to double in 10 years and triple in 20 years, that growth is not going to be all served by renewables and batteries. So you're going to have to bring in baseload, you're going to have to bring baseload at scale. So we have the ability to take these plants in retrofit for CCS to make them decarbonize so they can participate in this growing market.

So in Kern County alone, and this is all very close to our -- either within our field boundaries or next to it, we see 2.4 gigawatts of power generation that could serve a growing market. Now when we also saw pipelines, the more autonomous CO2 pipelines being lifted, that brought forward that brownfield idea that we had and b, we're now able to connect -- we'll be able to connect these power plants with our storage sites.

And as you see on the map, these are very short distances and some 5 to 20 miles for all these power plants to be able to get to one of our reservoir. So we're building scale on power. We're building scale on emissions. On an aggregate basis, we see about 5.5 million tons of emissions from these plants. And if you look at our inventory of permits, we're up to about 9 million tons that we are in some part of the permitting process all in the Central Valley.

So it's all coming together. The big part that we were waiting for is that market signal. And the market signal already talked about Google, but also California is looking for decarbonized power, understanding that we're going to have to bring incremental sources. And we feel retrofit of existing plants that are already there producing power is going to work much better and faster than having new build of any power generation in California, right?

So really well positioned to create this hub. L.A. is within 100 miles, 100 miles is important because of latency requirements as you look for inference. So this is all starting to take shape, where before we talked about a single site with single pore space. Now you can see that it's multiple sites, multiple plants and third parties are coming -- looking for a solution that only CRC can provide.

Our next question comes from David Deckelbaum with TD Cowen.

Francisco, Clio and Omar and team on several of the milestones achieved to date. I'm probably going to ask you more questions around a lot of things you're going to be asked on today. I want to go back to just the PDP decline. Curious like as we approach sort of year-end reporting for Francisco or Omar, how you think about are we recovering more oil in place at this point with performance revisions? Or are we shifting more recovery into earlier parts of the reservoirs economic life at this point?

David. I'll turn it to Omar to give any incremental highlights. But yes, these are some of the largest oil fields in the country. And if you look at oil in place, they are in the billions of barrels of oil in place. If you look at the ultimate recovery factors, these are sandstones that have both good permeability and porosity.

So the ability to, in a lot of cases, maintain pressure support or to go through a bypassed oil enhances those recoveries. But -- so this is different than shales, right? Shales is all about drilling and completion and about how effective can you make that single event of drilling.

Here, you're managing the reservoir and now that we have both permits and a very strong backdrop or from our ability to allocate capital to these projects, we're able to really work on life of field plans to maximize that output, bring a lot of that production forward. But maybe I'll turn it to Omar to see if he wants to add anything.

Yes. Thanks, Francisco. And thanks for the question, David. One thing I would add to Francisco's comments is just where we are with these reservoirs in their life cycle. We have a long history of operating these reservoirs. So we have steamfloods that started steaming back in '70s, waterflood back in '80s.

And the point I'm making is that we understand the behavior very well. So there are very little surprises as you manage PDP. And then you can look for incremental opportunities to shallow the decline. And it's basic blocking and tackling with the EOR projects, you're not going to get 2,000 barrel wells, you have a lot of 20, 30 better wells that you manage well and you work on them to gain another barrel or 2? And just given the number of wells they add up to a shallower decline.

So the 2 things that Francisco mentioned earlier, we have been focused on improving the injection side of EOR, both in steamfloods and waterfloods. That was most of the work we did in the first half of the year. And then we are focused on getting to the wells that fail quicker through technology. And AI is a big help. It's eliminating a lot of human error. It's eliminating a lot of human lag and we are getting to those opportunities faster.

So it's never a single silver bullet. It's a combination of all these factors. Where we are in the reservoirs life cycle where the declines are very predictable. Application of basic blocking and tackling and leveraging technology.

And then maybe Francisco, can I ask on just the high-level thoughts on the '26 plan, which I think was a pleasant surprise for everyone, just given the capital efficiency. It appears as you kind of approach a maintenance level, I'm curious as with the pending opportunity now for increased permits. It seems like your approach to capital allocation is still very much rooted in maximizing free cash per share, if I have that correct.

And I guess how do you think about that in the context of now more or less receiving a call from local governments to increase production in the state?

Yes, David. It's a great question. So you're absolutely right. Our focus is on growing cash flow per share. And so you do look at production as 1 of the components, but it's not the only one. So the way we're thinking about 2026 is a disciplined ramp-up on capital and we have a lot of flexibility.

And 1 of the things that we talked about, the type of assets that we have, but the ownership of the assets, it's also create a key advantage that we have. We own 100% of our fields. And so we controlled the spend depending on the commodity cycle. So it allows us to be very efficient. And as you make these assets better, as we've talked about, then your capital deployment becomes 1 of the highlights -- so the way we thought through it is, as we look for the best and optimal way to grow cash flow per share, it's really through a combination of drilling and also leaving cash to that we can opportunistically buy back shares, right?

So I think the combination of 2 -- of the 2 with a foundation of a very, very strong hedge book, we have 64% of our oil hedge into 2026. And that's only going to improve once we close the deal with Berry. So that gives us a really good place to start delivering we need to showcase the inventory, and we have a significant runway of great inventory to go after.

But we've been in a permitting constrained scenario, right? So the reactivation needs to be measured, thoughtful discipline in a way that we can showcase what this business is capable of. But you're right, in terms of the signal from the government is we need more California production. We need more Kern County production in particular. So as the state is looking for increased activity in Kern County, we will look to participate as we look to, first, grow cash flow per share and look for inventory that gets developed.

We will look to participate and our contribution is going to be to effectively double our rig count for now. But we'll continue looking and we'll obviously have to see where oil prices are. We'll have to see where our share prices are as we continue to think about capital allocation. But the way we are leaning into 2026, it's a good balance between buybacks and investing in our business.

Our next question comes from Josh Silverstein with UBS.

Maybe just sticking on the decline rates. You had previously discussed around a 6 to 8 rig, $500 million capital program in order to keep production flat. Now that you've had this reduction in the base decline rate I was curious if you could just kind of give us some color as to what that new maintenance level may be for CRC going forward?

Josh. Yes, I mean, we're below $500 million, clearly. I think with our 2026 preliminary guide. That's the number that you can triangulate around. Now as we mentioned, these numbers do not include the Berry assets. So as we bring -- we closed the Berry merger, we'll refresh that number inclusive of their assets and we'll provide a full corporate number to maintain -- the maintenance capital to keep production flat.

But on a stand-alone basis, so CRC and Aera assets given the improvements that we showcased in the earnings call today, we're clearly now below $500 million. We've seen Berry be able to maintain their production, total capital, and that's all of the capital with about $70 million, but we need to be able to close the transaction and provide a refresh to the market, but the baseline assumption is improving.

Got it. And then it's been a while since we've gotten an update on the Huntington Beach assets and what you guys are doing there and what the permitting and that process looks like. If you could just provide an update, that would be great?

Yes, absolutely. So things continue to progress well with Huntington Beach. We've made a number of public filings around preliminary development plans, 800 units that could be ultimately built at the site, once it's fully approved. That's all part of the process of engaging with the City of Huntington with all the local and regulatory agencies around the project.

So things are marching forward. We have a dedicated rig abandoning the wells there as we go. We continue to produce, we have abandoned the wells as we get all the permitting lined up. As we said before, we think this project is going to be ready 2028 time frame. That doesn't mean that there's not a monetization sooner. But as we looked at this project in the past, the -- as you re-entitle the land for its best use, which is residential housing and you are able to abandon the -- abandon the wells, you're going to get to an optimal price, where the market appetite will be there.

We provided guidance on the cost around $200 million to $250 million to abandon the property. That was a 2023 number. We have already made number of abandonments. So that number will come down as we look for that point to monetize the asset in 2028, but things are progressing well.

Our next question comes from Nate Pendleton with Texas Capital.

Congrats on yet another strong quarter. Looking at Slide 8 with your existing power generation portfolio and with some of your investments to date, can you talk about your willingness to lean further into the power generation space beyond Elk Hills such as additional plan ownership or additional investment in some more leading-edge power generation solutions?

Nate. So I would say for right now, the focus is going to be on the feedstock, which is natural gas, low methane emissions gas and certified -- third-party certified gas, which we think is going to be very attractive and we're the largest natural gas producer. And then on offering a CCS solution on the back end. And that's the way we're positioning the company.

I don't anticipate owners of -- ownership of natural gas combined cycle plans beyond what we have at this point. We are looking for other ways to bring power forward, things like fuel cells and geothermal, there's a lot of prospectivity in California for -- for geothermal, there's a lot of appetite on fuel cells to have a CCS solution.

So we're looking to see what's the right mix of providing this both the carbonized, but also baseload power that we need to be able to serve the growing market. So -- but we are the solution on CCS, and we are the feedstock on natural gas. That plays to our strength, and that's where we're going to continue to advance. And as we continue to bring some of these ideas forward more and more technologies, more and more hyperscalers. I think we'll start looking at what we have and to build that vision for a Kern County power platform that we talked about earlier.

And as a follow-up from an earlier question on connecting the emitters on Slide 7 with the recently passed legislation. Are there any underutilized pipelines right of way around those assets that could be brought in-house or repurposed to serve as the connective tissue there?

Yes, absolutely. So as you look at Slide 7, and you can see that we showcased the footprint fairly well that has both the fields and the current pipelines. So you can see that this is -- these are right of ways that are owned either by CRC or by other E&P companies. These fields are adjacent to ours sort of these power plants are also adjacent to ours.

So it's a particularly good place to be able to decarbonize this whole kind of micro grid. And so definitely, there's advantages as we talked about, we own a lot of land. We own a lot of surface ourselves and that we have partnerships with others that own that land as well. So -- so this is something that -- now that we have the moratorium on [ pace ] lifted, that's what we were really waiting on to be able to connect all of these assets, and that's what we're working with Capital and Power and others to try to figure out.

Our next question comes from Noel Parks with Tuohy Brothers Investment Research.

I have a couple of questions. So sort of as a reality check, how long has it been, since you've had the activity levels at Elk Hills that you're going to be ramping up into starting next year?

Yes. We've been in a permitting constrained environment, since the beginning of 2023. So the improvements that we've had in the past few months around the regulatory framework is a significant milestone for the company. Now we have been able to execute capital workovers and sidetracks effectively over that time, but it's new well bores that we haven't had permits to pursue. But now we have SP 237, so a brand-new law that not only allows for permits in kern County, but it also gives us duration.

So it's effectively a 10-year tied to the Kern County EIR. So a 10-year runway -- so how much -- when the last time we had as much support and as big of a runway, it's been a very long time. So as we mentioned in our slides, and I think we mentioned publicly before, the state is looking for local production to ramp back up to about 25% of the supply of the state. We've been trending down over the years.

We used to be 40%, 50% of the local suppliers, local E&P companies to the state. That's trended down to about 22%. So the call from the government is to bring more of that California low CI production. And so meaningful changes and meaningful improvements and in terms of the stage view towards local production and as the leading producer in the state. We have -- we want to do our part to help stabilize the fuel markets and look forward to bringing more production forward.

Great. And I'm just sort of thinking that there are so many irons in the fire and different types of catalysts you have at work right now. And with sort of the message of trying to the need to double the state's power production by 2035. So when do you foresee a ramp-up in production for your gas assets as you look ahead?

Yes. It's a function of capital allocation, where the best returns are. And if we look at our 2026 plan with the 4 rigs, we're going to focus on primarily oil. About 80% of the anticipated contribution from '26 activities is oily. So that means 20% gas and NGLs. So that's just a matter of where we are in terms of the returns, again, supported by a very strong hedge book. We see great returns in the projects, the returns that we've outlined before.

So natural gas will come if we get either stronger natural gas prices or we have supply agreements to all these groups that need power. Certainly, that will be the call to drill more gas. We have a lot of prospectivity. We have -- we're sitting on these great basins. And depending on what you are in the state, you could have heavy oil in the shallow reservoirs and then deep gas, a few thousand feet below that, right?

So -- you have a lot of stacked pay and a lot of flexibility in how you can run the assets and allocate capital. So we're looking for where the best returns are. And right now, we're seeing them in oil. But as again, as the market demand changes or increases in particular for natural gas, we will be ready to also pursue some gas on a go-forward basis.

[Operator Instructions] Our next question comes from Leo Mariani with ROTH.

I wanted to ask a little bit about on the capital plan for 2026. So as you're talking about running 4 rigs continuously for roughly $280 million to $300 million of D&C plus workover capital -- but if I just look at your kind of E&P spend in 2025, it was 200 -- I think it's $245 million to $275 million for kind of 1.5 rigs. So just the proportion seems a little bit out of whack there. So can you kind of help me just kind of square up the numbers a bit there?

Yes. I think you may be mixing Leo total capital versus D&C. So the D&C for '25 is lower. We have like you said, 2 rigs, and we didn't start the year with 2 rigs. We stepped into 2 rigs later. We do have a different facility spend and the facility spend that we talked about in this quarter, which is to bring the NGL project forward from Aera.

And so what we're doing is we're building a pipe from Aera to Elk Hills to bring rich wet gas to Elk Hills run it through our cryogenic plant and extract the 1,000 barrels of NGLs. It's a particularly good project because it just follows the natural gas that's already in place. It's just a more efficient way to extract incremental value from the project. But in terms of the D&C numbers, they're definitely lower for 2025. I don't know, if -- what is the number, Clio?

Yes, absolutely. Leo, you're comparing, obviously, our total capital versus what we're disclosing here related to the activity pickup. But for 2025, capital, we're effectively lining up to stay within our guidance. We haven't changed that. And that spend is all encompassing. It includes, obviously, the oil and gas spend as well as our carbon management spend and so that's where you're seeing the delta here as well as our corporate level spend.

But going forward, there's definitely significant capital efficiencies those gains have been through the merger with Aera, consolidating those gains has been the story for 2025. And in 2026, you're seeing that come through in the numbers and the efficiency that we're able to get from that capital spend in the $280 million to $300 million range, that's really yielding a very significant arrest of the decline.

Okay. And is that largely going to be workovers, which maybe are less capital intensive? Is there kind of a component of new drilling there? Do you have an estimate of that? Just trying to kind of get this a little bit apples-to-apples here?

Yes, 2026 will be -- will continue to be primarily workovers and sidetrack. Roughly speaking, 60%, 70% of the D&C will be in that category. So the rest would be in new wells as new permits start coming in for those.

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

Thank you. Thanks, everybody, for joining us today. We really look forward to seeing you in upcoming investor conferences during the winter season. Thank you so much.

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