California Resources Corp (CRC) Q3 2026 Earnings Report, Transcript and Summary

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.