CRC

This article first appeared on GuruFocus. - Net Production: Averaged 152,000 barrels of oil equivalent per day, with oil at 80% of mix; up 2% quarter over quarter and ahead of expectations. - Adjusted EBITDAX: $341 million, above the top end of guidance and consensus. - Operating Cash Flow (before working capital changes): $300 million. - Free Cash Flow (before working capital changes): $142 million. - Total Capital Spend: $158 million, within guidance. - Oil Realizations: 91.3% of Brent before hedges, at the low end of guidance; expected to improve to about 92% in Q4. - NGL Production: Increased approximately 1,000 net barrels per day (about 10% quarter over quarter) from processing additional Belridge gas at Elk Hills. - Natural Gas Realizations: About 119% of NYMEX Henry Hub, exceeding guidance. - Electricity Margin: $35 million, exceeding guidance on stronger power demand. - Operating Costs: $386 million, up $39 million from Q2, driven mainly by higher energy costs; Q4 cost initiatives expected to reduce operating costs by approximately $10 million. - G&A: Declined 16% from Q1 to $89 million (including $1 million from Crimson); adjusted G&A declined 20% to $79 million. - Shareholder Returns: $66 million returned, nearly half of free cash flow before working capital changes $36 million in dividends and $30 million in buybacks; dividend raised 4% (fifth consecutive annual increase). - Net Leverage: 1 times, with $1.3 billion of liquidity. - Q4 Outlook: Net production of about 151,000 barrels of oil equivalent per day at $102 Brent; adjusted EBITDAX of about $316 million; total capital of approximately $120 million (including $8 million for 2027 drilling preparation). - Full-Year 2026 Outlook: Adjusted EBITDAX of roughly $1.34 billion at $92 Brent; net production averaging about 152,000 barrels of oil equivalent per day (a record for CRC). - 2027 Plan: Six-rig California maintenance program targeting flat gross production from entry to exit on $450 million$475 million of D&C and workover capital; production expected to be second-half weighted. - Synergies and Cost Reductions: More than $400 million cumulative over four years across G&A, operating cost and capital, ahead of schedule and above initial targets. - Warning! GuruFocus has detected 4 Warning Signs with CRC. - Is CRC fairly valued? Test your thesis with our free DCF calculator. Release Date: November 03, 2026 For the complete transcript of the earnings call, please refer to the full earnings call transcript. - California Resources Corp (NYSE:CRC) delivered strong Q3 2026 results with production of 152,000 boe/d (80% oil), adjusted EBITDAX of $341 million, and free cash flow of $142 million, all exceeding guidance. - The Crimson acquisition closed, adding ~2,000 miles of pipeline and critical infrastructure; restarting the San Pablo Bay pipeline in Q1 2027 is expected to improve oil realizations toward the mid-90s and enhance flow assurance. - California Resources Corp (NYSE:CRC) signed an MOU with Bloom Energy to develop 1+ GW of clean, firm power using fuel cells with carbon capture, leveraging its land, gas, and carbon storage assets with third-party financing. - The company increased its dividend by 4% (fifth consecutive annual increase) and repurchased $30 million of shares, returning nearly half of free cash flow to shareholders; it has ~$570 million remaining under its buyback authorization. - California Resources Corp (NYSE:CRC) achieved over $400 million in cumulative synergies ahead of schedule and launched a new organization-wide cost reduction review targeting 2027-2028, with early wins from AI and digital tools. - Oil realizations were 91.3% of Brent in Q3, at the low end of guidance, due to transportation constraints and repricing of short-term contracts, though improvement to ~92% is expected in Q4. - Operating costs rose $39 million quarter-over-quarter to $386 million, driven by higher energy costs as SoCal border gas prices more than doubled and diesel prices increased. - A Kern County Superior Court ruling set aside the environmental impact report and approval for the CTV1 carbon capture project; California Resources Corp (NYSE:CRC) plans to pursue legal actions, and the impact on existing operations is uncertain. - The Uinta asset sale is expected to close by year-end 2026 for net proceeds of ~$100 million, removing production and cash flow, though proceeds will be redirected to higher-return California investments and shareholder returns. - The Golden Valley data center project faces a 12- to 18-month permitting timeline, with a hyperscaler MOU targeted for early 2027 and a draft PPA later in the year, creating uncertainty around timing and commercial terms. Q: Can you walk us through how the 1-plus gigawatt Bloom Energy opportunity gets developed, who the customers would be, and what the economics look like?A: CEO Francisco Leon explained that the MOU with Bloom Energy combines Bloom's modular fuel cell technology with CRC's natural gas, land, infrastructure, and carbon storage. The model involves third-party power developers or private equity owning and financing the projects, while CRC supplies gas, hosts the sites, provides grid-connected infrastructure, and has CTV transport and permanently store the CO2. Target customers include investor-owned utilities, municipal utilities, community choice aggregators, and hyperscalers, with sites being considered across the CTV platform in both Southern and Northern California. Q: What is the San Pablo Bay pipeline restart timeline, what work remains, and when will the realization and cash flow benefits show up?A: CEO Francisco Leon said the pipeline is ready to restart and requires no additional permits or capital, with a target of Q1 2027. The remaining work is finalizing logistical and commercial flexibilities, including potential waterborne access through Bay Area terminals. CFO Clio Crespy added that each percentage point of realization improvement is worth roughly $40 million of annual EBITDA at about 120,000 net barrels of oil per day and $90 Brent. Q4 2026 realizations are guided to about 92% of Brent, and a more meaningful contribution is expected in the second half of 2027. Q: What is the status of the Golden Valley data center project on permitting and customer conversations, and is it a proof of concept for future projects?A: CEO Francisco Leon said the California Office of Land Use and Climate Innovation issued a notice of preparation, starting the permitting clock, with a permit expected in about 12 to 18 months. The initial campus is 275 megawatts behind the meter using power from CRC's operating plant, with an existing PG&E interconnection for backup. CRC is targeting an MOU with a hyperscaler in early 2027 and a draft PPA later in the year, with Beacon funding early-stage development. Q: What does the Belridge-Elk Hills gas connection tell you about other reintegration opportunities, and how much incremental capital would they require?A: CFO Clio Crespy said the two-way integration is recovering about 1,000 additional barrels per day of NGLs, double the initial expectation, while Elk Hills gas fuels Belridge steam generation and reduces purchased gas. She said many more opportunities are being evaluated on the gas, power, and facility sides, but capital requirements vary widely and no aggregate number is ready yet. Projects will be prioritized on incremental cash flow relative to investment and execution risk. Q: What is Phase 2 of the organizational improvement program, why is now the right time, and what are the potential tailwinds?A: CEO Francisco Leon said Phase 1 brought the companies together, while Phase 2 is about designing how the combined company should work. The focus is standardizing systems and data, removing remaining duplication, and deploying AI and digital tools, with early wins including real-time production monitoring at Belridge and well-screening tools for workover candidates. Savings are expected to build through 2027 with most of the impact in 2028, and specific targets will be shared with 2027 guidance. Q: How should we think about the 2027 production shape under the six-rig program and what it means for capital efficiency?A: CEO Francisco Leon said CRC is targeting flat gross production from entry to exit in 2027 on $450 million to $475 million of D&C and workover capital, with production second-half weighted as the six-rig program ramps. He noted conventional wells take about 30 days from spud to production but 6 to 12 months to peak. Legacy CRC would have needed about eight rigs and $150 million more for the same outcome, and new production costs are about $27,000 per flowing barrel. Q: How do you decide where to commit CRC capital versus bringing in third-party partners, and how should investors judge value creation?A: CFO Clio Crespy said the key is selectivity, with every investment competing against reinvestment in the existing business, share repurchases, and balance sheet strength. CRC expects to be compensated for contributing land, gas supply, power, infrastructure, and carbon storage even when little new cash is required, through commercial agreements, partnerships, or ownership participation. Investors should judge CRC on the value created, capital committed, and cash flow generated rather than ownership percentages or size. Q: How should we think about buyback pace in Q4 and into 2027, especially with Uinta proceeds coming in?A: CFO Clio Crespy said CRC bought back $30 million of shares in Q3 at an average price of $53.50 and has repurchased roughly $470 million over the past two years. About $570 million remains under the authorization through the end of 2027. She said CRC can both reinvest in the business and buy back shares, and will continue to weigh share valuation against investment opportunities, cash generation, and balance sheet strength. Q: What is the outlook for the electricity margin in 2027 ahead of the Golden Valley PPA?A: CFO Clio Crespy said investors should use approximately $30 million to $40 million of annual electricity margin as a normalized reference for the existing business, before any PPA or contribution from Golden Valley or RCPPP. The $35 million generated in Q3 reflected favorable summer market conditions and should not be annualized. The bigger opportunity is converting that earnings potential into long-term contracted cash flow. Q: What are the remaining milestones at Huntington Beach and how is remediation progressing?A: CEO Francisco Leon said the Huntington Beach Planning Commission is finalizing study sessions in November, with a hearing expected in December and a city council vote targeted for January. The proposal includes up to 800 homes, 350 hotel rooms, retail, dining, and public open space, followed by Coastal Commission review expected to run through 2028. CRC has completed about $30 million of abandonment costs since 2024 and is on track to plug all idle wells by year-end 2028, while about 80 active wells producing roughly 3,000 barrels per day gross will remain. Q: What are the implications of the Kern County ruling on well stimulation treatment permits?A: CEO Francisco Leon said the For the complete transcript of the earnings call, please refer to the full earnings call transcript.

California Resources just dropped its Q3 2026 scorecard and the crowd flinched. The stock slipped about 2% today, yet the headline number was robust adjusted EBITDAX of US$341 million with free cash flow of US$142 million, both healthy figures for a California oil and gas producer. Market traders are reacting to recent share weakness and short-term emotion. The financials point to a business still generating meaningful cash while carrying net leverage of roughly 1x and US$1.3b of liquidity. This sets up a sharper debate between fear of past losses and confidence in current cash generation. Love California Resources' free cash flow engine but uneasy about recent share weakness and short-term emotion in the price? Compare that profile against our 34 high quality undervalued stocks to see how other cash generative stocks with solid balance sheets stack up. - Revenue (Q3 2026 vs. Q3 2025): US$421 million vs. US$878 million (a decline of about 52%) - Net Income / Loss (Q3 2026 vs. Q3 2025): loss of US$315 million vs. profit of US$64 million (a swing into a sizeable loss) - Basic EPS (Q3 2026 vs. Q3 2025): loss of US$3.55 per share vs. profit of US$0.76 per share (a sharp earnings drop per share) - Total Oil Equivalent Production (Q3 2026 vs. Q3 2025): 13.57 MMboe vs. 12.44 MMboe (output up about 9%) Prefer clean visual charts instead of another wall of dense financial text? View California Resources' full share price performance, volatility profile, and related valuation context in an easy-to-read dashboard through our company report for California Resources. One big promise around California Resources is that California focused projects will steadily turn infrastructure and carbon assets into more stable cash flows. "The main factor that would need to go right is continued execution on California focused projects, from Crimson pipeline integration to Golden Valley data center power and ongoing CCS build out, while keeping costs and permitting on track." Q3 shows real milestones. Crimson is closed with San Pablo Bay restart targeted for Q1 2027, CTV Elk Hills is already injecting CO2, Golden Valley permitting moved forward, and adjusted EBITDAX reached US$341 million with US$142 million in free cash flow, even while hedging losses pulled reported earnings into a US$315 million loss. One Narrative disagrees with today's price. → See where this Narrative says California Resources should trade. Bearish investors argue that California Resources can talk up its integrated platform yet still leak value when logistics or contracts misfire. "...the recent marketing disputes and takeaway bottlenecks that built about 1,500 boe/d of unsold oil and cut roughly US$25 million from quarterly adjusted EBITDAX show that this integration can still translate into higher operating costs and weaker differentials, which can pressure net margins if replicated." The latest quarter does not fully clear that hurdle. Adjusted EBITDAX landed at US$341 million with solid free cash flow, yet realizations sat at 91.3% of Brent and transport constraints again weighed on pricing. The US$315 million reported loss driven by hedging shows earnings quality still feels fragile when execution or financial choices misfire. California Resources shows that earnings headlines and share price moves can diverge for investors. The real opportunity could be in stocks that might be undervalued before the market reassesses them. - Company 1 - 18% below our estimate - targets hyperscale data centers needing dense, low-power NAND to handle surging AI workloads. - Company 2 - 45% below our estimate - converts a large backlog of data center and modular projects into high utilization for specialized mechanical and electrical crews. - Company 3 - 28% below our estimate - embeds custom chips and connectivity hardware at key digital choke points as data traffic strains existing infrastructure. That is three of the list. See all 34 potentially undervalued companies → This article is general in nature and was produced with the assistance of AI automation, based on data and analysis from Simply Wall St. We provide commentary based on historical data and analyst forecasts only using an unbiased methodology and our articles are not intended to be financial advice. It does not constitute a recommendation to buy or sell any stock, and does not take account of your objectives, or your financial situation. We aim to bring you long-term focused analysis driven by fundamental data. Note that our analysis may not factor in the latest price-sensitive company announcements or qualitative material. Simply Wall St has no position in any stocks mentioned. Companies discussed in this article include CRC. Have feedback on this article? Concerned about the content? Get in touch with us directly. Alternatively, email [email protected]

Image source: The Motley Fool. Tuesday, Nov. 3, 2026 - Vice President of Investor Relations - Daniel Juck - President and Chief Executive Officer - Francisco Leon - Executive Vice President and Chief Financial Officer - Clio Crespy Operator: 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. Daniel Juck: 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. Francisco Leon: 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. Clio Crespy: 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. Francisco Leon: 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: [Operator Instructions] The first question comes from Scott Hanold with RBC Capital Markets. Scott Hanold: 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? Francisco Leon: 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. Scott Hanold: 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? Francisco Leon: 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. Clio Crespy: 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. Operator: The next question comes from Betty Jiang with Barclays. Wei Jiang: 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. Francisco Leon: 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. Wei Jiang: 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? Francisco Leon: It should be about 12 to 18 months. Wei Jiang: 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? Francisco Leon: 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. Operator: The next question comes from Josh Silverstein with UBS. Joshua Silverstein: 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? Clio Crespy: 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. Joshua Silverstein: 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? Francisco Leon: 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. Operator: The next question comes from Arun Jayaram with JPMorgan. Arun Jayaram: 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? Francisco Leon: 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. Arun Jayaram: 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? Francisco Leon: 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. Clio Crespy: 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. Operator: The next question comes from David Deckelbaum with Stifel Financial. David Deckelbaum: 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? Clio Crespy: 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. David Deckelbaum: 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? Clio Crespy: 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. Operator: The next question comes from Nate Pendleton with Texas Capital. Nathaniel Pendleton: 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? Clio Crespy: 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. Nathaniel Pendleton: 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? Francisco Leon: 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. Operator: And the last questioner today will be Scott Gruber with Citigroup. Scott Gruber: 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? Clio Crespy: 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. Scott Gruber: 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. Francisco Leon: 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. Operator: This concludes our question-and-answer session. I would like to turn the conference back over to Francisco Leon for any closing remarks. Francisco Leon: Thank you. 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. Operator: The conference has now concluded. Thank you for attending today's presentation. You may now disconnect. Before you buy stock in California Resources, consider this: The Motley Fool Stock Advisor analyst team just identified what they believe are the 10 best stocks for investors to buy now… and California Resources wasn't one of them. The 10 stocks that made the cut could produce monster returns in the coming years. Consider when Netflix made this list on December 17, 2004... if you invested $1,000 at the time of our recommendation, you'd have $342,020!* Or when Nvidia made this list on April 15, 2005... if you invested $1,000 at the time of our recommendation, you'd have $1,270,017!* Now, it's worth noting Stock Advisor's total average return is 885% — a market-crushing outperformance compared to 208% for the S&P 500. Don't miss the latest top 10 list, available with Stock Advisor, and join an investing community built by individual investors for individual investors. See the 10 stocks » *Stock Advisor returns as of November 4, 2026. This article is a transcript of this conference call produced for The Motley Fool. While we strive for our Foolish Best, there may be errors, omissions, or inaccuracies in this transcript. As with all our articles, The Motley Fool does not assume any responsibility for your use of this content, and we strongly encourage you to do your own research, including listening to the call yourself and reading the company's SEC filings. Please see our Terms and Conditions for additional details, including our Obligatory Capitalized Disclaimers of Liability. The Motley Fool has no position in any of the stocks mentioned. The Motley Fool has a disclosure policy. Cal Resources (CRC) Q3 2026 Earnings Call Transcript was originally published by The Motley Fool

- Interested in California Resources Corporation? Here are five stocks we like better. - CRC beat third-quarter expectations, with production averaging 152,000 barrels of oil equivalent per day and adjusted EBITDAX of $341 million. It forecast fourth-quarter adjusted EBITDAX of about $360 million and full-year adjusted EBITDAX of roughly $1.34 billion. - The Crimson acquisition added about 2,000 miles of pipeline, and CRC plans to restart the San Pablo Bay Pipeline in early 2027 to improve crude access and realizations. Management estimates each one-percentage-point improvement in oil realizations could add roughly $40 million in annual EBITDA at the stated production and oil-price assumptions. - CRC is expanding into power and carbon management, including a proposed 1-gigawatt-plus fuel-cell and carbon-capture initiative with Bloom Energy. It returned $66 million to shareholders in the quarter and ended with 1-times net leverage and $1.3 billion in liquidity. - Crypto Bill Stalls, Smart Money Calls: Time to Buy the Dip? California Resources (NYSE:CRC) reported third-quarter 2026 production, cash flow and adjusted EBITDAX above its expectations, while outlining plans to expand its California-focused infrastructure, power and carbon-management businesses. President and CEO Francisco Leon said the company closed its acquisition of Crimson, agreed to sell its Uinta assets and increased its dividend for a fifth consecutive year. He said CRC is shifting from integrating acquisitions to optimizing its larger operating platform through additional cost reductions, standardized systems and digital tools. → L3Harris Stock Took a Beating—Is a 20% Rebound Next? - Blueprint for a Boom: SEC Clears the Crypto Runway "We have built a strong foundation. Now we are focused on getting more value from it," Leon said. Net production averaged 152,000 barrels of oil equivalent per day in the third quarter, with oil accounting for 80% of the production mix. Production rose 2% from the second quarter and exceeded the company's expectations, according to Executive Vice President and CFO Clio Crespy. → LyondellBasell's Dividend Looks Safer, But a New Risk Could Change That - Blueprint for a Banking Fortress: Circle Redraws the Map Adjusted EBITDAX totaled $341 million, above the top end of guidance and consensus, while operating cash flow before working-capital changes was $300 million. Free cash flow on the same basis was $142 million. Total capital spending was $158 million, within guidance. Oil realizations were 91.3% of Brent before hedges, at the low end of the company's guidance range. Crespy said short-term contract repricing and transportation constraints limited the company's access to higher-value markets. CRC expects realizations of about 92% of Brent in the fourth quarter. → Marvell Eyes a Swing for the AI Networking Fences as Markets Weigh Lumentum Price Tag Operating costs increased $39 million sequentially to $386 million, largely because SoCal Border natural-gas prices more than doubled from the previous quarter and diesel costs rose. The company expects cost initiatives to reduce fourth-quarter operating costs by about $10 million. Adjusted general and administrative expense fell 20% to $79 million as Berry-related synergies took hold. Reported G&A declined 16% from the first quarter to $89 million, including $1 million from Crimson. For the fourth quarter, CRC expects net production of about 151,000 barrels of oil equivalent per day at $102 Brent, including Uinta assets pending their anticipated sale by year-end. It projects adjusted EBITDAX of about $360 million and total capital spending of approximately $120 million, including $8 million for 2027 drilling preparation. For the full year, the company is targeting adjusted EBITDAX of roughly $1.34 billion at $92 Brent and average net production of approximately 152,000 barrels of oil equivalent per day. Leon said the Crimson acquisition added roughly 2,000 miles of pipeline, as well as Line 100 and storage assets, giving CRC greater control over how it moves crude to market. The company's immediate priority is restarting the San Pablo Bay Pipeline in the first quarter of 2027. The restart is intended to restore northbound crude access, broaden the potential buyer base and improve flow assurance. Leon said the pipeline is ready to restart and does not require additional permits or capital to return to service, though the company is finalizing commercial and logistical arrangements. CRC expects the reopened system to support oil realizations trending toward normalized levels in the mid-90% range of Brent over time. Crespy said that, at approximately 120,000 net barrels of oil per day and $90 Brent, each one-percentage-point improvement in realizations would represent roughly $40 million of annual EBITDA, excluding transportation savings and third-party midstream earnings. The company expects a more meaningful financial contribution from the San Pablo Bay Pipeline in the second half of 2027 as shipments and commercial agreements ramp up. CRC also filed a formal complaint with the California Public Utilities Commission related to transportation disruptions and plans to seek recovery of associated losses, though no potential recovery is included in its outlook. CRC plans to operate a six-rig California maintenance program in 2027, targeting flat gross production from the beginning to the end of the year. The company expects to spend $450 million to $475 million on drilling, completions and workovers. Leon said 2027 production should be second-half weighted as the company ramps its sixth rig. He characterized the expected production profile as flat to slightly declining early in the year, followed by a second-half recovery. The company said its 2026 California drilling and workover spending is tracking at about $355 million. Crespy said new production is being developed at approximately $27,000 per flowing barrel, with expected returns of about 70% and a multiple on invested capital of about 4 times, based on actual 2026 results and end-of-October strip pricing for future production. CRC also highlighted integration opportunities between its Belridge and Elk Hills fields. Since early July, it has processed additional Belridge gas at the Elk Hills cryogenic plant, increasing net natural-gas-liquid output by approximately 1,000 barrels per day, or about 10% sequentially. The company is evaluating similar connections across its asset base. Separately, management said it will conduct an organization-wide review targeting additional organic cost reductions in 2027 and 2028. CRC plans to provide updated targets with its next earnings release. CRC announced a memorandum of understanding with Bloom Energy covering the potential development of 1 gigawatt or more of clean, firm fuel-cell power with carbon-capture and storage capabilities. Under the proposed model, third-party power developers would own and finance the fuel-cell projects, while CRC would supply natural gas, land, infrastructure and carbon-storage services. The company said it is evaluating sites across its Carbon TerraVault platform in Northern and Southern California. Leon said potential customers include investor-owned utilities, municipal utilities, community choice aggregators and hyperscalers. At the Golden Valley Technology Hub in Elk Hills, CRC and co-developer Beacon submitted a project permit application to Kern County. Leon said the California Office of Land Use and Climate Innovation issued a notice of preparation, beginning the permitting process. CRC expects the process to take roughly 12 to 18 months. The proposed initial campus would include 275 megawatts of behind-the-meter power from CRC's existing Elk Hills plant. Management is targeting a memorandum of understanding with a hyperscaler in early 2027 and a draft power-purchase agreement later that year. On carbon management, CRC submitted a Class VI permit application to the Environmental Protection Agency for its CTV VIII project, bringing total submitted storage volumes above 400 million metric tons. CRC returned $66 million to shareholders during the quarter, including $36 million in dividends and $30 million in share repurchases. The company repurchased shares at an average price of $53.50 and has approximately $570 million remaining under its buyback authorization through the end of 2027. The company ended the quarter with net leverage of 1 times and $1.3 billion of liquidity. It also extended its $1.5 billion credit facility to 2030 and previously extended senior-note maturities to 2034 and 2035. California Resources Corporation (NYSE: CRC) is an independent energy company focused on the exploration, development and production of oil and natural gas in California. Its operations are concentrated in the state's San Joaquin and Los Angeles basins, where the company produces crude oil, natural gas and natural gas liquids for industrial, commercial and transportation markets. In addition to conventional oil and gas production, California Resources is developing carbon-management projects through its Carbon TerraVault business. This instant news alert was generated by narrative science technology and financial data from MarketBeat in order to provide readers with the fastest reporting and unbiased coverage. Please send any questions or comments about this story to [email protected]. The article "What California Resources (CRC) Said on Its Q3 Earnings Call" was originally published by MarketBeat. View MarketBeat's top stocks for November 2026.

California Resources (CRC) just released third quarter results, reporting revenue of US$421 million and a net loss of US$315 million, a sharp turn from profit in the same period last year. The latest quarterly loss and revenue drop have taken some heat out of California Resources in the very short term, with a 1 day share price return of down 5.3% and a 7 day share price return of down 4.0%. Even with that pullback, the stock still carries positive momentum over a longer stretch. It has a year to date share price return of 13.3% and a 1 year total shareholder return of 14.7%, helped by interest in carbon management projects and the Bloom Energy collaboration. Scan beyond California Resources and evaluate other energy producers under pressure with our hand picked list of solid balance sheet and fundamentals (24 results) that can better withstand earnings shocks and commodity swings. Bulls point to California Resources' carbon projects and analyst optimism, while bears focus on sharp revenue pressure and fresh losses after the hedge hit. Which side does current pricing really support as you weigh valuation next? Against a last close of $52.54, the most followed narrative for California Resources pegs fair value at $76.33. This places a lot of weight on cost discipline, integrated assets and early carbon management revenue. Cost discipline backed by ahead of schedule merger synergies and broader structural savings, including more than US$100 million of annualized reductions and a multi year target of up to US$470 million, creates room for higher free cash flow conversion, stronger net margins and potentially higher earnings quality. See why 6 investors see California Resources as 31% undervalued. Result: Fair Value of $76.33 (UNDERVALUED) Still, California Resources faces real execution risk if cost inflation keeps outpacing savings, or if fresh takeaway issues again compress differentials and cash generation. Find out about the key risks to this California Resources narrative. Mixed feelings on California Resources after these results are understandable, so move quickly, look through the underlying data, and decide what matters most for your own portfolio as you weigh the stock's 1 or more risk factors against its 1 or more potential upsides with the help of the 4 key rewards and 1 important warning sign. You do not need to stop your research at California Resources. Use the screener tools to surface fresh candidates that match how you like to invest. - Target potential mispricing by scanning a curated pool of companies that look cheap on quality and fundamentals using the 34 high quality undervalued stocks. - Strengthen your portfolio core by filtering for resilient balance sheets and steady fundamentals with the list of solid balance sheet and fundamentals (24 results). - Hunt for off the radar potential by reviewing a focused collection of smaller, high quality opportunities via the 19 high quality undiscovered gems. This article by Simply Wall St is general in nature. We provide commentary based on historical data and analyst forecasts only using an unbiased methodology and our articles are not intended to be financial advice. It does not constitute a recommendation to buy or sell any stock, and does not take account of your objectives, or your financial situation. We aim to bring you long-term focused analysis driven by fundamental data. Note that our analysis may not factor in the latest price-sensitive company announcements or qualitative material. Simply Wall St has no position in any stocks mentioned. Companies discussed in this article include CRC. Have feedback on this article? Concerned about the content? Get in touch with us directly. Alternatively, email [email protected]

- California Resources reported third quarter 2026 revenue of US$421 million and a net loss of US$315 million, while adjusted earnings per share of US$1.17 exceeded analyst expectations. - The new memorandum of understanding with Bloom Energy to evaluate up to 1 gigawatt of fuel cell power with carbon capture adds a potential growth leg alongside California Resources' existing production and carbon management activities. - The focus will now be on how California Resources' adjusted earnings beat shapes the broader investment narrative around its integrated California platform. Scan beyond California Resources and size up other hand-picked producers with resilient cash generation and balance sheets using the list of solid balance sheet and fundamentals (24 results) as a starting universe. For California Resources, the core belief is that an integrated California focused platform in oil, gas, power and carbon management can translate into durable cash generation despite volatility in reported earnings. The latest quarter complicates that story. Revenue for the period fell to US$421 million and the company posted a net loss of US$315 million, even as adjusted EPS of US$1.17 came in ahead of expectations. The near term bull case still leans on steady production, tighter cost control and execution on projects like Carbon TerraVault and the Crimson pipeline. Right now, the biggest swing factor is whether management can turn reported losses into cleaner, more predictable profitability. The main risk is that hedging hits, cost inflation or operational disruptions continue to erode margins and keep earnings quality under pressure. The new memorandum of understanding with Bloom Energy is the announcement that ties most directly into this earnings print. Management is evaluating up to 1 gigawatt of solid oxide fuel cell power paired with carbon capture and storage, using California Resources existing land position, subsurface storage and CO2 transportation capabilities as the backbone. For you as an investor, the relevance is simple. If California Resources executes on CCS and power projects at scale, Carbon TerraVault and the broader platform could add fee like revenue streams that are less tied to commodity prices. The flip side is execution and regulatory risk. Large, complex projects can absorb capital and management focus, especially when the core hydrocarbon business is reporting losses and faces ongoing cost and takeaway challenges. California Resources' narrative projects US$3.8b revenue and US$584.6 million earnings by 2029. This assumes revenue remains fairly flat over the next 3 years and an earnings increase of about US$706 million from current earnings of a US$121.0 million loss. Uncover why California Resources' fair value signals a 45% potential upside to its current price, which could narrow quickly if sentiment shifts toward California Resources. Some analysts anchor on a different catalyst. They see California Resources' CCS, power and pipeline projects as the main story, with forecasts before this quarter calling for revenue of about US$4.1b and earnings near US$925.3 million by 2029. Your view might land far below that or closer to it. Treat this earnings miss and the Bloom partnership as fresh inputs, and stress test a few scenarios rather than relying on one narrative that has not yet absorbed the latest numbers. Explore 3 other California Resources fair value estimates, including one that suggests as much as 438% upside from the current price! Don't just follow the ticker. Dig into the data and build a conviction that's truly your own. - A great starting point for your California Resources research is our analysis highlighting 4 key rewards and 1 important warning sign that could impact your investment decision. - See our latest analysis for California Resources. The report includes a comprehensive fundamental analysis summarized in a single visual, the Snowflake, making it easy to evaluate California Resources' overall financial health at a glance. Once you are comfortable with where California Resources fits in your portfolio, widen the lens and compare it against other businesses with different risk and income profiles using the Simply Wall St Screener. - If capital preservation ranks high for you, start by weighing California Resources against a wider pool of resilient companies through the 29 resilient stocks with low risk scores. - If dependable cash flows matter more, line up California Resources next to income focused opportunities using the 4 dividend fortresses. - If you want to hunt for under-the-radar ideas, expand beyond California Resources and comb through the 19 high quality undiscovered gems. This article by Simply Wall St is general in nature. We provide commentary based on historical data and analyst forecasts only using an unbiased methodology and our articles are not intended to be financial advice. It does not constitute a recommendation to buy or sell any stock, and does not take account of your objectives, or your financial situation. We aim to bring you long-term focused analysis driven by fundamental data. Note that our analysis may not factor in the latest price-sensitive company announcements or qualitative material. Simply Wall St has no position in any stocks mentioned. Companies discussed in this article include CRC. Have feedback on this article? Concerned about the content? Get in touch with us directly. Alternatively, email [email protected]

Our analysts just identified a stock with the potential to be the next Nvidia. Tell us how you invest and we'll show you why it's our #1 pick. Tap here. - Management is pivoting from a phase of rapid scale-building through M&A to an organization-wide optimization review aimed at lowering the controllable cost base through 2028. - The Crimson acquisition is being leveraged to gain control over critical midstream infrastructure, specifically to restore northbound market access and improve oil price realizations. - CRC is expanding its power strategy by partnering with Bloom Energy to develop 1 gigawatt of fuel cell power, utilizing existing natural gas infrastructure and carbon storage capabilities. - Operational efficiency has improved significantly, with the company now requiring only 6 rigs to maintain flat production compared to the 8 rigs needed by legacy operations. - The company is creating incremental value by integrating upstream processing with carbon management, such as processing Belridge gas at Elk Hills to increase NGL production by approximately 10%. - Strategic divestment of the Uinta assets allows the company to exit a high-decline, non-core geography and refocus capital on higher-return California opportunities. - The 2027 production profile is expected to be second-half weighted as the 6-rig maintenance program ramps up to achieve flat gross production from entry to exit. - Oil price realizations are projected to improve toward normalized levels in the mid-90s following the targeted restart of the San Pablo Bay pipeline in Q1 2027. - The Golden Valley Technology Hub project assumes a 12-to-18-month permitting timeline following the recent issuance of a notice of preparation by state authorities. - Management expects to share specific organic cost reduction targets for the 2027-2028 period during the next earnings call as the integration of Aera and Berry is now substantially complete. - A tentative court ruling may reopen well stimulation treatment permitting in California, which management views as a potentially meaningful development for future production. - The company faces a legal setback regarding the CTV I project's environmental report, though management intends to pursue legal action and notes other projects are unaffected. - The Huntington Beach property redevelopment is moving toward a city council vote in January 2027, with a subsequent two-year Coastal Commission review expected through 2028. - The Uinta asset sale is expected to yield approximately $100 million in net proceeds by year-end, effectively offsetting the cost of the Crimson acquisition. One stock. Nvidia-level potential. 30M+ investors trust Moby to find it first. Get the pick. Tap here. - CRC will provide land, natural gas, and carbon storage while third-party developers are expected to own and finance the fuel cell hardware. - The partnership targets the northern California market where CTV reservoirs are located, offering a combustion-free power solution with a concentrated CO2 stream for efficient capture. - The restart is targeted for Q1 2027 and requires no additional permits or major capital, as the pipeline is currently ready for service. - Reopening the line expands the pool of prospective buyers and provides flow security, with a 1% improvement in realizations representing roughly $40 million of annual EBITDA. - The permitting clock has officially started with a 12-to-18-month window expected for completion. - Management is targeting a Memorandum of Understanding with a hyperscaler in early 2027, focusing on the value of firm, behind-the-meter power. - Management emphasized a selective approach, contributing existing assets like land and gas supply to projects to capture value without necessarily committing large amounts of new cash. - New investments must compete with the high returns of the core E&P business and opportunistic share repurchases.

Announced MOU with Bloom Energy to Advance 1 GW or More of Decarbonized Power in California Submitted a New EPA Class VI Permit Application for ~57 Million Metric Tons of Storage Volume LONG BEACH, Calif., Nov. 02, 2026 (GLOBE NEWSWIRE) -- Carbon TerraVault Holdings, LLC (CTV), a carbon management subsidiary of California Resources Corporation (NYSE: CRC), today provided a third quarter 2026 update on its financial and operating results. In addition, CTV announced the signing of a memorandum of understanding1 (MOU) with Bloom Energy to jointly evaluate and target the potential development of 1 gigawatt (GW) or more of solid-oxide fuel cell power generation paired with carbon capture and storage in California. "We are advancing our CTV platform and today's MOU with Bloom opens new pathways to create value. We are focused on expanding our carbon storage portfolio through alliances like this to accelerate commercialization of CCS," said Francisco Leon, CRC President and Chief Executive Officer. "In addition, we recently submitted a new EPA Class VI permit application bringing total submitted permit volumes to more than 400 million metric tons. This complements the potential long-term CO₂ transportation optionality created through our recently closed Crimson acquisition. We believe CTV is positioned to create lasting value for shareholders and California communities." Highlights - Announced MOU1 with Bloom Energy to jointly evaluate and target the potential development of 1 GW or more of solid-oxide fuel cell power generation paired with carbon capture and storage. See California Resources Corporation Announces Strategic Collaboration with Bloom Energy to Advance Decarbonized Power Across California for additional information - Submitted a new carbon dioxide (CO2) storage application to the Environmental Protection Agency (EPA) for ~57 million metric tons (MMT); increasing total submitted CO2 permit volumes to ~409 MMT - Injection and permanent CO2 storage at Carbon TerraVault I (CTV I), California's inaugural carbon capture and storage (CCS) project, generating revenue from CO2 sourced from CRC's Elk Hills Cryogenic Gas Plant - Closed Crimson acquisition, adding optionality for a potential CO2 pipeline system through the ability to connect CTV's storage portfolio with industrial emission centers in Northern and Central California. See California Resources Corporation Completes Acquisition of Crimson for additional information Carbon Management Business (CMB) Third Quarter 2026 Results Selected Financial Statement Data and non-GAAP measures: | | 3rd Quarter | | | 2nd Quarter ($ in millions) | | 2026 | | | 2026 | | | | | Operating revenues | | $ | 2 | | | | $ | 1 | General and administrative expenses2 | | $ | — | | | | $ | 2 | Other operating expenses, net3 | | $ | 10 | | | | $ | 7 | Capital investments | | $ | 1 | | | | $ | 3 | Adjusted EBITDAX4 | | $ | (8 | ) | | | $ | (8 | ) Guidance The following table provides key CMB fourth quarter financial and operating guidance. CMB Guidance ($ in millions) | | 4Q26E | | Capital investments | | $0 - $2 General and administrative expenses | | $0 - $2 Other operating expenses, net3 | | $4 - $12 1 MOUs are non-binding agreements. The projects and transactions described in an MOU are subject to certain conditions precedent, typically including the negotiation of definitive documents, a final investment decision by the parties and receipt of EPA Class VI permits and other regulatory approvals. 2 Amount shown represents less than $1 million and is rounded to the nearest million. 3 Other operating expenses, net includes lease cost for sequestration easements, advocacy, and other startup related costs. 4 See Attachment 3 of CRC's 3Q26 earnings release for the non-GAAP financial measure of adjusted EBITDAX, including a reconciliation to its most directly comparable GAAP measure. About Carbon TerraVault Carbon TerraVault (CTV), CRC's carbon management business, develops services to capture, transport and permanently store CO2 for its customers. CTV is advancing a portfolio of CCS projects, including CTV I, which is now operational and injecting CO₂ for permanent sequestration in a depleted reservoir deep underground. For more information, visit www.carbonterravault.com. About California Resources Corporation California Resources Corporation (CRC) is an independent energy and carbon management company advancing the energy transition. CRC is committed to environmental stewardship while safely providing local, responsibly sourced energy. CRC is also focused on maximizing the value of its land, mineral ownership, and energy expertise for decarbonization by developing CCS and other emissions reducing projects. For more information about CRC, please visit www.crc.com. Forward-Looking Statements Information set forth in this communication, including financial estimates and statements as to the effects of the Berry Merger and the Crimson acquisition, constitute "forward-looking statements" within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 and other securities laws. All statements other than historical facts are forward-looking statements, and include statements regarding the benefits of the Berry Merger and the Crimson acquisition, CRC's future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives and intentions of management for the future. Words such as "expect," "could," "may," "anticipate," "intend," "plan," "ability," "believe," "seek," "see," "will," "would," "estimate," "forecast," "target," "guidance," "outlook," "opportunity" or "strategy" or similar expressions are generally intended to identify forward-looking statements. These forward-looking statements are based upon the current beliefs and expectations of the management of CRC and are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, projected in, or implied by, such statements. Although CRC believes the expectations and forecasts reflected in its forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond its control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause CRC's actual results to be materially different than those expressed in its forward-looking statements are described in its most recent Annual Report on Form 10-K and its other periodic filings with the SEC. These factors include, but are not limited to: fluctuations in commodity prices; production levels and/or pricing by OPEC, OPEC+ or U.S. producers; government policy, war and political conditions and events; integration efforts and projected synergies and other benefits in connection with the Berry Merger, Crimson acquisition and other acquisitions; divestitures and joint ventures; regulatory actions and changes that affect the oil and gas industry generally and us in particular; the efforts of activists to delay or prevent oil and gas activities or the development of CRC's carbon management segment; changes in business strategy and the ability and financial resources to execute its capital plan in a timely manner; lower-than-expected production; changes to estimates of reserves and related future cash flows; the recoverability of resources and unexpected geologic conditions; general economic conditions and trends; results from operations and competition in the industries in which it operates; CRC's ability to realize the anticipated benefits from prior or future efforts to reduce costs; environmental risks and liability; the benefits contemplated by its energy transition strategies and initiatives; CRC's ability to successfully identify, develop and finance carbon capture, transportation and storage projects, power projects and other renewable energy efforts, including those contemplated by the Bloom MOU; delays from government approvals and otherwise that could affect the timing of projects; future dividends and share repurchases and de-leveraging efforts; and natural disasters, accidents, mechanical failures, power outages, labor difficulties, cybersecurity breaches or attacks or other catastrophic events. CRC cautions you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the date hereof, and CRC is under no obligation, and expressly disclaims any obligation to update, alter or otherwise revise any forward-looking statements, whether as a result of new information, future events or otherwise. This communication may also contain information from third-party sources. This data may involve a number of assumptions and limitations, and CRC has not independently verified them and does not warrant the accuracy or completeness of such third-party information. Contacts: Daniel Juck (Investor Relations) 818-661-3700 [email protected] | Hailey Bonus (Media) 714-874-7732 [email protected] |

California Resources Corporation (CRC) came out with quarterly earnings of $1.17 per share, beating the Zacks Consensus Estimate of $0.94 per share. This compares to earnings of $1.46 per share a year ago. These figures are adjusted for non-recurring items. This quarterly report represents an earnings surprise of +24.47%. A quarter ago, it was expected that this company would post earnings of $1.31 per share when it actually produced earnings of $0.99, delivering a surprise of -24.43%. Over the last four quarters, the company has surpassed consensus EPS estimates two times. California Resources, which belongs to the Zacks Oil and Gas - Exploration and Production - United States industry, posted revenues of $1 billion for the quarter ended September 2026, surpassing the Zacks Consensus Estimate by 5.70%. This compares to year-ago revenues of $855 million. The company has topped consensus revenue estimates four times over the last four quarters. The sustainability of the stock's immediate price movement based on the recently-released numbers and future earnings expectations will mostly depend on management's commentary on the earnings call. California Resources shares have added about 24% since the beginning of the year versus the S&P 500's gain of 10.7%. While California Resources has outperformed the market so far this year, the question that comes to investors' minds is: what's next for the stock? There are no easy answers to this key question, but one reliable measure that can help investors address this is the company's earnings outlook. Not only does this include current consensus earnings expectations for the coming quarter(s), but also how these expectations have changed lately. Empirical research shows a strong correlation between near-term stock movements and trends in earnings estimate revisions. Investors can track such revisions by themselves or rely on a tried-and-tested rating tool like the Zacks Rank, which has an impressive track record of harnessing the power of earnings estimate revisions. Ahead of this earnings release, the estimate revisions trend for California Resources was mixed. While the magnitude and direction of estimate revisions could change following the company's just-released earnings report, the current status translates into a Zacks Rank #3 (Hold) for the stock. So, the shares are expected to perform in line with the market in the near future. You can see the complete list of today's Zacks #1 Rank (Strong Buy) stocks here. It will be interesting to see how estimates for the coming quarters and the current fiscal year change in the days ahead. The current consensus EPS estimate is $1.48 on $1.13 billion in revenues for the coming quarter and $4.30 on $4.04 billion in revenues for the current fiscal year. Investors should be mindful of the fact that the outlook for the industry can have a material impact on the performance of the stock as well. In terms of the Zacks Industry Rank, Oil and Gas - Exploration and Production - United States is currently in the top 11% of the 250 plus Zacks industries. Our research shows that the top 50% of the Zacks-ranked industries outperform the bottom 50% by a factor of more than 2 to 1. One other stock from the same industry, Murphy Oil (MUR), is yet to report results for the quarter ended September 2026. The results are expected to be released on November 4. This oil and gas producer is expected to post quarterly earnings of $0.91 per share in its upcoming report, which represents a year-over-year change of +122%. The consensus EPS estimate for the quarter has been revised 56.1% higher over the last 30 days to the current level. Murphy Oil's revenues are expected to be $766.69 million, up 4.6% from the year-ago quarter. Want the latest recommendations from Zacks Investment Research? Today, you can download 7 Best Stocks for the Next 30 Days. Click to get this free report California Resources Corporation (CRC) : Free Stock Analysis Report Murphy Oil Corporation (MUR) : Free Stock Analysis Report This article originally published on Zacks Investment Research (zacks.com). Zacks Investment Research

Raised Quarterly Dividend by 4% and Delivered 2% Quarter-over-Quarter Net Production Growth Sharpened Focus on California through Uinta Basin Sale and Closing of Crimson Midstream Acquisition LONG BEACH, Calif., Nov. 02, 2026 (GLOBE NEWSWIRE) -- California Resources Corporation (NYSE: CRC) today reported its financial and operating results for the third quarter of 2026. The Company plans to host a conference call and webcast at 1 p.m. ET (10 a.m. PT) on Tuesday, November 3, 2026. Conference call details can be found within this release. Third Quarter Highlights - Delivered average net production of 152 thousand barrels of oil equivalent per day (MBoe/d) (80% oil) - Reported a net loss of $315 million which includes the non-cash loss of $540 million from changes in the fair value of outstanding commodity derivatives, adjusted net income1 of $104 million and $341 million of adjusted EBITDAX1 which exceeded quarterly guidance - Generated net cash provided by operating activities of $305 million, deployed $158 million of total capital and delivered $147 million of free cash flow1 - Returned $66 million to shareholders, including $36 million in dividends and $30 million in share repurchases2 - Increased quarterly dividend by 4%, reinforcing commitment to sustainable shareholder returns; declared quarterly dividend of $0.42/share to be paid in the fourth quarter of 20262 - Ended the quarter with $1,280 million in borrowing capacity and $35 million in available cash and cash equivalents3, representing $1,315 million of liquidity1, 3 Other Highlights - Announced a memorandum of understanding4 (MOU) with Bloom Energy to jointly evaluate and target the potential development of 1 gigawatt (GW) or more of solid-oxide fuel cell power generation paired with carbon capture and storage. See California Resources Corporation Announces Strategic Collaboration with Bloom Energy to Advance Decarbonized Power Across California for additional information - Signed agreement to divest its Uinta Basin (Utah) assets for total cash consideration of approximately $90 million, subject to customary purchase price adjustments. The transaction is expected to close by year-end, subject to certain third-party consents and other customary closing conditions. See California Resources Corporation Announces Divestiture of Uinta Basin Assets for additional information - Closed its all-cash acquisition of Crimson Midstream Holdings, LLC ("Crimson"), strengthening CRC's Leading Energy Infrastructure Platform and expanding options for potential longer-term development of CO₂ transportation across California. See California Resources Corporation Completes Acquisition of Crimson for additional information - Published the 2025 Sustainability Update providing an overview of CRC's sustainability efforts and performance "Our team continues to execute exceptionally well through strong operational performance, synergy realization from our strategic initiatives and impressive free cash flow," said Francisco Leon, CRC's President and Chief Executive Officer. "Through continued capital discipline and the ongoing focus on sustainable efficiency gains, we are improving free cash flow and our liquidity profile. In addition, we remain committed to our shareholder capital return program with share repurchases and dividends, the latter demonstrated by the 4% dividend per share increase we announced today. We have also made significant progress on strategic priorities, including the Crimson pipeline acquisition, along with the Uinta Basin asset sale and Bloom Energy partnership. These initiatives broaden and strengthen our commitment to the Golden State while continuing to deliver value to all CRC constituents including our shareholders and California communities." Third Quarter 2026 Results - Net NGL and natural gas production exceeded guidance by approximately 1 MBoe/d, supported by the new Belridge-Elk Hills connection and California's first carbon capture and storage (CCS) project at CRC's Elk Hills Cryogenic Gas Plant, which led to increased gas processing and NGL recovery - Electricity revenue net of electricity generation expenses exceeded guidance primarily due to higher prices for resource adequacy revenue and sales from electricity delivered to the wholesale market as Elk Hills power plant ran at a higher operational capacity - Operating expenses were higher than anticipated and increased over the prior period, primarily due to higher prices for natural gas purchased and used in steamflood operations, and higher workover activity Select Production, Price and Financial Results and Non-GAAP Measures | | 3rd Quarter | | | 2nd Quarter ($ in millions except production and prices) | | 2026 | | | 2026 Net oil production per day (MBbl/d) | | | 121 | | | | | 120 | Realized oil price without derivative settlements ($ per Bbl) | | $ | 83.42 | | | | $ | 91.55 | Realized oil price with derivative settlements ($ per Bbl)1 | | $ | 72.46 | | | | $ | 76.43 | Net NGL production per day (MBbl/d) | | | 11 | | | | | 10 | Realized NGL price ($ per Bbl) | | $ | 48.57 | | | | $ | 49.62 | Net natural gas production per day (Mmcf/d) | | | 123 | | | | | 115 | Realized natural gas price ($ per Mcf) | | $ | 3.52 | | | | $ | 1.84 | Net total production per day (MBoe/d) | | | 152 | | | | | 149 | | | | | | Margin from purchased commodities1 | | $ | 15 | | | | $ | 11 | Electricity revenue net of electricity generation expenses1 | | $ | 35 | | | | $ | (4 | ) Net (loss) gain from commodity sales derivatives1 | | $ | (675 | ) | | | $ | 205 | Other operating expenses net of other revenue1 | | $ | 35 | | | | $ | 56 | Select Financial Statement Data and Non-GAAP Measures: | | 3rd Quarter | | | 2nd Quarter ($ and shares in millions, except per share amounts) | | 2026 | | | 2026 Total operating revenues before net (loss) gain from commodity derivatives1 | | $ | 1,096 | | | | $ | 1,092 | | | | | | Operating costs | | $ | 386 | | | | $ | 347 | General and administrative expenses | | $ | 89 | | | | $ | 97 | Adjusted general and administrative expenses1 | | $ | 79 | | | | $ | 89 | Taxes other than on income | | $ | 81 | | | | $ | 66 | Transportation costs | | $ | 31 | | | | $ | 30 | Operating (loss) income | | $ | (407 | ) | | | $ | 511 | Interest and debt expense, net | | $ | 26 | | | | $ | 28 | Income tax benefit | | $ | (113 | ) | | | $ | (56 | ) Deferred income tax benefit | | $ | (113 | ) | | | $ | (55 | ) Net (loss) income | | $ | (315 | ) | | | $ | 514 | Weighted-average common shares outstanding - diluted | | | 88.7 | | | | | 89.3 | Net (loss) income per share - diluted | | $ | (3.55 | ) | | | $ | 5.76 | | | | | | Adjusted net income1 | | $ | 104 | | | | $ | 88 | Adjusted net income per share1 - diluted | | $ | 1.17 | | | | $ | 0.99 | Net cash provided by operating activities | | $ | 305 | | | | $ | 263 | Net cash provided by operating activities before net changes in operating assets and liabilities1 | | $ | 300 | | | | $ | 300 | Capital investments | | $ | 158 | | | | $ | 149 | Adjusted EBITDAX1 | | $ | 341 | | | | $ | 338 | Free cash flow1 | | $ | 147 | | | | $ | 114 | Fourth Quarter 2026 Guidance and Preliminary 2027 Outlook The following table provides select fourth quarter 2026E guidance5. Guidance includes the financial results of the Uinta Basin through year-end 2026, while the preliminary 2027 outlook excludes the Uinta. CRC ran an average of five rigs during the third quarter of 2026 and similarly, expects to run an average of five rigs during the fourth quarter of 2026. CRC plans to enter 2027 with six rigs in California. See Attachment 2 for CRC's fourth quarter 2026E guidance. CRC Guidance | 4Q26E Net Production (MBoe/d) | 150 - 152 Percentage Oil | 79 | % Capital Investments ($ millions) | $110 - $130 Adjusted EBITDAX1 ($ millions) | $340 - $380 Leon added, "As we look to 2027, CRC is moving from acquisition to optimization. Having built, in our view, California's leading energy infrastructure platform, our focus now turns to running it better by lowering costs, improving capital efficiency and putting our midstream, power and carbon opportunities to work. That strategy positions us to strengthen free cash flow and continue delivering meaningful returns to our shareholders." 2027 drilling, completions and workover capital is expected to be $450 - $475 million. Planned activity levels will be supported by the Company's growing permit inventory and ongoing operational efficiencies. CRC remains focused on disciplined capital allocation, maintaining a strong balance sheet and delivering sustainable shareholder returns. CRC intends to provide full-year 2027 guidance with its fourth quarter and year-end 2026 earnings release. The Company has flexibility to adjust its 2027 capital program to reflect changes in commodity prices and other market factors. Shareholder Returns CRC is committed to sustainably returning cash to shareholders through dividends and repurchases of its common stock. In the third quarter of 2026, CRC repurchased 0.6 million shares of its common stock for $30 million at an average price of $53.48 per share and returned $36 million in dividends to shareholders. Since 2021, the Company has returned approximately $1,721 million to shareholders, including $1,210 million in share repurchases and $511 million in dividends. As of September 30, 2026, CRC had $570 million remaining for share repurchases under its authorized Share Repurchase Program through December 31, 20272. On November 2, 2026, CRC's Board of Directors amended its cash dividend policy to increase the anticipated total annual dividend by approximately 4% to $1.68, payable to shareholders in quarterly increments of $0.42 per share of common stock. The Board of Directors also declared a quarterly cash dividend of $0.42 per share of common stock, payable to shareholders of record on December 4, 2026. The dividend is expected to be paid on December 18, 20262. Balance Sheet and Liquidity As of September 30, 2026, CRC had $35 million in available cash and cash equivalents3, $1,280 million in available borrowing capacity under its Revolving Credit Facility (which reflects $1,460 million of borrowing capacity less $180 million of outstanding letters of credit) and liquidity of $1,315 million. In October 2026, CRC entered into a new amendment to its Revolving Credit Facility to, among other things, extend the maturity date to March 2030, increase the elected commitments of its lenders to $1,470 million, re-affirm its borrowing base at $1,500 million, and implement certain other technical amendments. Upcoming Investor Conferences CRC is scheduled to participate in the following events through year-end 2026: - Goldman Sachs 7th Annual Carbonomics Conference, November 10, London, UK - Wolfe Global Oil & Gas Conference 2026, November 18, Virtual - 2026 Stephens Annual Investment Conference, November 19, Nashville, TN - Capital One Securities 21st Annual Energy Conference, December 1, New Orleans, LA - UBS 30th Annual Global Technology and AI Conference 2026, December 2, Scottsdale, AZ - Mizuho Power, Energy & Infrastructure Conference 2026, December 8, New York City, NY - Bernstein 5th Annual Industrials & Energy Forum, December 9, New York City, NY - 25th Annual Wells Fargo Energy and Power Symposium, December 9, New York City, NY - Stifel 2026 Frontier Tech 2.0 Energy Summit, December 10, New York City, NY CRC plans to post its presentation materials to its website on the day of the event. See the Events and Presentations page under the Investor Relations section at www.crc.com. Conference Call Details A conference call and webcast is planned for 1 p.m. ET (10 a.m. PT) on Tuesday, November 3, 2026. To participate in the call, dial (877) 328-5505 (International calls dial +1 (412) 317-5421) or access via webcast at www.crc.com. Participants may also pre-register for the conference call at https://dpregister.com/sreg/10211602/104c2aa7a86. A digital replay of the conference call will be available for approximately 90 days. 1 See Attachment 3 for the non-GAAP financial measures of adjusted net income (loss), adjusted net income (loss) per share - basic and diluted, net cash provided by operating activities before net changes in operating assets and liabilities, adjusted EBITDAX, free cash flow, free cash flow before net changes in operating assets and liabilities, adjusted general and administrative expenses, total operating revenues before net (loss) gain from commodity derivatives, margin from purchased commodities, electricity revenue net of electricity generation expenses, other operating expenses net of other revenue and liquidity, including reconciliations to the most directly comparable GAAP measure without unreasonable effort. See Attachment 2 for the 4Q26 estimates of the non-GAAP measures of adjusted general and administrative expenses, margin from purchased commodities, electricity revenue net of electricity generation expenses and other operating expenses net of other revenue and reconciliations to its most directly comparable GAAP measure. The 4Q26 estimates of some non-GAAP measures cannot be reconciled to its most directly comparable GAAP measure without unreasonable effort. See Attachment 1 for a reconciliation of drilling completion and workover capital to total capital investments, and non-cash commodity derivative (loss) gain from combined derivatives to net (loss) gain from combined derivatives, reported under GAAP. 2 All of CRC's future quarterly dividends and share repurchases are subject to commodity prices, debt agreement covenants and Board of Directors' approval. The total value of shares purchased excludes commissions and excise taxes. Commissions paid on share repurchases were not significant in all periods presented. 3 Excludes restricted cash of $13 million. 4 MOUs are non-binding agreements. The projects and transactions described in an MOU are subject to certain conditions precedent, typically including the negotiation of definitive documents, a final investment decision by the parties and receipt of EPA Class VI permits and other regulatory approvals. 5 4Q26 guidance assumes Brent price of $102.90 per barrel of oil, NGL realizations as a percentage of Brent consistent with prior years and a NYMEX gas price of $3.25 per mcf. About California Resources Corporation California Resources Corporation (CRC) is an independent energy and carbon management company advancing the energy transition. CRC is committed to environmental stewardship while safely providing local, responsibly sourced energy. CRC is also focused on maximizing the value of its land, mineral ownership, and energy expertise for decarbonization by developing CCS and other emissions reducing projects. For more information about CRC, please visit www.crc.com. About Carbon TerraVault Carbon TerraVault (CTV), CRC's carbon management business, develops services to capture, transport and permanently store carbon dioxide (CO2) for its customers. CTV is advancing a portfolio of carbon capture and storage (CCS) projects, including CTV I, which is now operational and injecting CO2 for permanent sequestration in a depleted reservoir deep underground. For more information, visit www.carbonterravault.com. Forward-Looking Statements Information set forth in this communication, including financial estimates and statements as to the effects of the Berry Merger and the Crimson acquisition, constitute "forward-looking statements" within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 and other securities laws. All statements other than historical facts are forward-looking statements, and include statements regarding the benefits of the Berry Merger and the Crimson acquisition, CRC's future financial position, business strategy, projected revenues, earnings, costs, capital expenditures and plans and objectives and intentions of management for the future. Words such as "expect," "could," "may," "anticipate," "intend," "plan," "ability," "believe," "seek," "see," "will," "would," "estimate," "forecast," "target," "guidance," "outlook," "opportunity" or "strategy" or similar expressions are generally intended to identify forward-looking statements. These forward-looking statements are based upon the current beliefs and expectations of the management of CRC and are subject to risks and uncertainties that could cause actual results to differ materially from those expressed in, projected in, or implied by, such statements. Although CRC believes the expectations and forecasts reflected in its forward-looking statements are reasonable, they are inherently subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond its control. No assurance can be given that such forward-looking statements will be correct or achieved or that the assumptions are accurate or will not change over time. Particular uncertainties that could cause CRC's actual results to be materially different than those expressed in its forward-looking statements are described in its most recent Annual Report on Form 10-K and its other periodic filings with the SEC. These factors include, but are not limited to: fluctuations in commodity prices; production levels and/or pricing by OPEC, OPEC+ or U.S. producers; government policy, war and political conditions and events; changes in price realizations; integration efforts and projected synergies and other benefits in connection with the Berry Merger, Crimson acquisition and other acquisitions; divestitures and joint ventures, including the Uinta divestiture; regulatory actions and changes that affect the oil and gas industry generally and CRC in particular; the efforts of activists to delay or prevent oil and gas activities or the development of CRC's carbon management segment; changes in business strategy and the ability and financial resources to execute its capital plan in a timely manner; lower-than-expected production; changes to estimates of reserves and related future cash flows; the recoverability of resources and unexpected geologic conditions; general economic conditions and trends; results from operations and competition in the industries in which it operates; CRC's ability to realize the anticipated benefits from prior or future efforts to reduce costs and improve capital efficiencies; environmental risks and liability; the benefits contemplated by its energy transition strategies and initiatives; CRC's ability to successfully identify, develop and finance carbon capture, transportation and storage projects, power projects and other renewable energy efforts, including those contemplated by the Bloom MOU; changes in transportation costs and CRC's ability to develop midstream opportunities; delays from government approvals and otherwise that could affect the timing of projects; future dividends and share repurchases and de-leveraging efforts; and natural disasters, accidents, mechanical failures, power outages, labor difficulties, cybersecurity breaches or attacks or other catastrophic events. CRC cautions you not to place undue reliance on forward-looking statements contained in this document, which speak only as of the date hereof, and CRC is under no obligation, and expressly disclaims any obligation to update, alter or otherwise revise any forward-looking statements, whether as a result of new information, future events or otherwise. This communication may also contain information from third-party sources. This data may involve a number of assumptions and limitations, and CRC has not independently verified them and does not warrant the accuracy or completeness of such third-party information. Contacts: Daniel Juck (Investor Relations) 818-661-3700 [email protected] | Hailey Bonus (Media) 714-874-7732 [email protected] Attachment 1 STATEMENTS OF OPERATIONS, SELECT FINANCIAL INFORMATION | | | | | | | | | | | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months ($ and shares in millions, except per share amounts) | | 2026 | | 2026 | | 2025 | | 2026 | | 2025 | | | | | | | | | | Statements of Operations: | | | | | | | | | | Revenues | | | | | | | | | | Oil, natural gas and natural gas liquids sales | | $ | 1,002 | | | $ | 1,056 | | | $ | 715 | | | $ | 2,963 | | | $ | 2,231 | Net (loss) gain from commodity derivatives | | | (675 | ) | | | 205 | | | | (23 | ) | | | (1,318 | ) | | | 140 | Revenue from marketing of purchased commodities | | | 40 | | | | 26 | | | | 58 | | | | 107 | | | | 178 | Electricity revenue | | | 46 | | | | 6 | | | | 101 | | | | 63 | | | | 181 | Other revenue | | | 8 | | | | 4 | | | | 4 | | | | 22 | | | | 15 | Total operating revenues | | | 421 | | | | 1,297 | | | | 855 | | | | 1,837 | | | | 2,745 | | | | | | | | | | | Operating Expenses | | | | | | | | | | Operating costs | | | 386 | | | | 347 | | | | 316 | | | | 1,098 | | | | 927 | General and administrative expenses | | | 89 | | | | 97 | | | | 87 | | | | 292 | | | | 238 | Depreciation, depletion and amortization | | | 137 | | | | 131 | | | | 123 | | | | 401 | | | | 382 | Asset impairment | | | — | | | | — | | | | 2 | | | | — | | | | 2 | Taxes other than on income | | | 81 | | | | 66 | | | | 70 | | | | 214 | | | | 187 | Costs related to marketing of purchased commodities | | | 25 | | | | 15 | | | | 44 | | | | 63 | | | | 135 | Electricity generation expenses | | | 11 | | | | 10 | | | | 11 | | | | 26 | | | | 26 | Transportation costs | | | 31 | | | | 30 | | | | 19 | | | | 87 | | | | 59 | Accretion expense | | | 26 | | | | 27 | | | | 28 | | | | 80 | | | | 85 | Net (gain) loss on natural gas purchase derivatives | | | (1 | ) | | | 5 | | | | 27 | | | | 28 | | | | 24 | Measurement period adjustments, net | | | — | | | | (2 | ) | | | — | | | | (2 | ) | | | 1 | Other operating expenses, net | | | 43 | | | | 60 | | | | 29 | | | | 157 | | | | 127 | Total operating expenses | | | 828 | | | | 786 | | | | 756 | | | | 2,444 | | | | 2,193 | Loss on asset divestitures | | | — | | | | — | | | | (1 | ) | | | — | | | | (1 | ) Operating (Loss) Income | | | (407 | ) | | | 511 | | | | 98 | | | | (607 | ) | | | 551 | | | | | | | | | | | Non-Operating (Expenses) Income | | | | | | | | | | Interest and debt expense, net | | | (26 | ) | | | (28 | ) | | | (25 | ) | | | (83 | ) | | | (77 | ) Equity loss from unconsolidated subsidiaries | | | (1 | ) | | | (2 | ) | | | (2 | ) | | | (5 | ) | | | (3 | ) Loss on early extinguishment of debt | | | — | | | | (28 | ) | | | — | | | | (49 | ) | | | (1 | ) Other non-operating income, net | | | 6 | | | | 5 | | | | 4 | | | | 14 | | | | 9 | | | | | | | | | | | (Loss) Income Before Income Taxes | | | (428 | ) | | | 458 | | | | 75 | | | | (730 | ) | | | 479 | Income tax benefit (provision) | | | 113 | | | | 56 | | | | (11 | ) | | | 218 | | | | (128 | ) Net (Loss) Income | | $ | (315 | ) | | $ | 514 | | | $ | 64 | | | $ | (512 | ) | | $ | 351 | | | | | | | | | | | Net (loss) income per share - basic | | $ | (3.55 | ) | | $ | 5.79 | | | $ | 0.76 | | | $ | (5.77 | ) | | $ | 4.00 | Net (loss) income per share - diluted | | $ | (3.55 | ) | | $ | 5.76 | | | $ | 0.76 | | | $ | (5.77 | ) | | $ | 3.97 | | | | | | | | | | | Adjusted net income | | $ | 104 | | | $ | 88 | | | $ | 123 | | | $ | 271 | | | $ | 319 | Adjusted net income per share - basic | | $ | 1.17 | | | $ | 0.99 | | | $ | 1.47 | | | $ | 3.06 | | | $ | 3.63 | Adjusted net income per share - diluted(1) | | $ | 1.17 | | | $ | 0.99 | | | $ | 1.46 | | | $ | 3.03 | | | $ | 3.61 | | | | | | | | | | | Weighted-average common shares outstanding - basic | | | 88.7 | | | | 88.8 | | | | 83.7 | | | | 88.7 | | | | 87.8 | Weighted-average common shares outstanding - diluted(1) | | | 88.7 | | | | 89.3 | | | | 84.4 | | | | 88.7 | | | | 88.4 | | | | | | | | | | | Effective tax rate | | | 26 | % | | (12) % | | | 15 | % | | | 30 | % | | | 27 | % | | | | | | | | | | | | | | | | | | | | | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months ($ in millions) | | 2026 | | 2026 | | 2025 | | 2026 | | 2025 Cash Flow Data: | | | | | | | | | | Net cash provided by operating activities | | $ | 305 | | | $ | 263 | | | $ | 279 | | | $ | 667 | | | $ | 630 | Net cash used in investing activities | | $ | (245 | ) | | $ | (153 | ) | | $ | (87 | ) | | $ | (534 | ) | | $ | (217 | ) Net cash used in financing activities | | $ | (68 | ) | | $ | (94 | ) | | $ | (68 | ) | | $ | (217 | ) | | $ | (589 | ) | | | | | | | | | | | | September 30 | | December 31, | | | | | | ($ in millions) | | 2026 | | 2025 | | | | | | Select Balance Sheet Information: | | | | | | | | | | Total current assets | | $ | 820 | | | $ | 938 | | | | | | | Property, plant and equipment, net | | $ | 5,975 | | | $ | 5,905 | | | | | | | Total current liabilities | | $ | 1,622 | | | $ | 1,050 | | | | | | | Long-term debt, net | | $ | 1,281 | | | $ | 1,283 | | | | | | | Noncurrent asset retirement obligations | | $ | 888 | | | $ | 913 | | | | | | | Total stockholders' equity | | $ | 3,025 | | | $ | 3,674 | | | | | | | | | | | | | | | | | | | | | | | | | | | (1) Adjusted net income per share - diluted for the three months ended September 30, 2026 is calculated using weighted average shares outstanding of 89.2 million shares. Adjusted net income per share - diluted for the nine months ended September 30, 2026 is calculated using weighted average shares outstanding of 89.3 million shares. GAINS AND LOSSES FROM COMMODITY DERIVATIVES | | | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months ($ millions) | | 2026 | | 2026 | | 2025 | | 2026 | | 2025 | | | | | | | | | | Non-cash (loss) gain from commodity sales derivatives | | $ | (554 | ) | | $ | 370 | | | $ | (32 | ) | | $ | (976 | ) | | $ | 130 | Net settlements and premiums | | | (121 | ) | | | (165 | ) | | | 9 | | | | (342 | ) | | | 10 | Net (loss) gain from commodity sales derivatives | | $ | (675 | ) | | $ | 205 | | | $ | (23 | ) | | $ | (1,318 | ) | | $ | 140 | | | | | | | | | | | | | | | Non-cash (gain) loss from natural gas purchase derivatives | | $ | (14 | ) | | $ | (20 | ) | | $ | 24 | | | $ | (22 | ) | | $ | 2 | Settlements | | | 13 | | | | 25 | | | | 3 | | | | 50 | | | | 22 | Net (gain) loss from natural gas purchase derivatives | | $ | (1 | ) | | $ | 5 | | | $ | 27 | | | $ | 28 | | | $ | 24 | | | | | | | | | | | | | | | | | | | | | Non-cash (loss) gain from combined commodity derivatives | | $ | (540 | ) | | $ | 390 | | | $ | (56 | ) | | $ | (954 | ) | | $ | 128 | Net settlements and premiums from combined derivatives | | | (134 | ) | | | (190 | ) | | | 6 | | | | (392 | ) | | | (12 | ) Net (loss) gain from combined commodity derivatives | | $ | (674 | ) | | $ | 200 | | | $ | (50 | ) | | $ | (1,346 | ) | | $ | 116 | | | | | | | | | | | CAPITAL INVESTMENTS | | | | | | | | | | | | | | | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months ($ millions) | | 2026 | | 2026 | | 2025 | | 2026 | | 2025 | | | | | | | | | | Facilities | | $ | 22 | | $ | 38 | | $ | 28 | | $ | 97 | | $ | 53 Drilling and completions | | | 115 | | | 77 | | | 26 | | | 245 | | | 60 Workovers | | | 18 | | | 24 | | | 17 | | | 59 | | | 51 Other | | | — | | | 6 | | | 1 | | | 15 | | | 1 Oil and natural gas segment | | | 155 | | | 145 | | | 72 | | | 416 | | | 165 Carbon management segment | | | 1 | | | 3 | | | 15 | | | 16 | | | 22 Corporate and other | | | 2 | | | 1 | | | 4 | | | 6 | | | 15 Total capital investment | | $ | 158 | | $ | 149 | | $ | 91 | | $ | 438 | | $ | 202 LIQUIDITY | | | | ($ millions) | | September 30, 2026 | | December 31, 2025 Available cash and cash equivalents(1) | | $ | 35 | | | $ | 117 | | | | | Revolving credit facility: | | | | Borrowing capacity | | | 1,460 | | | | 1,460 | Outstanding letters of credit | | | (180 | ) | | | (176 | ) Availability | | $ | 1,280 | | | $ | 1,284 | | | | | Liquidity | | $ | 1,315 | | | $ | 1,401 | | | | | (1) Excludes restricted cash of $13 million and $15 million at September 30, 2026 and December 31, 2025, respectively. | | | | | | Attachment 2 CRC GUIDANCE | | Consolidated 4Q26E | | Oil and Natural Gas Segment | | Carbon Management Segment Net production (MBoe/d) | | 150 - 152 | | | | Net oil production (%) | | 79% | | | | Operating costs ($ millions) | | $370 - $390 | | $370 - $390 | | General and administrative expenses ($ millions) | | $95 - $99 | | $12 - $16 | | $0 - $2 Adjusted general and administrative expenses ($ millions) | | $83 - $93 | | $12 - $16 | | $0 - $2 Depreciation, depletion and amortization ($ millions) | | $128 - $140 | | $120 - $130 | | Capital investments ($ millions) | | $110 - $130 | | $110 - $125 | | $0 - $2 Adjusted EBITDAX ($ millions) | | $340 - $380 | | | | | | | | | | Margin from purchased commodities ($ millions) (1) | | $11 - $15 | | | | Electricity revenue net of electricity generation expenses ($ millions) | | $5 - $11 | | | | Other operating expenses net of other revenue ($ millions) (2) | | $20 - $30 | | | | $4 - $12 Transportation costs ($ millions) | | $30 - $35 | | $20 - $24 | | Taxes other than on income ($ millions) | | $68 - $78 | | $60 - $66 | | Interest and debt expense ($ millions) | | $28 - $32 | | | | | | | | | | Other Assumptions: | | | | | | Brent ($/Bbl) | | $102.90 | | | | NYMEX ($/Mcf) | | $3.25 | | | | Price realization oil - % of Brent: | | 91% - 93% | | | | Price realization NGLs - % of Brent: | | 55% - 62% | | | | Price realization natural gas - % of NYMEX: | | 110% - 116% | | | | | | | | | | Current income tax provision ($ millions) (3) | | $(2) - $2 | | | | Effective tax rate | | 27% - 31% | | | | (1) Margin from purchased commodities is calculated as the difference between revenue from marketing of purchased commodities and costs related to marketing of purchased commodities, and excludes costs of transportation. (2) Other operating expenses net of other revenue is calculated as the difference between other revenue and other operating expenses, net and includes exploration expense and CMB expenses. CMB expenses includes lease cost for sequestration easements, advocacy, and other startup related costs. See Attachment 3 for management's disclosure of its use of these non-GAAP measures and how these measures provide useful information to investors about CRC's results of operations and financial condition. (3) Current income tax composition is subject to variability and depends on a number of factors, including but not limited to, final taxable income determinations, the availability and utilization of net operating loss carryforwards (NOLs), applicable tax credits, and other differences between book and taxable income. Accordingly, the current provision may vary from period to period and should not be viewed as indicative of future tax obligations. FORWARD LOOKING NON-GAAP RECONCILIATIONS | | 4Q26E | | Consolidated | | Oil and Natural Gas Segment | | Carbon Management Segment ($ millions) | | Low | | High | | Low | | High | | Low | | High General and administrative expenses | | $ | 95 | | | $ | 99 | | | $ | 12 | | $ | 16 | | $ | — | | $ | 2 Equity-settled stock-based compensation | | | (12 | ) | | | (6 | ) | | | — | | | — | | | — | | | — Estimated adjusted general and administrative expenses | | $ | 83 | | | $ | 93 | | | $ | 12 | | $ | 16 | | $ | — | | $ | 2 | | | | | | | | | | | | | | | | | | Consolidated | | 4Q26E ($ millions) | | Low | | High Revenue from marketing of purchased commodities | | $ | 30 | | | $ | 46 | Costs related to marketing of purchased commodities | | | (19 | ) | | | (31 | ) Margin from purchased commodities | | $ | 11 | | | $ | 15 | | | | | | | | | | | Consolidated | | 4Q26E ($ millions) | | Low | | High Electricity revenues | | $ | 11 | | | $ | 21 | Electricity generation expenses | | | (6 | ) | | | (10 | ) Electricity revenue net of electricity generation expenses | | $ | 5 | | | $ | 11 | | | | | | | | | | | Consolidated | | 4Q26E ($ millions) | | Low | | High Other operating expenses, net | | $ | 39 | | | $ | 53 | Other revenue | | | (19 | ) | | | (23 | ) Other operating expenses net of other revenue | | $ | 20 | | | $ | 30 | | | | | Attachment 3 NON-GAAP RECONCILIATIONS To supplement the presentation of its financial results prepared in accordance with U.S. generally accepted accounting principles (GAAP), management uses certain non-GAAP measures to assess its financial condition, results of operations and cash flows. These measures are also widely used by the industry, the investment community and CRC's lenders. Although these are non-GAAP measures, the amounts included in the calculations were computed in accordance with GAAP. Certain items excluded from these non-GAAP measures are significant components in understanding and assessing CRC's financial performance, such as CRC's cost of capital and tax structure, as well as the effect of acquisition and development costs of CRC's assets. Management believes that the non-GAAP measures presented, when viewed in combination with CRC's financial and operating results prepared in accordance with GAAP, provide a more complete understanding of the factors and trends affecting the Company's performance. The non-GAAP measures presented herein may not be comparable to other similarly titled measures of other companies. Below are additional disclosures regarding each of these non-GAAP measures, including reconciliations to their most directly comparable GAAP measure where applicable. ADJUSTED NET INCOME (LOSS) Adjusted net income (loss) and adjusted net income (loss) per share are non-GAAP measures. CRC defines adjusted net income as net income excluding the effects of significant transactions and events that affect earnings but vary widely and unpredictably in nature, timing and amount. These events may recur, even across successive reporting periods. Management believes these non-GAAP measures provide useful information to the industry and the investment community interested in comparing CRC's financial performance between periods. Reported earnings are considered representative of management's performance over the long term. Adjusted net income (loss) is not considered to be an alternative to net income (loss) reported in accordance with GAAP. The following table presents a reconciliation of the GAAP financial measure of net income and net income attributable to common stock per share to the non-GAAP financial measures of adjusted net income and adjusted net income per share. | | | | | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months ($ millions, except per share amounts) | | | 2026 | | | | 2026 | | | | 2025 | | | | 2026 | | | | 2025 | Net (loss) income | | $ | (315 | ) | | $ | 514 | | | $ | 64 | | | $ | (512 | ) | | $ | 351 | Unusual, infrequent and other items: | | | | | | | | | | Non-cash derivative loss (gain) on Brent based commodity contracts | | | 554 | | | | (370 | ) | | | 32 | | | | 976 | | | | (130 | ) Non-cash derivative (gain) loss on natural gas derivative contracts | | | (14 | ) | | | (20 | ) | | | 24 | | | | (22 | ) | | | 2 | Asset impairment | | | — | | | | — | | | | 2 | | | | — | | | | 2 | Severance and termination costs | | | — | | | | — | | | | — | | | | 25 | | | | 8 | Merger-related costs | | | 3 | | | | 1 | | | | 6 | | | | 5 | | | | 10 | Net loss on asset divestitures | | | — | | | | — | | | | 1 | | | | — | | | | 1 | Loss on early extinguishment of debt | | | — | | | | 28 | | | | — | | | | 49 | | | | 1 | Offshore platform expense | | | 6 | | | | 10 | | | | 5 | | | | 26 | | | | 7 | Litigation and settlements | | | — | | | | — | | | | 1 | | | | — | | | | 26 | Measurement period adjustments, net | | | — | | | | (2 | ) | | | — | | | | (2 | ) | | | 1 | Other, net | | | 23 | | | | 12 | | | | 11 | | | | 43 | | | | 27 | Total unusual, infrequent and other items | | | 572 | | | | (341 | ) | | | 82 | | | | 1,100 | | | | (45 | ) Income tax (benefit) provision of adjustments at the combined tax rate | | | (153 | ) | | | (85 | ) | | | (23 | ) | | | (317 | ) | | | 13 | | | | | | | | | | | Adjusted net income | | $ | 104 | | | $ | 88 | | | $ | 123 | | | $ | 271 | | | $ | 319 | | | | | | | | | | | Net income (loss) per share – basic | | $ | (3.55 | ) | | $ | 5.79 | | | $ | 0.76 | | | $ | (5.77 | ) | | $ | 4.00 | Net income (loss) per share – diluted | | $ | (3.55 | ) | | $ | 5.76 | | | $ | 0.76 | | | $ | (5.77 | ) | | $ | 3.97 | Adjusted net income per share – basic | | $ | 1.17 | | | $ | 0.99 | | | $ | 1.47 | | | $ | 3.06 | | | $ | 3.63 | Adjusted net income per share – diluted | | $ | 1.17 | | | $ | 0.99 | | | $ | 1.46 | | | $ | 3.03 | | | $ | 3.61 | ADJUSTED EBITDAX CRC defines adjusted EBITDAX as earnings before interest expense; income taxes; depreciation, depletion and amortization; exploration expense; other unusual, infrequent and out-of-period items; and other non-cash items. CRC believes this measure provides useful information in assessing its financial condition, results of operations and cash flows and is widely used by the industry, the investment community and its lenders. Although this is a non-GAAP measure, the amounts included in the calculation were computed in accordance with GAAP. Certain items excluded from this non-GAAP measure are significant components in understanding and assessing CRC's financial performance, such as its cost of capital and tax structure, as well as depreciation, depletion and amortization of CRC's assets. This measure should be read in conjunction with the information contained in CRC's financial statements prepared in accordance with GAAP. A version of adjusted EBITDAX is a material component of certain of its financial covenants under CRC's Revolving Credit Facility and is provided in addition to, and not as an alternative for, income and liquidity measures calculated in accordance with GAAP. These materials include forward-looking non-GAAP financial measures, including adjusted EBITDAX. CRC is unable to provide a reconciliation of such forward-looking non-GAAP measures to the most directly comparable forward-looking GAAP financial measures because certain information needed to reconcile these measures is dependent on future events, many of which are outside of CRC's control and cannot be reasonably predicted at this time. These items include, but are not limited to, changes in working capital, the timing and amount of capital accruals, and other non-cash or unusual items. Accordingly, a quantitative reconciliation is not available without unreasonable efforts. The following table represents a reconciliation of the GAAP financial measures of net income and net cash provided by operating activities to the non-GAAP financial measure of adjusted EBITDAX. CRC has included non-GAAP measures of adjusted EBITDAX for its oil and gas segment and its carbon management segment below. Management believes these segment non-GAAP measures are useful for investors to understand the results of our core businesses. | | | | | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months ($ millions, except per BOE amounts) | | | 2026 | | | | 2026 | | | | 2025 | | | | 2026 | | | | 2025 | Net (loss) income | | $ | (315 | ) | | $ | 514 | | | $ | 64 | | | $ | (512 | ) | | $ | 351 | Interest and debt expense | | | 26 | | | | 28 | | | | 25 | | | | 83 | | | | 77 | Depreciation, depletion and amortization | | | 137 | | | | 131 | | | | 123 | | | | 401 | | | | 382 | Income tax (benefit) provision | | | (113 | ) | | | (56 | ) | | | 11 | | | | (218 | ) | | | 128 | Interest income | | | — | | | | — | | | | (1 | ) | | | (1 | ) | | | (6 | ) Equity loss from unconsolidated subsidiaries | | | 1 | | | | 2 | | | | 2 | | | | 5 | | | | 3 | Exploration expense | | | — | | | | 27 | | | | — | | | | 27 | | | | 1 | Unusual, infrequent and other items (1) | | | 572 | | | | (341 | ) | | | 82 | | | | 1,100 | | | | (45 | ) Non-cash items | | | — | | | | | | | | — | | | Accretion expense | | | 26 | | | | 27 | | | | 28 | | | | 80 | | | | 85 | Stock-based compensation | | | 9 | | | | 8 | | | | 5 | | | | 24 | | | | 18 | Pension and post-retirement benefits | | | (2 | ) | | | (2 | ) | | | (1 | ) | | | (6 | ) | | | (4 | ) Adjusted EBITDAX | | $ | 341 | | | $ | 338 | | | $ | 338 | | | $ | 983 | | | $ | 990 | | | | | | | | | | | Net cash provided by operating activities | | $ | 305 | | | $ | 263 | | | $ | 279 | | | $ | 667 | | | $ | 630 | Cash interest payments | | | 44 | | | | 26 | | | | 6 | | | | 71 | | | | 56 | Cash interest received | | | — | | | | — | | | | (1 | ) | | | (1 | ) | | | (6 | ) Cash income taxes | | | — | | | | 16 | | | | 6 | | | | 16 | | | | 45 | Exploration expense | | | — | | | | 27 | | | | — | | | | 27 | | | | 1 | Working capital changes | | | (8 | ) | | | 6 | | | | 48 | | | | 203 | | | | 264 | Adjusted EBITDAX | | $ | 341 | | | $ | 338 | | | $ | 338 | | | $ | 983 | | | $ | 990 | | | | | | | | | | | Net (loss) income per Boe | | $ | (22.51 | ) | | $ | 37.93 | | | $ | 5.09 | | | $ | (12.36 | ) | | $ | 9.31 | Adjusted EBITDAX per Boe | | $ | 24.37 | | | $ | 24.94 | | | $ | 26.90 | | | $ | 23.73 | | | $ | 26.25 | | | | | | | | | | | (1) See Adjusted Net Income (Loss) reconciliation. SEGMENT ADJUSTED EBITDAX This measure should be read in conjunction with Note 16 Segment Information in CRC's 2025 Annual Report. A reconciliation of the non-GAAP measure of segment adjusted EBITDAX cannot be reconciled to the comparable measure of operating cash flow prepared in accordance with GAAP without unreasonable effort. | | | | Oil and Natural Gas Segment | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months ($ millions) | | | 2026 | | | | 2026 | | | | 2025 | | | | 2026 | | | | 2025 | Segment profit | | $ | 360 | | | $ | 427 | | | $ | 182 | | | $ | 1,071 | | | $ | 642 | Depreciation, depletion and amortization | | | 128 | | | | 124 | | | | 118 | | | | 379 | | | | 365 | Exploration expense | | | — | | | | 27 | | | | — | | | | 27 | | | | 1 | Accretion expense | | | 26 | | | | 27 | | | | 28 | | | | 80 | | | | 85 | Adjusted income items | | | 11 | | | | 3 | | | | 4 | | | | 18 | | | | 7 | Adjusted EBITDAX - Oil and Natural Gas | | $ | 525 | | | $ | 608 | | | $ | 332 | | | $ | 1,575 | | | $ | 1,100 | | | | | | | | | | | Carbon Management Segment | | | | | | | | | | Segment loss | | $ | (14 | ) | | $ | (13 | ) | | $ | (21 | ) | | $ | (39 | ) | | $ | (66 | ) Interest on contingent liability (related to Carbon TerraVault JV) | | | 3 | | | | 3 | | | | 3 | | | | 9 | | | | 8 | Equity loss from unconsolidated subsidiary | | | 1 | | | | 2 | | | | 2 | | | | 4 | | | | 4 | Depreciation, depletion and amortization | | | 2 | | | | — | | | | — | | | | 2 | | | | — | Adjusted income items | | | — | | | | — | | | | 2 | | | | — | | | | 2 | Adjusted EBITDAX - Carbon Management | | $ | (8 | ) | | $ | (8 | ) | | $ | (14 | ) | | $ | (24 | ) | | $ | (52 | ) | | | | | | | | | | FREE CASH FLOW | | | | | | | | | | Management uses free cash flow, which is defined by CRC as net cash provided by operating activities less capital investments, as a measure of liquidity. The following table presents a reconciliation of CRC's net cash provided by operating activities to free cash flow. | | | | | | | | | | | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months ($ millions) | | | 2026 | | | | 2026 | | | | 2025 | | | | 2026 | | | | 2025 | | | | | | | | | | | Net cash provided by operating activities | | $ | 305 | | | $ | 263 | | | $ | 279 | | | $ | 667 | | | $ | 630 | Capital investments | | | (158 | ) | | | (149 | ) | | | (91 | ) | | | (438 | ) | | | (202 | ) Free cash flow | | $ | 147 | | | $ | 114 | | | $ | 188 | | | $ | 229 | | | $ | 428 | | | | | | | | | | | FREE CASH FLOW BEFORE NET CHANGES IN OPERATING ASSETS AND LIABILITIES | | | | | | | | | | Management uses free cash flow before changes in operating assets and liabilities, which is defined by CRC as net cash provided by operating activities less net changes in operating assets and liabilities and capital investments, as a measure of liquidity. The following table presents a reconciliation of CRC's net cash provided by operating activities to free cash flow before net changes in operating assets and liabilities. | | | | | | | | | | | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months ($ millions) | | | 2026 | | | | 2026 | | | | 2025 | | | | 2026 | | | | 2025 | | | | | | | | | | | Net cash provided by operating activities | | $ | 305 | | | $ | 263 | | | $ | 279 | | | $ | 667 | | | $ | 630 | Net changes in operating assets and liabilities | | | (5 | ) | | | 37 | | | | 43 | | | | 180 | | | | 165 | Net cash provided by operating activities before net changes in operating assets and liabilities | | | 300 | | | | 300 | | | | 322 | | | $ | 847 | | | $ | 795 | Capital investments | | | (158 | ) | | | (149 | ) | | | (91 | ) | | | (438 | ) | | | (202 | ) Free cash flow before net changes in operating assets and liabilities | | $ | 142 | | | $ | 151 | | | $ | 231 | | | $ | 409 | | | $ | 593 | ADJUSTED GENERAL & ADMINISTRATIVE EXPENSES | | | | | | | | | | Management uses a measure called adjusted general and administrative (G&A) expenses and adjusted G&A per BOE to provide useful information to investors interested in comparing CRC's costs between periods and performance to its peers. | | | | | | | | | | | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months ($ millions) | | | 2026 | | | | 2026 | | | | 2025 | | | | 2026 | | | | 2025 | General and administrative expenses | | $ | 89 | | | $ | 97 | | | $ | 87 | | | $ | 292 | | | $ | 238 | Stock-based compensation and other | | | (10 | ) | | | (8 | ) | | | (5 | ) | | | (25 | ) | | | (18 | ) Adjusted G&A expenses | | $ | 79 | | | $ | 89 | | | $ | 82 | | | $ | 267 | | | $ | 220 | | | | | | | | | | | G&A per BOE | | $ | 6.36 | | | $ | 7.16 | | | $ | 6.92 | | | $ | 7.05 | | | $ | 6.31 | Adjusted G&A per BOE | | $ | 5.65 | | | $ | 6.57 | | | $ | 6.52 | | | $ | 6.44 | | | $ | 5.83 | | | | | | | | | | | TOTAL OPERATING REVENUES BEFORE NET (LOSS) GAIN FROM COMMODITY DERIVATIVES | | | | | | | | | | Management uses a measure called total operating revenues before net (loss) gain from commodity derivatives, which is calculated as the difference between total operating revenues less net (loss) gain from commodity derivatives. | | | | | | | | | | | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months ($ millions) | | | 2026 | | | | 2026 | | | 2025 | | | | 2026 | | | 2025 Total operating revenues | | $ | 421 | | | $ | 1,297 | | $ | 855 | | | $ | 1,837 | | | $ | 2,745 Less: Net gain (loss) from commodity derivatives | | | (675 | ) | | | 205 | | | (23 | ) | | | (1,318 | ) | | | 140 Total operating revenues before net gain (loss) from commodity derivatives | | $ | 1,096 | | | $ | 1,092 | | $ | 878 | | | $ | 3,155 | | | $ | 2,605 | | | | | | | | | | MARGIN FROM PURCHASED COMMODITIES | | | | | | | | | | Management uses a measure called margin from purchased commodities, which is calculated as the difference between revenue from purchased commodities and costs related to purchased commodities. This non-GAAP measure excludes transportation costs. | | | | | | | | | | | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months ($ millions) | | | 2026 | | | | 2026 | | | | 2025 | | | | 2026 | | | | 2025 | Revenue from purchased commodities | | $ | 40 | | | $ | 26 | | | $ | 58 | | | $ | 107 | | | $ | 178 | Costs related to purchased commodities | | | (25 | ) | | | (15 | ) | | | (44 | ) | | | (63 | ) | | | (135 | ) Margin from purchased commodities | | $ | 15 | | | $ | 11 | | | $ | 14 | | | $ | 44 | | | $ | 43 | | | | | | | | | | | ELECTRICITY REVENUE NET OF ELECTRICITY GENERATION EXPENSES | | | | | | | | | | Management uses a measure called electricity revenue net of electricity generation expenses, which is calculated as the difference between electricity revenue and electricity generation expenses. | | | | | | | | | | | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months ($ millions) | | | 2026 | | | | 2026 | | | | 2025 | | | | 2026 | | | | 2025 | Electricity revenue | | $ | 46 | | | $ | 6 | | | $ | 101 | | | $ | 63 | | | $ | 181 | Electricity generation expenses | | | (11 | ) | | | (10 | ) | | | (11 | ) | | | (26 | ) | | | (26 | ) Electricity revenue net of electricity generation expenses | | $ | 35 | | | $ | (4 | ) | | $ | 90 | | | $ | 37 | | | $ | 155 | | | | | | | | | | | OTHER OPERATING EXPENSES NET OF OTHER REVENUE | | | | | | | | | | Management uses a measure called other operating expenses net of other revenue, which is calculated as the difference between other operating expenses, net and other revenue. | | | | | | | | | | | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months ($ millions) | | | 2026 | | | | 2026 | | | | 2025 | | | | 2026 | | | | 2025 | Other operating expenses, net | | $ | 43 | | | $ | 60 | | | $ | 29 | | | $ | 157 | | | $ | 127 | Other revenue | | | (8 | ) | | | (4 | ) | | | (4 | ) | | | (22 | ) | | | (15 | ) Other operating expenses net of other revenue | | $ | 35 | | | $ | 56 | | | $ | 25 | | | $ | 135 | | | $ | 112 | | | | | | | | | | | Attachment 4 PRODUCTION STATISTICS | | | | | | | | | | | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months Net Production Per Day | | 2026 | | 2026 | | 2025 | | 2026 | | 2025 Oil (MBbl/d) | | | | | | | | | | San Joaquin Basin | | 93 | | 93 | | 81 | | 94 | | 83 Los Angeles Basin | | 16 | | 15 | | 17 | | 16 | | 17 Uinta Basin | | 2 | | 3 | | — | | 3 | | — Other Basins | | 10 | | 9 | | 9 | | 9 | | 9 Total | | 121 | | 120 | | 107 | | 122 | | 109 | | | | | | | | | | NGLs (MBbl/d) | | | | | | | | | | San Joaquin Basin | | 10 | | 10 | | 10 | | 10 | | 10 Other Basins | | 1 | | — | | — | | — | | — Total | | 11 | | 10 | | 10 | | 10 | | 10 | | | | | | | | | | Natural Gas (MMcf/d) | | | | | | | | | | San Joaquin Basin | | 101 | | 93 | | 103 | | 96 | | 100 Los Angeles Basin | | 1 | | 1 | | 1 | | 1 | | 1 Sacramento Basin | | 10 | | 10 | | 11 | | 10 | | 12 Uinta Basin | | 9 | | 9 | | — | | 9 | | — Other Basins | | 2 | | 2 | | 3 | | 2 | | 2 Total | | 123 | | 115 | | 118 | | 118 | | 115 | | | | | | | | | | Total Net Production (MBoe/d) | | 152 | | 149 | | 137 | | 152 | | 138 | | | | | | | | | | Gross Operated and Net Non-Operated | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months Production Per Day | | 2026 | | 2026 | | 2025 | | 2026 | | 2025 Oil (MBbl/d) | | | | | | | | | | San Joaquin Basin | | 99 | | 102 | | 86 | | 101 | | 88 Los Angeles Basin | | 20 | | 21 | | 21 | | 21 | | 22 Uinta Basin | | 3 | | 4 | | — | | 4 | | — Other Basins | | 11 | | 9 | | 11 | | 10 | | 11 Total | | 133 | | 136 | | 118 | | 136 | | 121 | | | | | | | | | | NGLs (MBbl/d) | | | | | | | | | | San Joaquin Basin | | 11 | | 10 | | 11 | | 10 | | 11 Uinta Basin | | 1 | | 1 | | — | | 1 | | — Total | | 12 | | 11 | | 11 | | 11 | | 11 | | | | | | | | | | Natural Gas (MMcf/d) | | | | | | | | | | San Joaquin Basin | | 129 | | 128 | | 133 | | 128 | | 134 Los Angeles Basin | | 6 | | 6 | | 6 | | 6 | | 6 Sacramento Basin | | 13 | | 13 | | 14 | | 13 | | 14 Uinta Basin | | 12 | | 12 | | — | | 12 | | — Other Basins | | 3 | | 3 | | 4 | | 3 | | 4 Total | | 163 | | 162 | | 157 | | 162 | | 158 | | | | | | | | | | Total Gross Production (MBoe/d) | | 172 | | 174 | | 155 | | 174 | | 158 | | | | | | | | | | Attachment 5 PRICE STATISTICS | | 3rd Quarter | | 2nd Quarter | | 3rd Quarter | | Nine Months | | Nine Months | | | 2026 | | | | 2026 | | | | 2025 | | | | 2026 | | | | 2025 | Oil ($ per Bbl) | | | | | | | | | | Realized price with derivative settlements | | $ | 72.46 | | | $ | 76.43 | | | $ | 67.04 | | | $ | 72.76 | | | $ | 68.61 | Realized price without derivative settlements | | $ | 83.42 | | | $ | 91.55 | | | $ | 66.32 | | | $ | 83.08 | | | $ | 68.34 | | | | | | | | | | | NGLs ($/Bbl) | | $ | 48.57 | | | $ | 49.62 | | | $ | 41.04 | | | $ | 47.70 | | | $ | 46.10 | | | | | | | | | | | Natural gas ($/Mcf) | | | | | | | | | | Realized price without derivative settlements | | $ | 3.52 | | | $ | 1.84 | | | $ | 3.47 | | | $ | 2.99 | | | $ | 3.46 | | | | | | | | | | | Index Prices | | | | | | | | | | Brent oil ($/Bbl) | | $ | 91.36 | | | $ | 96.87 | | | $ | 68.13 | | | $ | 88.71 | | | $ | 69.94 | WTI oil ($/Bbl) | | $ | 85.79 | | | $ | 92.79 | | | $ | 64.93 | | | $ | 83.50 | | | $ | 66.70 | NYMEX average monthly settled price ($/MMBtu) | | $ | 2.96 | | | $ | 2.90 | | | $ | 3.07 | | | $ | 3.63 | | | $ | 3.39 | | | | | | | | | | | Realized Prices as Percentage of Index Prices | | | | | | | | | | Oil with derivative settlements as a percentage of Brent | | | 79 | % | | | 79 | % | | | 98 | % | | | 82 | % | | | 98 | % Oil without derivative settlements as a percentage of Brent | | | 91 | % | | | 95 | % | | | 97 | % | | | 94 | % | | | 98 | % | | | | | | | | | | Oil with derivative settlements as a percentage of WTI | | | 84 | % | | | 82 | % | | | 103 | % | | | 87 | % | | | 103 | % Oil without derivative settlements as a percentage of WTI | | | 97 | % | | | 99 | % | | | 102 | % | | | 99 | % | | | 102 | % | | | | | | | | | | NGLs as a percentage of Brent | | | 53 | % | | | 51 | % | | | 60 | % | | | 54 | % | | | 66 | % NGLs as a percentage of WTI | | | 57 | % | | | 53 | % | | | 63 | % | | | 57 | % | | | 69 | % | | | | | | | | | | Natural gas without derivative settlements as a percentage of NYMEX contract month average | | | 119 | % | | | 63 | % | | | 113 | % | | | 82 | % | | | 102 | % Attachment 6 THIRD QUARTER 2026 DRILLING ACTIVITY | | San Joaquin | | Los Angeles | | Sacramento | | Uinta | | Other | | Wells Drilled | | Basin | | Basin | | Basin | | Basin | | Basins | | Total | | | | | | | | | | | | Development Wells | | | | | | | | | | | | Primary | | 17 | | — | | — | | 3 | | — | | 20 Waterflood | | 2 | | 6 | | — | | — | | — | | 8 Steamflood | | 89 | | — | | — | | — | | — | | 89 Total (1) | | 108 | | 6 | | — | | 3 | | — | | 117 | | | | | | | | | | | | | | | | | | | | | | | | NINE MONTHS 2026 DRILLING ACTIVITY | | San Joaquin | | Los Angeles | | Sacramento | | Uinta | | Other | | Wells Drilled | | Basin | | Basin | | Basin | | Basin | | Basins | | Total | | | | | | | | | | | | Development Wells | | | | | | | | | | | | Primary | | 40 | | — | | — | | 4 | | — | | 44 Waterflood | | 52 | | 7 | | — | | — | | — | | 59 Steamflood | | 172 | | — | | — | | — | | — | | 172 Total (1) | | 264 | | 7 | | — | | 4 | | | | 275 | | | | | | | | | | | | (1) Includes steam injectors and drilled but uncompleted wells, which are not included in the SEC definition of wells drilled.