Good day and welcome to the California Resources Corporation first quarter 2024 earnings conference call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on a touch-tone phone. To withdraw your question, please press star then two. Please note, this event is being recorded. I would like now to turn the conference over to Joanna Park, Vice President of Investor Relations and Treasurer. Please go ahead. Welcome to California Resources Corporation's first quarter 2024 conference call. Prepared remarks today will come from our President and CEO, Francisco Leon, and our CFO, Nelly Molina. Following our prepared remarks, we will be available to take your questions. Please limit your questions to one primary and one follow-up. Our remarks today include forward-looking statements based on current expectations. Actual results may differ materially due to factors described in our earnings release and in our SEC filings. We undertake no obligation to update these statements as a result of new information or future events. We will also discuss our pending merger with Aera. We encourage you to read our Definitive Merger Proxy Statement issued on May 7th, 2024, as it contains important information. Copies of this and other relevant documents will be available on our website and the SEC's website. Additional information about the individuals participating in our proxy solicitation, such as our directors and officers and their interests, will be provided in our Merger Proxy Statement. Last night, we also provided information reconciling non-GAAP financial measures discussed today to the most directly comparable GAAP financial measures on our website. We also issued our earnings release in a new quarterly presentation. I'll now turn the call over to Francisco. Thank you, Joanna. Welcome, everyone, and thanks for joining us. During our first quarter in 2024, we continued our strong operational execution from 2023 and made good progress on our long-term goals. We hit the ground running with the announcement of our pending Aera merger. We remain focused on closing this transaction and have passed key milestones such as the HSR waiting period and the filing of the Definitive Proxy Statement with the SEC, and are tracking toward a mid-year 2024 close. This highly accretive transaction builds scale, strengthens the durability of our conventional business, and significantly expands our carbon management opportunities to solidify CRC's differentiated strategy and advantage position. We remain confident in our ability to execute our strategy and deliver sustainable free cash flow to our shareholders and low-carbon intensity energy to Californians. For today's discussion, I'll be highlighting a few key topics. One, the strength and quality of our assets and operational excellence of our team. Two, an update on the Aera merger and how it will unlock incremental shareholder returns. Three, our advantaged position to provide the energy and decarbonization solutions California needs. Let's begin. During the quarter, gross production remained flat, entry to exit, while operating a 1-rig program demonstrating the strength of our asset base. Our portfolio consists of conventional reservoirs with stable and low-decline production profiles associated with water floods and steam floods, in contrast to unconventional reservoirs with high initial production followed by steep declines. Conventional reservoirs also lend themselves to significant workover potential, which provides an efficient means to bring on production at a fraction of the cost of a new well. In addition to workovers, our operations team performed well-maintenance and artificial lift optimizations that helped offset the production decline even further. As such, CRC was able to invest just $22 million in the first quarter in drilling and workover capital to achieve this result. Our large base of PDP production also provides predictability in cash flow and financial stability. Our business generated $149 million in Adjusted EBITDA and delivered $33 million in Free Cash Flow. These strong financial results set the foundation for our strong first-quarter cash returns in which we distributed $79 million to shareholders via dividends and buybacks, and nearly $95 million through April. The total cash payout from this initiative implies an annualized yield of approximately 8%. We currently have $675 million remaining on our share repurchase program, and our board intends to evaluate further increases to our dividend following closing of the Aera merger. As we look forward, we remain focused on providing much-needed local energy for today, as well as lower-carbon intensity energy and carbon solutions for the future. Total capital investments for 2024 are expected to range between $200 million and $240 million, running a one-rig program for the remainder of the year. Similar to 2023, this year's program is expected to deliver entry-to-exit net production decline of 5%-7%. At this point of the year, we have not seen sufficient improvement in the permitting process to support the multi-rig drilling program and expect to maintain lower activity throughout the balance of the year. As an update on the Kern County EIR, in March, the court ordered the county to prepare a revised EIR that should address three key items: mitigation of agricultural impacts, health assessments, and water supply analysis. We currently expect the county to certify a revised EIR and adopt a revised zoning ordinance around year-end 2024, and estimate that the stay-on-drilling could be lifted by the trial court sometime in the second half of 2025. Separate from Kern County's efforts, our team continues to work diligently toward progressing alternative paths to navigate these delays. Slide 18 of our deck details these pathways. First, our current approvals allow us to support a one-rig program through 2025. Second, the county can meet CEQA requirements by approving a conditional use permit and conducting a field-level CEQA review, which would form the basis for new drill permits to be issued. Third, our broad footprint in and outside of Kern County allows for multi-basin development. We are targeting a potential return to an increased level of activity in the second half of 2025. Moving to Aera, we remain focused on closing the merger. We expect this transformational transaction to create significant scale and asset durability to meet California's growing energy needs. Aera 's conventional assets are similar to CRC's, with low royalty burden and multi-stack producing zones with 10%-13% corporate production declines before capital. The transaction also expands our leading carbon management platform, adding premium pore space and co-located CO2 capture opportunities that further strengthen our ability to help the Golden State meet its ambitious climate goals. We remain confident in our ability to deliver $150 million in annual synergies from the combined businesses and create meaningful long-term value for our shareholders. To date, the CRC and Aera teams have worked together to identify meaningful synergies around G&A, supply chain, and infrastructure optimizations. This great work gives us a path to deliver $50 million of these run-rate synergies within six months of closing. We are targeting to close the transaction in mid-2024 and will provide more detailed guidance post-close. Regarding the sustainability of our business, we recently received a Grade A certification through MiQ's Methane Emissions Performance Standard from our operating assets in Los Angeles and Orange counties. This rating highlights CRC's dedication to high sustainability standards, continuous monitoring, and methane reduction in our operations. As a reminder, we set an initial goal to lower methane emissions by 50% from our 2013 baseline by 2030. We surpassed this goal in 2018, 12 years ahead of schedule. We then set a new goal in 2022 to further reduce methane emissions by 30% from our 2020 baseline, also by 2030. CRC's methane reduction goals and execution exceed the 2030 goals that California has set for the state. Turning to Carbon TerraVault. On March 28th, Kern County announced that based on the comments received during the public comment period, our CTV I permit would require further environmental review, and the county recommended continuation of the process to the August 22nd Planning Commission hearing this year. As a reminder, the EPA and Kern County have worked hand in hand on advancing this first-of-a-kind permit in California in a matter that complies with California's environmental standards, which are undoubtedly the highest in the U.S. The comments received were a result of our four joint EPA-Kern County public workshops that were voluntarily held to maximize the opportunity for public comment. These workshops, along with the EPA's voluntary extension of the public period from 45-90 days, facilitated the desired engagement with the public in the permitting process, the natural outcome of which is not, unsurprisingly, the need for more time to consider those comments. CTV supports this approach as it sets the gold standard for CCS permitting. And as previously communicated last quarter, we continue to expect the final EPA and Kern County permits in the second half of 2024, enabling us to meet our target FID on CTV I in the same window and begin CO2 sequestration by the end of 2025. And now, let me turn the call over to Nelly to cover our first-quarter performance and second-quarter 2024 guidance in more detail. Nelly? Thanks, Francisco. In the first quarter of 2024, we generated $54 million of adjusted net income, or $0.75 per diluted share. We produced 76,000 bbl of oil equivalent per day and 48,000 bbl of oil per day, all within our guidance range. Results reflected the strong execution of our operations team amidst a scheduled major maintenance at our Elk Hills power plant. The scope of the turnaround was expanded, and the longer downtime impacted gas sales volumes beyond initial guidance but allowed for the maintenance to increase reliability at nominal impacts to cash flow. The power plant resumed operations back in early April. Production volumes also reflected the divestiture of our share of a non-operated field Round Mountain, as well as natural decline. Moving to cash flows, first-quarter net cash from operating activities was $87 million. Our total capital invested during the quarter was $54 million, with workover capital expenditures of $22 million. We generated $33 million in free cash flow during the quarter. We maintain our strong balance sheet with $880 million of liquidity, which includes $403 million of cash and $477 million of available borrowing capacity under our revolver credit facility. We ended the first quarter with a leverage ratio of 0.2x. In March, and in connection with the Aera merger, we secured a commitment to increase our borrowing base from $1.2 billion- $1.5 billion and increase our revolver elective commitment from $630 million- $1.1 billion. Those increases will become effective upon the merger closing and will improve our liquidity by $470 million. We are committed to preserving a solid balance sheet and believe we have the financial flexibility to deliver on our strategic objectives. Turning to second quarter, gross production is expected to average around 93,000 bbl of oil equivalent per day, reflecting modest natural declines. Net production is expected to range between 74,000 bbl and 78,000 bbl of oil equivalent per day and 61% oil. We anticipate sequential quarterly net production to remain relatively flat due to the softer natural gas pricing environment and growing seasonal supply of solar power. These will result in less natural gas sold and consumed at our Elk Hills power plant. Let me remind you that our net production volumes represent our sales volumes and can fluctuate based on market conditions, whereas gross production reflects the actual reservoir capability and performance. We expect to deploy $50 million-$57 million in capital in the second quarter, and we'll continue to focus on operating efficiencies. With that, I'll pass it on to Francisco for his final remarks. Thank you, Nelly. In conclusion, I'm proud of the accomplishments of the entire organization. Over the next 18 months, our efforts will focus on the closing and integration of the Aera merger while unlocking our targeted synergies. The CRC team is excited to work closely with the Aera team to build a stronger, California-focused organization, combining the best that both teams have to offer. Aera is a great company, and their execution over 25 years is a testament to the great people that work there. I am optimistic about our EMP business and our ability to return to an increased level of drilling activity in the second half of 2025. I am also encouraged by the progress made by the CTV team, clearing key milestones towards California's first-ever CO2 injection permit. CRC is well-positioned to generate competitive returns, decarbonize California's hard-to-abate sectors, and deliver sustainable cash flow for years to come. Thanks for your time today. Operator, please open the lines for questions. We will now begin the question-and-answer session. To ask a question, you may press star, then one, on your touch-tone phone. If you're using a speakerphone, please pick up your handset before pressing the keys. If at any time your question has been addressed and you would like to withdraw it, please press star, then two. At this time, we will pause momentarily to assemble our roster. The first question comes from Scott Hanold of RBC Capital Markets. Please go ahead. Yeah, thanks. Thanks, all. Hey, I was wondering if we could give a little bit more color on, I guess, what you're hearing with the Class VI permit. You obviously indicated that Kern County's EIR is set for an August timeframe. So is it your understanding that the EPA and Kern County will issue their respective EIR and draft or final permits at the same time in August? And just generally, what do you understand is the discussion points coming out of those hearings that give you pretty good confidence to maintain your FID timeline as well as first injection? Hey, Scott. Yeah, confidence is absolutely there. The lack of, we don't know exactly the EPA and Kern County timeline and if they're going to be ultimately synced up. We know if you think about the EPA permit, which is a subsurface permit, we look at to be on track for the summer, as we talked about today, with the county, which is really more of an above-the-ground permit for conditional use. That's now targeted for August, which is a couple of months behind the EPA. So the confidence is really there to get to the finish line on that final permit and then getting to FID right away on our first project. So that hasn't changed. If you remember last earnings call, we talked about receipt of the permit in the second half of the year. So we're very much still targeting that. When we look at creating kind of the gold standard permitting for CCS in the U.S., it's important that we take time because there's a lot at stake. We have 1 billion metric tons of pore space. We have 20 million tons of injection. So that first permit will set the stage for everything else that comes. So where it's hard to meet quarter-over-quarter timelines given that we have to announce this publicly, the confidence continues to grow on the permitting process, on the engagement with the communities. I would say the excitement is there also on emitter opportunities. I would say more emitter opportunities unfold as time passes so that pore space is becoming more valuable. The confidence level's high. It's just a matter of getting to the finish line on this first permit that needs to check a lot of boxes. But our team is working it, and we're excited to get to FID this year. Yeah. And just to clarify something there, you said there are more emitter opportunities unfolding. Is that referring to more brownfield opportunities? I would say it's all of the above. Emitters, greenfield. When you have the scarcity in a brand new business model where you're years ahead of anybody else in terms of getting to a first injection permit, as you start getting closer to that finish line, more and more industries of different types, again, brownfield and greenfields, are coming to us and saying, "Okay, this is really, really special, really interesting. I'd like to take a reservation for pore space." The focus right now is to get to that permit, right? So announcement of more emitter deals on a premature basis without the permit, I think the market discounts that. We want to get to that first permit and then announce all the conversations we're having. Okay. Thanks for that clarification. My follow-up question is on Aera with the closing fairly imminent, I guess, in the next couple of months. Can you remind us, what are some of the low-hanging fruit that we could see on the near-term kind of benefit the combined company? And I think Nelly had mentioned specifically, obviously, some maybe softness in natural gas demand due to solar pickup in the summer. But when we were talking before, I think you talked about some synergistic opportunities between CRC's legacy assets and Aera there as well. But can you give us a sense of what are the low-hanging fruit where we could see kind of some near-term benefits? Yeah, there's a lot of low-hanging fruit. If you look at $150 million of annual synergies, 10 years of run rate, that's $1 billion that would be added value to the combined entity. And as we talked about before, there's upside to that number. These are two great companies coming together that have been run independently from each other. A lot of facilities are already in place. A lot of capacity, whether it's power, water treatment, or gas flows, now we have an opportunity to reimagine how the western side of Kern County should look. So there's a lot there. Excited to share the specifics in a few months. But I'll turn it to Omar Hayat to maybe provide a couple of more detailed examples of what we're seeing. Yeah, thanks, Francisco. Scott, like Francisco mentioned in his earlier comments, the synergies are really going to be focused around three areas: infrastructure, supply chain, and G&A. So to give you more specific examples on infrastructure, what we are looking at is what we are trying to leverage here is a close proximity of Aera's operations to ours. There is already some legacy connectivity between the fields, but we plan to invest and build that connectivity even more. And what we want to get to is an ability to move power, gas, oil, and water across these fields. And we see either an improvement in margin for our products through doing that or lowering the cost of our operations. So, for example, there are Aera fields that are in close proximity to our Elk Hills power plant, where there could be a potential to move them away from PG&E power and provide our own power there and lower the cost. Similarly, Aera is a net consumer of gas because of the steam flood operations. We are a net producer, so we see some opportunities to explore there as well. And then moving on, there is a possibility to look at various oil blends to improve our margins and even water treatment for beneficial use, given that we operate in an agricultural county here in Kern County with a lot of demand for water. So that's infrastructure. And similarly, in supply chain, what's going to happen is that our scale will essentially double in size. So that then lends itself to looking at the operating model differently. We can look at some insourcing opportunities for some of the services. We will also look at outsourcing some and learn from the two companies and bring the best practices to the combined company. G&A is an obvious one. Obviously, with overlapping footprint, we see material opportunities there as well. Yeah, so the plan is to hybrid the best of combined teams from a G&A perspective. So we're working it, and the commitment is we're going to get to $50 million of synergies within the first six months. So there is a low-hanging fruit. There is a lot of opportunity, and we're excited about it. Thank you. Our next question comes from Kalei Akamine from Bank of America. Please go ahead. Hey, good morning, guys, Francisco, Nelly. My first question is on the use of cash. So the buyback this quarter has some support from the balance sheet, and I think that makes sense given the performance lag. The context there, I think, is the EIR result. So we like seeing you lean in. But with Aera now closing, I feel like there are now competing priorities for that cash with respect to leverage. So I guess with those motivations as the backdrop, wondering about the rough contours of your cash program post-Aera. Yeah, I think definitely getting to the finish line, Kalei. We need to improve the Aera balance sheet. We're going to look opportunistically to refinance that debt. Our commitment is to get to a less than 0.5 leverage ratio on the debt. But we think we can get there fairly quickly. The amount of cash generation from this business is absolutely tremendous. So we're going to look to increase the dividend subject to board approval after closing. Then you have a fantastic tool, which is the share repurchase program. I see an opportunity as we get to final permits on both oil and gas and CCS. In looking at the lag in the stock performance, I continue to buy aggressively our shares. So I wouldn't say overarchingly there's a change. I would say it's probably more to come. We have a good track record returning cash to shareholders. We'll continue doing that. Anything related to the Aera merger, we'll address quickly, get the debt back levels down, and then focus on distributing more cash to shareholders. My suspicion is that the quarterly cash sweep will probably be split between the buyback and debt reduction. But as you think about the cash balance that you currently have, that's still very strong. How do you think that trends as we head towards that target leverage metric that you have in 2025? Yeah, I guess one clarification is remember the effective date on the transaction is 01/01/2024. So there's already cash in the system with an Aera balance sheet that's being used to de-lever already as we go. So we do have a few things to take care of after closing or before closing. But I think the prime objective post-closing and once we get on track to get the leverage to 0.5 will be to distribute cash to shareholders. So that's what we did in 2023 when we had no permits for oil and gas. That's what we'll do in 2024 and into 2025. Got it. I appreciate that. My second question goes to pro forma guidance, CapEx, OpEx, and Aera included. Closing is coming up for Aera, and you suggested that program is basically a mirror of yours. But had it closed within a month or so, wondering about any updated thoughts you have on 2024 guidance. And I'll leave it there. Yeah, 2024 guidance, we haven't communicated for the combined company. You have the view for CRC midpoint of production 70,000 BOE per day. So basically, a continuation of what we have delivered in the first quarter and our capital $200 million-$240 million for CRC. So we'll update 2024 guidance. We are not expecting to run any rigs on Aera's fields in the second half of the year. So I would say a light capital program on a relative basis for 2024. What we do see once we're able to get back to increased production and we have the ability to invest to keep production flat, we see investment of about $500 million-$600 million as maintenance for the combined company. That would be drilling completions and workovers plus facilities. And that varies every year. That would be the objective once we get back to full permits. But in the meantime, low capital, one rig program on the combined basis. And you can see some of the numbers on the slides, but it's a low capital program until we can get permits back on track. In the absence of a drilling program on the Aera asset for 2024, what are your expectations for an oil decline rate? Yeah, so on the slides, you'll see that we showed Aera's decline and CRC's from 2023 average of about 6% for both companies. And as I said, these assets are very similar. Really good rock, low decline. And you can basically get from the corporate decline rate of, call it, 11.5%. You can get into the mid-single digits with workovers and sidetracks and increased workovers on capital and OpEx. And that's effectively what Aera did last year. That's what Aera is doing this year. So 5%-7% on a combined basis based on last year, I would expect something similar for this year with one rig running between the two companies. Our next question comes from Nate Pendleton of Stifel. Please go ahead. Good morning, and thanks for taking my questions. Good morning, Nate. For my first question, AI and data center power demand has been quite topical recently. Can you provide your perspective on the opportunity that you see for CRC given your dominant position in the California natural gas market? Hey, Nate. Definitely watching it unfold. If you look at what the data centers are looking for, it's 24/7 power, but they're also looking for carbon-free power. They need land. They need running room. They need water. We provide it all at Elk Hills. We'll have it at Belridge as well. If you look at California specifically, where you don't have an ability to develop nuclear, we're down to one plant. The only reliable sources of carbon-free power are going to be natural gas fire power plants with CCS. So we think we have the perfect solution to keep the data centers in California. And CalCapture, which is our Elk Hills Power project, becomes a fascinating opportunity to advance and look forward. So early conversations are happening. And maybe I'll turn it to Chris Gould to give a perspective of what we're seeing on the data center side. Yeah, thanks, Francisco. Nate, thanks for the question. Yeah, just to unpack that a bit, obviously, California is a national leader in technology. And it's got a high concentration of data centers in LA, Silicon Valley, and Sacramento. And that uniquely overlaps with our footprint for our CTV reservoir. So you all know CTV 1 is about 120 mi or so from LA. And CTV II through V are 30 mi-65 mi from Sacramento or Silicon Valley. So we're uniquely positioned to take advantage of that growth and that opportunity by co-locating either hyperscale data centers, which as you know are large megawatt facilities, and/or co-locators, which are smaller, with a range of different storage volumes and injection to do what Francisco referenced around sourcing that baseload carbon-free energy. So very excited about that. As Francisco mentioned, early discussions underway. Ultimately, the scale at which we could deliver a solution like that is in the gigawatt range as opposed to the megawatt range and something we're advancing discussions with. Got it. I appreciate the detail. It's a great opportunity. For my follow-up, referencing slide 18, can you provide some detail around the potential to use those Conditional Use Permits for Kern County, such as other limitations on the potential size of those programs that such permits could support? So good potential. So not only we talked about CRC having in the queue three conditional use permits: Elk Hills, Buena Vista, and Kern Front. Aera has several CUPs in the queue as well. So we'll have a lot of opportunity to go back to kind of field-specific programs. The packaging of the programs, number of wells, injectors, that's still to be determined in terms of how ultimately best get the CUPs off the ground. And that's what we're working through. It still will take some time. We don't see that process moving quickly. And as we said, it's going to be more of a second half of next year. But good confidence in the ability to permit using that format. That's effectively how the rest of the state works in other places where CalGEM is the lead agency. So we see this as working well. Even though it's not ready today, it's a very good solution to permit using the CUPs. Our next question comes from Betty Jiang of Barclays. Please go ahead. Hello. Thank you for taking my question. I wanted sorry, just follow up on the permitting question a bit more. I guess on the conditional use, some of the two other options beyond the Kern County litigation resolution, when it comes down to the Conditional Use Permit and Francisco, what you just talked about, the multi-basin approach, can you just get a bit more detail into the legislatures or the organization that's involved in providing these permits and whether that could completely offset the permits that you guys need in Kern County that will be able to compensate the hurdles that you're currently seeing in Kern County? Thanks. Hey, Betty. Yeah, so we're in multiple basins. We're in Long Beach. We're in Sacramento. And now with Aera, we'll be in Ventura beyond the San Joaquin Basin, which is primarily Kern County. The attention's been given to Kern County and the process that they had as the lead agency effectively. And that's what's been challenged in the courts. But outside of Kern County, CalGEM is the lead agency. And CalGEM's working through a new standard operating procedure. They're working through their process in terms of making sure we're checking all the requirements from a regulation perspective. And so outside of Kern County, it's CalGEM. And the discussions are ongoing. We're actually receiving sidetracks under this process. Not enough to say that they've more than compensated the loss in Kern County, but there's progress there. That's what gives us confidence that we're going to be able to run a one-rig program this year and next year. There could be some upside as more permits come through, but hard to know at this stage. We just know that CalGEM's working it and progress is starting to show up. Got it. Thank you. And I have a follow-up on the Brookfield payment and how to think about the next catalyst when it comes to the carbon management business. Can you just walk through what we should be looking for to receive the next, the third installment payment for Brookfield? And when should we expect in terms of FID for the CO2 plant, for the first injection plant, which I believe will be followed by the hydrogen plant? Yeah, Betty. So as we looked two plus years ago now with Brookfield, a first-of-a-kind joint venture, there were a lot of unknowns as to how things were going to progress. And we set up as we dropped in reservoirs and we dropped in the first one called 26R, we decided to have a staggered payment system that's tied to milestones. First payment was for the draft permit, which we received in December. The second permit came in as the public comment period was finalized and completed to Brookfield's satisfaction. The third payment is around the final permit effectively and reaching FID. So I would expect that either later this year, the beginning of next year. It just depends on how things play out in terms of getting to FID. But if you go back to my conversation earlier, we're looking for final permit in the second half of this year. The gas processing plant, which is our CRC-owned plant, 100,000 tons per year of CO2 that we can capture right away, that's a project that's within fuel boundaries. It's already in place and something that we can execute quickly. The conversations with Brookfield will be around that FID as the project that triggers the last payment. It also has the condition of final declaration of the size of the reservoir by the EPA. We are seeing upsides to the numbers that we had planned for. That's why we provide a range to the third payment that could be higher than the first and second and third payments. Kind of a catch-up payment if the reservoir is higher. Expect more news in the second half of the year once we get closer to final permit. Once we get to FID, we'll update on that Brookfield payment. But I think we'll be in a position in the near term to collect all three payments and looking forward to adding more reservoirs into the JV. The next question comes from Leo Mariani of Roth MKM. Please go ahead. I wanted to focus a little bit on the production here. So you guys certainly mentioned that first-quarter production came in a little bit lower. And it sounded like some of that was extended maintenance at Elk Hills and towards the power plant. I was hoping you guys could kind of quantify. So how much did you lose in the first quarter? And presumably, that's all back in the second quarter. But then it sounds like you're also losing some production here just to kind of lower gas demand. So maybe you can help quantify that a bit. And presumably, those are some of the reasons why you guys lowered the production guidance a little bit and then also probably higher oil prices with some PSC impact. Is there anything else that kind of caused you to bring the production guidance a little bit lower here in 2024? Hey, Leo. So yeah, first quarter, the delay of the power plant turnaround was about 800 bbl equivalent per day. But it's all of it gas. And so that was the impact there. And as we talked about, this plant is growing in value every day. And our team does a fantastic job of maintaining the assets. We took the opportunity to do an expanded review to make sure everything was functioning and looking at the steam turbines and doing an inspection. So that was completed successfully. The plant got restarted running at 100% capacity. And that's primarily the impact in the first quarter. We also had some weather, a lot of storms, mudslides to contend with. And then finally, the PSC effect. So yeah, that's where we're at the lower end of the range. More gas struggled a little bit more than oil. Oil actually was on the high end of the range. But those are kind of the first quarter impacts. Now, second quarter comes around a little bit of the spillover of the turnaround for Elk Hills. But again, we got it back up and running in full in April. So you're back to having two primary issues for the second quarter. One is we're planning the second quarter at a higher Brent price. So you do expect some impact to PSC as it's inversely correlated PSC to production. But what we're seeing in the second quarter is we're having to take down the power plant to a lower capacity given that we're seeing a lot of solar energy being generated in the second quarter. And that brings prices for power down. So rather than send power into the grid in this environment, we decide to ramp down the plant on a temporary basis. I would say this is a seasonal aspect of how we're seeing things unfold in California. We do have fixes on a go-forward basis. It's one of the, again, advantages of having the merger with Aera. And basically, what happens is there's some permeate gas that is not up to specs for the utilities, but we're able to run that to our power plant. As the plant goes from full capacity of 550 MW ±, then you're able to put all the gas into the plant. If you bring that down in terms of capacity, then you have less consumption of that gas. And so you're not getting to that sales point. We're able to, after the merger closes, to route that gas to Aera's fields and offset some of the gas that they're purchasing at Belridge, as an example. The two fields are already connected with a pipeline. So it gives us effectively a relief valve to move that gas on a go-forward basis. But that's effectively what's going on. So there are independent issues with the plant. The first one was a turnaround. The second one is market. And maybe I'll just ask Jay Bys to provide a little bit more color commentary on solar power generation in California. Good morning. Yes, California has actually become a net power exporter over the course of the last couple of years. In fact, power's going north to Washington State to capture GHG-driven pricing up there. Even with that, we're seeing growing backdowns on both solar and wind generation in these shoulder months. It's interesting to watch this play out. Fortunately, we've got a couple of different value streams related to our power plant, as Francisco points out. Even when we back the unit down, we're not able to take full advantage of the off-spec gas that would otherwise be burned. But we do continue to have the benefit of the plant behind the fence to give us very attractive rates. We've got a capacity revenue stream that goes with the power plant. It's going to be interesting to see how the broader circumstance plays out in California. But from our perspective, we're pretty well situated. The addition of the Aera off-ramp, if you will, to run this off-spec gas through steamers, that's only a benefit. Okay. Appreciate the thorough answer there. And then just wanted to follow up on the oil and gas drilling permit process here. So it sounds like there's been maybe somewhat of a hiatus for CalGEM kind of outside of Kern County. Obviously, you've got the LA Basin operations, the Sac Basin operations. You mentioned the agency's kind of reviewing procedures out there. Just for some context, have they not really issued much in the way of drilling permits to anybody this year as they're kind of reviewing those protocols? And presumably, they're going to have maybe some updated protocols and perhaps a slightly modified permitting process later this year. Just how do we kind of expect that to play out? I assume you've been in contact with CalGEM about these things. So maybe just a little bit more color, just because obviously, you have assets outside of Kern. It'd be great to kind of drill some wells. So that's the thing. You got it, Leo. That's exactly right. CalGEM is going through a fairly extensive review of their procedures and looking to improve how they think about permitting in California. Like I said, there's sidetracks. And there's progress being made in our fields. And we're seeing some approved in other fields throughout the state. We haven't seen new wells permitted this year under the new format. And CalGEM's still working through that. Can't speak for them as to when they're going to be ready. We engage with them very frequently in looking to get back to full permitting capacity and full drilling program outside of Kern County. So hard to pinpoint a specific date when CalGEM will be ready. But we do see progress already, meaningful progress on sidetracks and workovers. And the anticipation is that we'll get the new wells back on track soon. I can't put a timeline to it. But we see a lot of progress being made. And the agencies are talking about us getting to, hopefully, the final steps in their process. The next question comes from Noel Parks of Tuohy Brothers Investment Research. Please go ahead. Hi. Just had a couple. You mentioned earlier that there is interest from Brownfield and Greenfield emitters that are looking to reserve pore space. I just wondered, in talking with parties like that, can you talk about sort of what the terms are that are being discussed? Are they mostly focused on commitments to certain volume or pricing terms? Anything about that would be interesting. Yeah. So you have a few very interesting dynamics at play. We see California emitters winning grants from the Department of Energy to capture CO2. But that's only going to be valuable and good if we have a storage site to put the CO2 to work. So we're looking for the discussions with the brownfield emitters really circle around CO2 pipelines. We are still waiting for the legislature to issue rulings around the framework on how CO2 pipelines are going to work in the state. We anticipate some progress being made during either the budget session or later in the legislative year. So that's something that could be a very positive catalyst. But without those pipelines, then the connectivity to brownfield emitters is not going to be there and putting at risk the DOE funding and some of the big capital projects that these emitters have. I would say that's, in a nutshell, what's slowing down some of the Brownfield emitters. On the Greenfield emitters, where we have all of them behind the fence, it's really about trying to optimize how we allocate the pore space. We've talked about a $50-$75 per ton storage fee that the JV is going to collect from these emitters. Ultimately, they need a CCS storage site as well to make their projects clean. And a lot of these markets are unfolding, whether it's hydrogen or ammonia. These projects, there's no market for the clean version of these energy sources. So the offtake is being discussed. And so there's other elements to the greenfield projects in terms of more certainty as to how do we get the CO2 on the ground once we get the permit, less certainty as to how they're going to get the product sold and what kind of premium it's going to command. So it's unfolding. It's moving. It's very dynamic. A lot of really interesting discussions happening. And that final permit on Class VI will ultimately unlock a lot of these exciting discussions. Great. Thanks for that. I wanted to ask about the Aera acquisition. Looking back to sort of where the strip stood at the time that you announced it early in the year, so looking at WTI, the strip out a couple of years was kind of in that mid-60s sort of range. Then with this last rally we had in crude, it took it more like to low- to mid-70s. I just wondered if that delta translated to any projects, any upside potential that you didn't include in your evaluation so you essentially aren't going to be paying for that might come into play if you could envision a long-term, stronger oil price? Yeah. I mean, definitely, the conditions that supported the decision around the Aera merger are there and are getting stronger in a lot of ways given the confidence that we have on synergies. We have seen the beginning of the year with stronger Brent pricing. As a reminder, as a private company, Aera had a different view on hedging their volumes than we did. They have entered historically into more swaps, locking in some of the pricing, which is good because it gives us more of an ability to plan. But it takes away some of the upside. They do have some barrels open that would provide some further upside to pricing in the near term. Difficult to quantify at this stage. But we'll be providing an update once we get to close. This concludes our question-and-answer session. I would like to turn the conference back over to Mr. Leon for any closing remarks. Thanks for joining us today. We will be presenting at several investor conferences during the summer. Really look forward to seeing you and engaging in more conversations. Thanks so much. Bye-bye. The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.