CRC - NYSE

Good day, and welcome to the California Resources Corporation First Quarter 2024 Earnings Conference Call. [Operator Instructions] 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 7, 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 and 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 midyear 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; and three, our advantage position to provide the energy and decarbonization solutions California needs. So 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 waterfloods and steamfloods, 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 EBITDAX 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 1-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% to 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 3 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 1-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 a new drill permit 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% to 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 6 months of closing. We are targeting to close the transaction in mid-2024, and we'll 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, one March 28, 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 22 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 manner that complies with California's environmental standards, which are undoubtedly the highest in the U.S. The comments received were a result of our 4 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 to 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 barrels of oil equivalent per day and 48,000 barrels 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 at 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 maintained 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 to $1.5 billion and increase our revolver [ letter of ] commitment from $630 million to $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 financial flexibility to deliver on our strategic objectives. Turning to second quarter, gross production is expected to average around 93,000 barrels of oil equivalent per day, reflecting modest natural declines. Net production is expected to range between 74,000 and 78,000 barrels 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. This 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 reflect the actual reservoir capability and performance. We expect to deploy $50 million to $57 million in capital in the second quarter and will 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 E&P 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 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.

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

Yes. I was wondering if we could give a little bit more color on, I guess, what you're hearing with the classics 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 -- your 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?

Scott, yes, confidence is absolutely there. The lack of -- we don't know exactly the EPA and Kern County, the timeline and if they're going to be ultimately synced up. We know we -- if you think about the EPA permit, which is a subsurface permit, we look at to be on track for the summer. And 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 and -- 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 of 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 in the -- given that we have to announce this publicly, the confidence continues to grow on the permitting process, on the engagement with the communities. And I would say the excitement is there also on emitter opportunities. I would say more emitter opportunities unfold as time passes. So, that poor space is becoming more valuable. So the confidence level is 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.

Yes. And just to clarify some of that, 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 ]. It's -- 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, brownfields 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. 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 to 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 like -- and 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?

Yes, 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 2 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.

Yes. Thanks, Francisco. Scott, like Francisco mentioned in his earlier comments, the synergies are really going to be focused around 3 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 the close proximity of Aera's operations to ours. There's 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 their steamflood 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, on 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 in-sourcing opportunities for some of the services. We will also look at outsourcing some and learn from the 2 companies and bring the best practices to the combined company. And G&A is an obvious one. Obviously, with overlapping footprint, we see material opportunities there as well.

Yes. So the plan is to migrate to the best of combined teams from a G&A perspective. And so, we're working it. And the commitment is, we're going to get to $50 million of synergies within the first 6 months. So there is a low-hanging fruit. There is a lot of opportunity, and we're excited about it.

Our next question comes from Kalei Akamine from Bank of America.

My first question is on the use of cash. So the buyback this quarter had 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.

Yes. 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 the debt. And our commitment is to get to a less than 0.5x leverage ratio on the debt. But we think we can get there pretty fairly quickly. And the amount of cash generation from this business is absolutely tremendous. And so, we're going to look to increase the dividend, subject to Board approval, after closing. And then, you have the 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 and looking at the lag in the stock performance, 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 of returning cash to shareholders. We'll continue doing that. And 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 '25?

Yes. I guess, one clarification is, remember, the effective date on the transaction is 1/1/24. So there's already cash in the system with Aera's balance sheet that's being used to delever already as we go. So we do have a few things to take care after closing or before closing. But I think the prime objective post closing and once we get on track to get the leverage to 0.5x will be to distribute cash to shareholders. So that's what we did in '23 when we have no permits for oil and gas. That's what we'll do in '24 and into '25.

Got it. I appreciate that. My second question goes to your pro forma guidance, CapEx, OpEx and [ ARO ] 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 '24 guidance? And I'll leave it there.

Yes. '24 guidance, we haven't communicated for the combined company. You have the view for CRC midpoint of production, 70,000 BOEs per day, so basically, a continuation of what we have delivered in the first quarter, and our capital, $200 million to $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 '24. 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 to $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, 1-rig program on a 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 '24, what are your expectations for an oil decline rate?

Yes. So we -- 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% to 7% on a combined basis based on last year. I would expect something similar for this year with 1 rig running between the 2 companies.

Our next question comes from Nate Pendleton of Stifel.

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?

Nate, definitely, watching it unfold. If you look at what the data centers are looking for is 24/7 power, but they're also looking for carbon-free power. They have -- they need land. They need running room. They need water. We provide it all at Elk Hills. We 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 1 plant, the only reliable sources of carbon-free power are going to be natural gas-fired 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.

Yes. Thanks, Francisco. Nate, thanks for the question. Yes, 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 reservoirs. So you all know CTV I is about 120 miles or so from LA, and CTV II through V are 30 to 65 miles 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. And 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. And 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 upper 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 Q3, 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.

I wanted -- sorry, just a follow-up on the permitting question a bit more. I guess, on the conditional use -- some of -- the 2 other options beyond the Kern County litigation resolution, when it comes down to the conditional use permit, and Francesco, what you just talked about, the multi-basin approach, what is it -- can you just get the -- 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?

Betty, yes, 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 has 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 is 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, and that's what gives us confidence that we're going to be able to run a 1-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 is working it and progress is starting to show up.

Got it. 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 third install -- payment for Brookfield? And when should we expect in terms of FID for the cryo plant for the first injection plant, which I believe will be followed by the hydrogen plant?

Yes, Betty, so as we looked 2-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 that's -- 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 are looking for final permit in the second half of this year. And 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 field boundaries. It's already in place and something that we can execute quickly. So the conversations with Brookfield will be around that FID as a project that triggers the last payment. But it also has the condition of final declaration of the size of the reservoir by the EPA. So we are seeing upsides to the numbers that we had planned for. So 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. So 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 3 payments and looking forward to adding more reservoirs into the JV.

The next question comes from Leo Mariani of Roth MKM.

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 in terms of 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 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 '24?

Leo, yes, first quarter, the delay of the power plant turnaround was about 800 barrels equivalent per day, but it's all of it gas. And so, that was the impact there. And as we talked about, this is -- this plant is growing in value every day. And we have -- our team does a fantastic job of maintaining the assets. We took the opportunity to do an expanded review of -- to make sure everything was functioning and looking at the steam turbines and doing an inspection. So, that was completed successfully. The plant is running -- got restarted, running at 100% capacity. And those are the -- 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 yes, that's why we're at the lower end of the range. More -- gas struggled a little bit more than oil. Oil actually was above -- 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 2 primary issues for the first -- 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 again 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 allows -- that brings prices for power down. So, rather than send power into the grid in this environment, we decided to ramp down the plant for -- 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 Permian 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 megawatts plus or minus, 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 2 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 they're 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.

Yes, California has actually become a net power exporter over the course of the last couple of years. In fact, power is 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 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, and we've got a capacity revenue stream that goes with the power plant. So 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 I 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 LA Basin operations, the Sac Basin operations. You mentioned the agencies 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, and it'd be great to kind of drill some wells.

So, that's -- I think 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. There's -- we haven't seen new wells permitted this year under the new format. I think CalGEM is still working through that. Can't speak for them as to when they're going to be ready. We engage with them very frequently and looking to get back to full permitting capacity and full drilling program outside of Kern County. So hard to pinpoint the specific date when CalGEM will be ready. But we do see progress already -- meaningful progress on sidetracks and workovers. And anticipation is that we'll get the new wells back on track soon. So 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.

I just had a couple. You mentioned earlier that there is interest from brownfield and greenfield emitters that are looking to reserve pore space. And 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.

Yes. So you have a few very interesting dynamics at play. We see California emitters winning grants from the Department of Energy to capture CO2 and -- but that's only going to be valuable and good if they 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. And 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 to $75 per ton storage fees that the JV is going to collect from these emitters. Ultimately, they need a storage -- 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 are -- 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 very dynamic. A lot of really interesting discussions happening. And that final permit on classics will ultimately unlock a lot of these exciting discussions.

Great. And I wanted to ask about the Aera acquisition. And 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. And 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 valuation, 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.

Yes. 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 at 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 ability to plan, but it takes away some of the upside. They do have some barrels open that will provide some further upside to pricing in the near term. Difficult to quantify at this stage and -- 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. Thank you so much. Bye-bye.