Good day, and welcome to the California Resources Corporation First Quarter 2024 Earnings Conference Call. Please note this event is being recorded. I would now like to turn the conference over to Joanna Park, Vice President of Investor Relations and Treasurer. Please go ahead.

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 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; 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 the 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, on 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 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 reflects 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'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.

The first question comes from Scott Hanold of RBC Capital Markets.

I was wondering if we could get more details on what you're hearing regarding the classics permit. You indicated that Kern County's EIR is scheduled for an August timeframe. Is it your understanding that the EPA and Kern County will issue their respective EIR and draft final permits at the same time in August? Additionally, what are the key discussion points from those hearings that give you confidence in maintaining your FID timeline and first injection?

Yes, I have complete confidence. While we are unsure about the timeline from the EPA and Kern County and whether they will align, we expect to be on track for the EPA permit, which is a subsurface permit, by summer. The County's permit, which pertains to above-ground conditional use, is now aimed for August, making it a couple of months behind the EPA. Our confidence in reaching the final permit and moving quickly to FID for our first project remains strong. As discussed in the last earnings call, we are still targeting the permit's receipt in the latter half of the year. Establishing a gold standard for CCS permitting in the U.S. is crucial, and we are being thorough, given the significant stakes involved. We have 1 billion metric tons of pore space and expect to inject 20 million tons. This first permit will set the groundwork for subsequent permits. While it is challenging to meet quarter-over-quarter timelines, our confidence in the permitting process and community engagement continues to grow. Additionally, opportunities among emitters are increasing over time, enhancing the value of the pore space. Our confidence level is high, and we are focused on completing this first permit, which involves numerous requirements. Our team is dedicated, and we are eager to reach 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 includes both emitters and greenfield projects. When you have a scarcity in a brand-new business model and you're years ahead of others in obtaining a first injection permit, as you near that goal, more industries of various types, both brownfields and greenfields, are approaching us and expressing interest in reserving pore space. Currently, our main focus is to secure that permit. Announcing additional emitter deals prematurely without the permit may not be well received by the market. We prefer to reach that first permit before sharing details about the discussions we’re having.

My follow-up question is about Aera, with the closing expected in the coming months. Can you share what some of the immediate advantages we might see from the combined company are? Nelly mentioned potential softness in natural gas demand because of increased solar usage in the summer. Previously, you discussed synergistic opportunities between CRC's legacy assets and Aera. Can you provide insight into the immediate benefits we could anticipate?

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.

Thank you, Francisco. Scott, as Francisco pointed out earlier, our synergies will focus on three main areas: infrastructure, supply chain, and general and administrative costs. Specifically for infrastructure, we aim to take advantage of the close proximity of Aera's operations to ours. There is already some existing connectivity between the fields, but we plan to enhance that further. Our goal is to enable the transfer of power, gas, oil, and water across these fields, which could either improve our product margins or reduce operational costs. For instance, some Aera fields are near our Elk Hills power plant, presenting the opportunity to shift from PG&E power to our own, reducing costs. Additionally, Aera's steamflood operations make it a net consumer of gas, while we are a net producer, which opens up further opportunities for us. We can also explore different oil blends to enhance margins and look into water treatment for beneficial use, particularly since we operate in an agricultural region in Kern County with high water demand. On the supply chain front, our scale will effectively double, allowing us to reconsider our operating model. We can explore in-sourcing some services while also examining outsourcing possibilities to learn from both companies and integrate best practices into the combined entity. G&A is another clear area for potential savings due to our overlapping operations.

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 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, to 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 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 had 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.

'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. On the slides, we showed that Aera's decline and CRC's from 2023 averaged about 6% for both companies. These assets are quite similar, featuring excellent rock and low decline rates. From the corporate decline rate of approximately 11.5%, you can reach mid-single digits through workovers, sidetracks, and increased workovers on capital and operating expenses. That's essentially what Aera achieved last year and is continuing to do this year. Based on last year, I would expect a combined decline rate of 5% to 7% for this year with one rig operating between the two 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, we are closely monitoring the situation. Data centers require around-the-clock power and are increasingly seeking carbon-free energy sources. They also require land, space for expansion, and water, all of which we can provide at Elk Hills and Belridge. In California specifically, due to limitations on nuclear development, we are left with just one plant. The only dependable sources of carbon-free power are natural gas-fired plants equipped with carbon capture and storage. We believe our solution is ideal for supporting data centers in California. Our Elk Hills project, CalCapture, presents an exciting opportunity for the future. We are already having preliminary discussions on this front. Now, I’ll hand it over to Chris Gould for insights on the data center aspect.

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 are 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?

There is a lot of potential here. We mentioned that in Q3, CRC has conditional use permits for Elk Hills, Buena Vista, and Kern Front. Aera also has several CUPs that are pending. This means we will have many opportunities to return to specific field programs. We are still determining how best to implement these programs, including the number of wells and injectors. It will take some time to get the CUPs launched, and we don’t anticipate a quick process. As we mentioned, this is likely to be more relevant in the second half of next year, but we are confident in our ability to move forward with permitting using this approach. This method has been effective in other areas of the state where CalGEM is the lead agency, so we believe it will work well here too. Although it is not ready yet, using the CUPs is a solid solution for permitting.

Our next question comes from Betty Jiang of Barclays.

I wanted to follow up on the permitting question a bit more. Regarding the conditional use permit and the other options beyond the resolution of the Kern County litigation, could you provide more detail about the legislatures or organizations involved in granting these permits? Additionally, could this potentially offset the permits needed in Kern County and help address the challenges you are currently facing there?

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. Looking back over two years ago with Brookfield, which is our first joint venture of this type, there were numerous uncertainties about how developments would unfold. We established a staggered payment system linked to specific milestones as we initiated the reservoirs, starting with the first one called 26R. The initial payment was for the draft permit we obtained in December. The second payment occurred when the public comment period was finalized to Brookfield's satisfaction. The third payment will be associated with the final permit and reaching the final investment decision. I anticipate this could happen either later this year or at the start of next year, depending on our progress towards that final decision. As I mentioned earlier, we are aiming for the final permit in the latter half of this year. We have our gas processing plant, owned by us, capable of capturing 100,000 tons of CO2 per year, which is already built within the project boundaries and can be executed rapidly. Therefore, discussions with Brookfield will center around the final investment decision, which will trigger the final payment. This is contingent on the EPA's final declaration of the reservoir size. We are seeing positive adjustments to our anticipated numbers, which is why we presented a range for the third payment that could exceed the first two payments, acting as a catch-up if the reservoir size is larger. Expect more updates in the latter half of the year as we approach the final permit. Once we reach the final investment decision, we will provide updates regarding the Brookfield payment. I believe we will soon be positioned to collect all three payments and look forward to introducing more reservoirs into the joint venture.

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?

In the first quarter, the delay in the power plant turnaround resulted in a loss of about 800 barrels equivalent per day, all of which was gas. This had a significant impact, but as we mentioned, the value of the plant is increasing daily. Our team does an excellent job of maintaining the assets, and during this period, we took the opportunity to conduct an extensive review to ensure everything was functioning properly, including inspecting the steam turbines. This was completed successfully, and the plant has been restarted, now operating at full capacity. Those are the main factors affecting the first quarter. We also faced challenges from weather, including storms and mudslides, along with the PSC effect, which is why we find ourselves at the lower end of the production range. Gas production was more impacted than oil, which actually performed well, coming in on the high end of the range. Looking ahead to the second quarter, we experienced some spillover from the Elk Hills turnaround, but we managed to get it back up and running fully in April. In the second quarter, we are planning with a higher Brent price, which will affect PSC due to its inverse relationship with production. Additionally, we need to reduce the power plant's capacity because there is an increased generation of solar energy, which lowers power prices. Consequently, we've decided to temporarily scale back the plant's output instead of sending power into the grid during this period. This seasonal change is how we're seeing developments unfold in California. We have plans for the future as a result of our merger with Aera, which brings us certain advantages. We have some Permian gas that doesn't meet utility specifications, but we can still use it in our power plant. Running the plant at its full capacity enables us to utilize all the gas, but when we decrease capacity, we consume less gas, leading to lower sales. After the merger, we'll be able to direct that gas to Aera's fields, alleviating some of their purchasing needs at Belridge. The two fields are already connected by a pipeline, providing us with a way to manage the gas going forward. There are two separate issues concerning the plant: the first is the turnaround, and the second is market conditions. I'll ask Jay Bys to provide additional insights 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.

I believe you understand correctly, Leo. CalGEM is undergoing a thorough evaluation of their procedures and seeking to enhance their approach to permitting in California. As I mentioned, there are ongoing sidetracks and progress in our fields, and we are witnessing approvals in other areas across the state. However, we have not observed any new well permits issued this year under the new guidelines, as CalGEM is still working through the process. I cannot speak for them regarding their timeline. We maintain regular communication with them and are eager to return to full permitting capacity and a complete drilling program outside of Kern County. It's difficult to pinpoint an exact date for when CalGEM will be prepared, but we are already seeing significant progress on sidetracks and workovers. We anticipate that new wells will be back on track soon. While I can't provide a specific timeline, we are encouraged by the advancements being made, and the agencies are indicating that we are approaching 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. There are several interesting dynamics at play. We see California emitters winning grants from the Department of Energy to capture CO2, but this will only be valuable if they have a storage site for the CO2. Our discussions with brownfield emitters primarily focus on CO2 pipelines. We are waiting for the legislature to provide guidance on how CO2 pipelines will function in the state. We expect progress during the budget session or later in the legislative year, which could serve as a positive catalyst. However, without those pipelines, connectivity to brownfield emitters will be lacking, putting the DOE funding and major capital projects at risk. This situation is a key factor slowing down some brownfield emitters. For greenfield emitters, our focus is on optimizing pore space allocation. We have discussed $50 to $75 per ton storage fees that the joint venture will collect from these emitters. They also need a CCS storage site to ensure their projects are clean. Many markets, like hydrogen and ammonia, are still developing, and there is currently no market for the clean versions of these energy sources. Discussions about offtake are ongoing. There are additional challenges for greenfield projects regarding how to get CO2 processed once we secure the permit, but less certainty about selling the product and what premium it might achieve. The situation is evolving and very dynamic, with many engaging discussions occurring. Securing the final permit for classical processes will ultimately unlock many 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. The conditions that supported the decision regarding the Aera merger remain strong and are improving in several ways, especially with the confidence we've gained from the synergies observed at the start of the year alongside rising Brent prices. It's important to note that as a private company, Aera had a different approach to hedging their volumes compared to us. They have historically engaged in more swaps to secure certain pricing, which benefits our planning but limits potential upside. However, they still have some barrels unhedged that could offer additional pricing upside in the near term. It's challenging to quantify this right now, but we will provide an update once we finalize the 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.

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