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

Welcome to California Resources Corporation’s Third Quarter 2023 Conference Call. Participating on today’s call are Francisco Leon, President and Chief Executive Officer; Nelly Molina, Executive Vice President and Chief Financial Officer; as well as CRC’s entire executive team. I’d like to highlight that we have provided slides in the Investor Relations section of our website, crc.com. These slides provide additional information about our operations and our third quarter results. We have also provided information reconciling non-GAAP financial measures discussed to the most directly comparable GAAP financial measures on our website as well as in our earnings release. Today, we are making some forward-looking statements based on current expectations. Actual results may differ due to factors described in our earnings press release and in our periodic SEC filings. As a reminder, we have allotted additional time for Q&A at the end of our prepared remarks and we ask that participants limit their questions to a primary and one follow-up. With that, I will now turn the call over to Francisco.

Thank you, Joanna. CRC continues to demonstrate what it means to be a different kind of energy company. We’re executing on our low decline and high cash flow generating oil and natural gas business, increasing shareholder returns and advancing our leading carbon management business. We are doing this all while working to provide innovative energy solutions to help California meet its 2045 decarbonization goals. Cash flow, carbon and California are our core strengths, and our quarterly results demonstrate substantial progress on all these fronts. Starting with cash flow. During the third quarter, we continued to deliver strong results, producing 85,000 barrels of oil equivalent per day and generating $71 million of free cash flow. We remain on track with our 5% to 7% entry to exit production decline expectation for the year and have progressed our business transformation efforts, targeting $55 million of annual run rate cost savings that are expected to lower our E&P business cost structure by approximately $2 per barrel. Nelly will expand on the cost reductions achieved to-date, our shareholder return progress and cover the key business drivers for 2024. Moving on to carbon. We continue to expand our reach and strengthen our role as the market leader for CCS in California. Our first-mover advantage is demonstrated through our multiple Class VI permit applications with the EPA. A recently published tracker by the EPA shows our leadership in Region nine with over 50% of all permits submitted to-date and show CTV I on track to receive the first draft classics permit in California by year-end. Additional progress can be seen in our growing project queue as we develop pore space in other parts of the state. We are pleased to announce our own capture and storage project at CRC’s cryogenic gas processing plant at Elk Hills. This project will install new equipment to capture 100,000 metric tons of CO2 per year from some of our natural gas production through a pre-combustion separation process and permanently sequester the CO2 in our CTV I reservoir. We are targeting FID of this project during the first half of 2024 and first injection by the end of 2025. This project is co-located at Elk Hills with our CTV I CO2 storage reservoir and is our fastest track to CCS adoption and the first CCS cash flow in California. CRC expects to earn 45Q credits and other incentives and anticipates paying CTV JV an injection fee for CO2 sequestration services. CTV JV’s economics are expected to be in line with previously announced storage-only deals with an EBITDA in the $50 to $75 per ton range. Further, this project will increase the operational efficiency of our cryogenic gas processing plant, which will benefit from improved propane recovery, higher production and reduce the carbon intensity of the electricity generated from the Elk Hills power plant, which, as a result, will potentially lower the carbon tax for the plant. Today, we have also announced a new Carbon Dioxide Management Agreement or CDMA with NLC Energy, an innovative renewable energy partner. CTV will sequester 150,000 metric tons of CO2 per year from a new renewable natural gas facility that will be constructed at our proposed CTV Clean Energy Park at Elk Hills. Once online, CRC will have the option of utilizing this product to supply facilities at our energy park with decarbonized energy or we can sell the RNG to the market. With this new CDMA, combined with our Elk Hills gas plan capture project, we now have reserved 57% of the pore space in our CTV I storage reservoir. The CTV Clean Energy Park at Elk Hills will provide unique advantages and benefits to industrial partners. The park provides greenfield projects with access to land and proximity to a favorable end-user market where we can reduce the all-in cost of production and effectively transport decarbonized products by conventional means, effectively creating a virtual CO2 pipeline designed to decarbonize Brownfield emissions by capturing the market for their products versus the CO2 at their facilities. The proximity of CTV storage reservoirs to major demand centers in the Bay Area, Los Angeles and the broader Central Valley helped make greenfield projects competitive with great products that are transported to California from thousands of miles away. Furthermore, CRC and CTV receive an added benefit of access to renewable fuels for use in our own processes to help further lower our carbon intensity while also providing development and employment opportunities to our local communities. And finally, our California positioning is a key advantage that enables us to develop energy solutions for the state’s future energy landscape. CRC has the leading permit application position, land and mineral ownership, strong partnerships and California expertise. We control several key aspects and variables that allow CRC to derisk the new energy projects and enable commercial-scale CCS quicker than many others in the state or even the U.S. We are also well positioned as the largest natural gas producer in California. We believe low carbon intensity natural gas will play an important role in the energy transition. We want to grow our contribution of local supply by developing our inventory. As such, we have identified incremental resource of 1 TcF of natural gas in our existing fields in Sacramento and Western San Joaquin. We’re in the process of high-grading the inventory and finalizing plans to develop this resource. Further and to validate our low methane intensity positioning, we are pursuing third-party responsibly sourced gas designation for our current and future production, which we expect to have in 2024. Over the past several years, CRC has primarily focused on developing our oil inventory. However, California’s gas market continues to experience significant volatility due to the reliance on imported gas from other states and aging infrastructure. This, coupled with strong expected demand through 2045, will likely lead to continued premium pricing relative to the rest of the country. Our teams are working on development plans to unlock CRC’s untapped natural gas potential to meet this need with local and responsibly sourced supply. At CRC, we’re determined to lead the energy transition. We are committed to improving our products and providing carbon management solutions that help enable renewable and replacement fuels. And now I’ll pass it over to Nelly to provide an update on CRC’s financial position and several important points on our preliminary 2024 financial and operational outlook. Nelly?

Thank you, Francisco, and welcome again, everyone. Shifting to the quarterly financial results, we executed on our plan and delivered another strong quarter of free cash flow. Results were largely in line with guidance and we have modestly narrowed our full year 2023 guidance to reflect our operational results year-to-date. The increase in oil prices during the quarter meant production sharing contracts had a greater impact on CRC’s net oil production. Brent averaged $85.95 for the quarter compared to the price of $75.28 per barrel used to set guidance. The nearly $11 difference in price assumption contributed to a $7 million increase in cash flow, but also impacted oil production by 1,200 barrels down due to PSE effect. We have auctioned nearly all of our business transformation initiatives and expect to see at least $55 million of run rate level savings beginning in 2024. Our work continues and we believe we can further identify opportunities over time. We expect to exit the year with a solid balance sheet and ample liquidity. To demonstrate our confidence in future performance and our commitment to shareholder returns, the Board has authorized a dividend increase for the third consecutive year. And as a result, we are increasing our fixed dividend by 10%, bringing our quarterly dividend to $0.31 per share. This reflects an annual dividend of $1.24 per share with an approximately 2.4% yield at the end of the third quarter stock price. Since year-end 2020, we have returned $736 million through dividends and stock buybacks while increasing our cash position by over $450 million. Our share repurchases amount to 18% of the company’s shares outstanding at the end of the calendar year 2020. CRC has a $1.1 billion share repurchase program in place with $497 million of capacity remaining through June 2024. In addition to our stock buybacks, we have delevered our balance sheet by repurchasing at a slight premium $35 million of our notes, reducing the principal amount of our outstanding debt to $565 million. Looking ahead to 2024, we anticipate an increasing level of drilling activity in the second half of next year. We have various paths to achieve this beyond the resolution of Kern County EIR. The first is by utilizing updated field-level EIR. The second is by pursuing natural gas projects within the Sacramento Basin. And finally, through developing a more robust inventory of sidetracks to access bypass hydrocarbons and new reserves. CRC has considerable expertise in drilling sidetracks from existing wellbores. We have executed over 1,000 sidetracks from our THUMS islands, which target reserves from one of the largest oil fields in the U.S., our Wilmington field. CRC is committed to increasing its level of activity and the optionality we have for 2024 reflects the benefit of our diverse portfolio and extensive operating expertise. In addition to our increased activity set on the operations front, we have scheduled a four-year major maintenance at Elk Hills power plant and one of our gas processing facilities at the beginning of next year, which will require a combined capital investment of approximately $34 million. This downtime is expected to reduce gas volumes by approximately 20 million cubic feet per day for the first quarter of 2024. The Elk Hills power plant is a very important asset for us and for the CAISO Grid. CRC has consistently supplied both energy and generating capacity to the CAISO marketplace. In 2024, we have contracted an increase of approximately $45 million in capacity revenue, which will flow through our electricity revenue line. Increased capacity revenue is expected to offset both of these major maintenance activities. We continue advancing our strategy on both our conventional and energy transition business to be the energy solutions provider for California. Francisco, back to you.

Thank you, Nelly. As we look to 2024, we see a number of exciting catalysts for CRC as we remain disciplined and focused on building a different kind of energy company. Cash flow, carbon and California remain our core strengths. We continue to deliver meaningful value to our shareholders. We are producing some of the lowest carbon intensity oil and gas energy for the state and are helping California reach its climate goals through industry-leading carbon management solutions. Thank you for joining us on the call today. We’ll now open the line for questions. Operator?

Today’s first question comes from Kalei Akamine with Bank of America. Please proceed.

Hey good morning guys. I’ve got a couple. So I apologize in advance. The first one is more of a housekeeping one in nature, though. I want to understand why there was a CapEx provision in the quarter. Presumably, your permitting constraints were already anticipated, but the market seems to be interpreting that maybe there’s a new message that the constraints have maybe gotten worse. So wondering if you can first clear that up and maybe while we’re at it, some early thoughts on 2024 could be helpful.

Yes. There were some delays in third quarter facility spending that we expect to complete before the end of the year. It's mainly a timing issue related to the facility projects we planned. I wouldn’t read too much into it. For 2024, we have identified significant catalysts. While we are not ready to provide guidance, there are key factors to consider when modeling next year. One is our business transformation work, which has led to an annualized savings run rate of $55 million. The team has done a great job implementing these changes, and we will continue to seek new ways to improve efficiency and further reduce costs, which have decreased by about $2 per barrel. Additionally, we have a resource adequacy contract for our power plant that will contribute an extra $45 million of capacity. As a reminder, this plant earned about $50 million in resource adequacy payments this year, so this increment almost doubles that amount for being on standby for the grid. We have some exciting catalysts ahead next year. We also need to maintain the plant to ensure it operates at its best. We have not received any new information on permits, but we believe that in the first half of the year, you should anticipate a one rig program. In the second half, we expect to return to a more typical run rate with three or four rigs for drilling activity.

Got it. That’s very clear, thanks. My second question is on natural gas. And I want to spend a little bit of time framing this out. So I apologize for the multiple parts. So I guess, first, the dynamics in California are obviously very tight. Just kind of looking at the chart, it implies that something has changed post-COVID. I guess, first off, can you help us understand what that change is? And then next, all activity has a value skill, right? So when you think about gas, at what price does it compete with oil and you can pick your oil price, maybe call it $80. And then when you think about this opportunity longer term and I think your slide on the balances actually frames this very well, California gas has a direct link with the Permian Basin, albeit that build-out is still taking place and there’s a couple of years before it really gets in the way. But I’m wondering what you could do now today to sort of get ready for that opportunity? How much low friction growth do you have in the bag? And how do you think about the infrastructure constraints?

Yes, Kalei, you framed it well. To emphasize the situation in California, the state currently requires more natural gas. We import over 92% of the gas we consume, and being the fifth largest economy, we have significant industrial and commercial demands for gas in addition to residential needs. This gas is sourced from other states and is typically not under long-term contracts, as it comes to the West Coast primarily for better pricing. However, we are now competing with LNG export facilities being developed in various parts of the U.S. This creates a major challenge for California and poses risks to baseload power. Our commitment is to seek solutions from an energy standpoint for the state. We possess a considerable amount of gas, which we haven't emphasized in recent years. Earlier this year, we began exploring whether we can improve a number of locations within existing fields that are close to facilities and customers, and today we are announcing the results of that initiative. By pursuing RSE designation, we aim to underscore the distinction of the gas we import. Not all gas is alike, as gas from other basins, particularly fracked gas, can have higher fugitive emissions. We prefer California-produced gas, specifically from CRC. We're optimistic about the immediate prospects. While we are not yet discussing the economics, there is a structural premium for natural gas in California that we anticipate will continue for many years. Having local resources to meet the state's needs is vital. Our positioning is strong, and we believe we can generate substantial returns for shareholders akin to those from oil. This does not mean we are ignoring opportunities to drill more oil wells. We are confident that low carbon intensity oil and gas will remain relevant for decades to come. California needs both oil and gas, and we are capable of supplying both. We are now highlighting the gas aspect of our operations, which we haven't previously discussed, and I am very optimistic about the potential of our assets.

So I guess just to clarify, the change in California is just greater power demand. And then could you address the infrastructure constraints piece? How much can you grow without spending additional material capital dollars on infrastructure today? And how much do you think you could spend over the next few years?

Yes, it’s too early to quantify things. To elaborate on the resource base, when discussing Western San Joaquin, we are primarily focused on wet gas at Elk Hills and Buena Vista, where we have significant existing infrastructure. The emphasis now is on drilling deeper, but known productive wells. We are shifting our focus back to these gas wells, and we also benefit from generating NGLs from this production. As we go north to Sacramento, the gas is dry, with minimal processing needs and ample infrastructure in place. There are established markets, so the main focus is acquiring permits and initiating drilling. We still need to determine our development pace and are working on assessing the project's economics for future disclosure; however, we are very optimistic about our position. The situation in California has changed, as the state has a natural gas shortfall but consumes large amounts. We noted a significant price difference this year, with natural gas at $47 per Mcf in the state compared to about $4 in the rest of the country, highlighting a tenfold premium in a state that heavily relies on imported gas, with 92% being imported. This underscores the need for in-state gas storage solutions to mitigate market shocks and fluctuations caused by aging infrastructure. The recent expansion of storage capacity in California should help stabilize prices this winter, although we need to see how this develops. Ultimately, demand remains robust, and it is clear that the state's dependence on imports puts its energy security at risk, which poses challenges.

Thank you. And our next question today comes from Scott Hanold with RBC Capital Markets. Please go ahead.

Yes, hey thanks. When you were in your prepared comments talking about the Kern County EIR and looking at the second half 2024 and doing some more drilling, you kind of mentioned, obviously, you’re potentially more drilling in the Sacramento Basin for gas sidetracks and then obviously exploring the field-level EIRs. With respect to like sidetracks and I mean, do you need to get permits for that? Or is the permitting process a little bit different?

You do need permits for sidetrack, Scott. It’s a little bit different process. We’ve seen not only CRC pursuing this, but most of the other operators in the state have been using the sidetrack inventory. So relatively high confidence that we’re going to be able to unlock multiple options here as the year progresses. Still very much looking for resolution on Kern County EIR, anticipate hearing more than likely in the first quarter, first half of next year. So that’s still moving forward. We don’t have any new updates other than the briefs have been completed and the decision is likely early next year. But we see multiple paths to getting back to drilling wells in sidetrack. It’s an exciting opportunity, different permitting process, but ultimately in line with the expectation to satisfy all the requirements from some of the agencies that we need to. It’s something that we’ve done over the years. The industry is very comfortable doing that. So we feel that’s a path forward. And as you said, Sacramento Basin different counties, different needs for the product will be out there as well. So we’re advancing all fronts and difficult to handicap which one comes first, but we’re growing more and more comfortable that there will be a solution in the second half of next year.

Okay. Just to clarify, you are currently obtaining permits in the Sacramento Basin for gas wells and pursuing permits for the sidetracks and yards. You are doing this while also hoping for the Kern County EIR to be approved at this time. Is that an accurate statement, or is it something you are still working towards?

No, we are actively pursuing all avenues. To be clear, we have not received a new permit this year. However, we are working on all the solutions we previously identified to get back on track. This includes the Kern County EIR, field level EIR, sidetracks, and drilling outside of Kern County. The team is focused on all these efforts. We also look forward to discussing our plans for 2024 in February next year.

Got it. And then maybe a little bit on the CMB business. You talked about the Elk Hills gas plant. And obviously, it’d be, I guess, the first brownfield went out there now that you guys have contracted with yourselves for. You already discussed a little bit on the economic parameters. I’m just kind of curious, how does that economics work if in these are, to your understanding, still right now 45Q LCFS eligible? And are you sharing that credit with the JV? So is there some benefit to like CRC by itself through this process as well?

The CRC is investing in the capture equipment for this project, which differs from our larger scale plans due to being a pre-combustion capture system. This involves low capital requirements and utilizes the already operational CGP1 cryogenic plant as an add-on. While this is an expense for CRC, we will pursue incentives like 45Q and LCFS available for CCS. Additionally, the plant itself brings benefits to CRC, such as a higher yield of natural gas liquids, specifically propane, and increased production. Although we are not completely eliminating emissions, we are reducing them, which should result in carbon tax reductions. The capture system is responsible for earning the 45Q credits, and we will pay a storage fee to the joint venture, similar to what we require from others. However, CRC stands to gain multiple advantages that benefit its shareholders. This project is significant and demonstrates progress, showcasing effective operations. Importantly, it positions us to advance CCCI by 2025, likely making it the quickest project in the state to earn the 45Q credit, thereby addressing feasibility concerns regarding CCS. Having more control points will aid in reaching those goals.

Thank you.

Thank you. And our next question comes from Leo Mariani with ROTH MKM. Please go ahead.

Hey guys. A few questions around some of these numbers that you’ve thrown out here. So the first one is on this kind of $45 million sort of resource adequacy payment from the state. I guess you’re saying that’s kind of roughly doubling in 2024 versus 2023. I just wanted to make sure I sort of understood the mechanics around that. Is this basically the state been cutting you a check so far in 2023 for that amount? And that amount sort of doubles next year? Does this flow through your sort of electricity business margins or if you guys are selling the power, maybe you don’t really get the check there? I’m just trying to kind of understand if that’s kind of free money for being on standby or if you are producing, then maybe you don’t get all of that. Just kind of some help around the mechanics here would be great.

Great question. So as you know, the state of California has a big penetration of renewable energy and that doesn’t work 24/7. So you require baseload from different sources to make sure the lights are on in the state. So years ago, California entered into this resource adequacy program through the utilities that they pay independent power producers to be on standby. Let me turn it over to Jay Bys, if he has a few more thoughts around regulators adequacy and what it means.

Yes, thank you. To clarify, the state does not directly pay for capacity. Anyone providing load within California, particularly in CAISO, must have sufficient capacity to support that load. This applies to both utilities and aggregators, who are responsible for securing the necessary capacity. Essentially, they are contributing to CRC to ensure that this capacity is available. In the past, there was a more relaxed approach regarding how much capacity certain parties backed up using the marketplace. However, CAISO has now firmly emphasized the importance of ensuring that load is properly backed up. Consequently, the current pricing reflects the true market value of this capacity. Additionally, having an asset that is consistently available is certainly appealing in the marketplace.

And Leo, just to add one more, just to clarify. So we have 550 megawatts at Elk Hills. We use about a third of that power for our own consumption in the oilfield and two-thirds is available to sell to CAISO and into utilities. So this is a way to guarantee that supply to this resource adequacy program. And it’s another way to kind of showcase that you want to be long commodity and long power in the state that’s struggling to keep up otherwise.

Okay. Maybe I can just try to phrase this a little bit differently. If the plant pretty much runs at the same rate in 2024 as it does in 2023 and let’s say all other variables are the same such as power pricing, input costs, etcetera, are you getting an extra $45 million next year in the business?

Correct. That’s exactly what typically happens in the third quarter. We just received the payment for 2023. These are contracted capacities that the team has already executed on, resulting in an additional $45 million of cash. Correct.

Okay. Great. Thanks for the clarification. And then just on the $55 million of cost savings, which you’re expecting next year, I just wanted to get a sense, are you seeing some of that already in the second half 2023 numbers? Or do you think that’s kind of an incremental $55 million when the calendar turns..?

From a modeling perspective, I would apply it in 2024. We are already seeing some modal savings this quarter, but there are offsets. There are severance costs and several other factors that need to be addressed, along with significant cost reductions. So you will see the full impact of the $55 million plus for 2024.

Okay. That’s helpful. And then lastly, guys, is there any update on kind of pipeline regulation on the CO2 side there in the state?

We are seeking clarity on Senate Bill 905, which initiates discussions about pipelines in California. Currently, there are no new updates. We expect that at the beginning of next year, when the state sets the budget, there will be an opportunity for the legislature to pass the necessary language, which will ultimately enhance the framework for CO2 regulation. We anticipate obtaining new information early next year. However, we believe that the energy transition cannot delay, which is why we are enthusiastic about our greenfield projects and the project at Elk Hills that involves captured storage. We are positioned to make all of this possible as we await the approval of CO2 pipeline regulations. The integration of emissions with our reservoirs gives us a competitive edge in securing cash flows from this expanding business. We have strong backing from the administration and legislators regarding the pipeline, and we are hopeful that we will see progress in that area early next year.

Thank you. And our next question comes from Nate Pendleton with Stifel. Please go ahead.

Good morning. Thanks for taking my questions.

Good morning.

Regarding the planned spending for the carbon management business on land and easements, how should we think about that type of spending trending into the future? And can you provide some insight into the competition you’re seeing in California for that pore space?

We have a strategy to develop several areas across the state for pore space in the CCS business. In Elk Hills, we have all components of the business located together, including surface, minerals, and emissions. However, as we expand to different areas in the state, we need to acquire land to ensure we have the necessary scale and have considered all elements involved. The anticipated $20 million in easements in the fourth quarter is aimed at expanding our landholdings. This will assist us as we prepare to submit permits and move forward in other regions, allowing us to buy land for future development. It's hard to predict how much we will spend on this in the future. However, you can find more detailed information in our slide deck regarding our activities at CTV II and CTV III. We are developing new sites and submitting permits, with a long queue of projects to come. The easement is for upcoming projects in the CTV IV, V, and VI categories, where we aim to enhance those reservoirs and strengthen our market position amidst competition. We are aware of competition for land rights, although it may not always be evident through permit submissions. There are large developers working on their own CCS platforms. While we can't specify who these companies are, there is demand for land and pore space. Though not widely reported, this demand is present. We are confident in our strategy of building scale and pursuing multiple projects to grow our business beyond our initial market forecasts.

Got it. Thanks for the detail. And you have the potential for equity ownership in a number of the projects that plan to use CTV for CCS. So at a high level, can you speak to your framework for making an investment decision at the various projects, including the NLC RNG facility?

Yes, absolutely. I believe our team made a smart choice to keep the option to participate, which allows us to enter new markets and understand their dynamics. As we progress with the Clean Energy Park at Elk Hills and introduce new technology, it's essential to grasp the value of their propositions and offtake agreements for the success of our CCS operations. Some projects will be a better fit than others—some will be more developed, and there will be interest in investing in certain ventures. We have the option to partner with Brookfield, allowing us to enter together and evaluate the scalability of the markets, pricing points, and our position. If we see a strong return opportunity, we will invest; if development appears to take longer, we may hold off. It's beneficial to have this flexibility. We anticipate making an initial decision early next year regarding Lone Cypress, which I find to be a compelling project for developing the first large-scale clean hydrogen offering in the state. It offers a fast track to market and cost advantages due to its location near the energy park. We are currently working towards the FID decision, which first requires obtaining the Class VI permit. While we are evaluating the project, it's challenging to provide definitive guidance since each project has unique characteristics, funding requirements, and capital structures. However, I appreciate having the ability to assess each project's market impact as it relates to California.

Absolutely. Thanks for taking my questions.

Thank you. And our next question comes from Scott Gruber at Citi. Please go ahead.

Yes, just staying on the capture project at the Elk Hills gas plant, does the economic range there, $50 million to $70 million of EBITDA per ton, just consider the 45Q credits? Or does it also include LCFS? And just some color on the LCFS qualification process and outlook to tap that market as well?

The $50 million to $75 million represents the value for pore space for storage-only projects in California, applicable to both our emissions and third-party emissions. This indicates the fee for pore space, which may involve negotiations regarding credits or cash between the emitters and the joint venture. We can expect a mix of both. Regarding the project, the 45Q tax credit, which is an after-tax amount, means we need to account for it before taxes, resulting in over $100 per ton. We plan to apply for the LCFS pathway since this project supports a power plant providing energy for the oil field, incorporating lower carbon molecules and electrons. We believe it meets the LCFS eligibility criteria. Additionally, we must pay California's carbon tax for any emissions produced in the state, which applies to all industrial groups. This project aligns with our goal of reducing emissions and consequently lowering greenhouse gas costs for CRC. The economics of the joint venture suggest that the $50 to $75 per ton range provides an unlevered return of 10% to 30%. While this range is broad, it reflects our current disclosures. The project is expected to maintain these economics. Furthermore, CRC's benefits include both our stake in the joint venture and additional economic advantages beyond the 45Q credit, including potential added propane and carbon tax avoidance, leading to promising returns overall. The capital requirement for this project is relatively low per ton, contributing to strong anticipated returns across the board.

I appreciate all that color. And then turning to your asset sales. It looks like the P&A activity on the 90-acre parcel at Huntington Beach is going to step up to 40 wells next year. Can you give us a sense of the costs associated with that? And then just ultimately, what’s the cost to clean up the property, P&A, all the wells on the property, rezone and get it ready for sale? Do you have a better sense for costs associated with that?

Yes, thanks for the question. We're making significant progress on the one-acre property. To recap, we have the large 90-acre field at Huntington Beach, which will take more time to abandon and monetize. However, we are currently focused on another field nearby, referred to as Fort Apache, which is one acre. We're making great strides there and have completed the abandonment of the producing wells. We're in the process of finalizing all surface abandonment and are collaborating with the city and regulators to prepare the site for sale, aiming to call for offers in the fourth quarter. To address your question more specifically, once we establish a market value per acre, we would like to discuss associated costs. This will provide insight into what a one-acre abandonment to sale process looks like in this area and will help us apply similar insights to the larger 90-acre property, alongside some timeline estimates for that site. Our main focus right now is the one-acre property, and I believe we are making solid progress. More updates will follow.

Got it. Thanks for those details. Thank you.

Thank you. And our next question today comes from Noel Parks with Tuohy Brothers Investment Research. Please go ahead.

Hi, good morning.

Good morning.

I have a couple of questions. In your discussion about the storage project involving the pre-combustion capture system, you provided some insights. I'm not very familiar with these systems, but I'm interested in knowing what type of equipment vendor you plan to use for that. Is it based on proprietary technology or is it something that's more widely available?

It’s, yes, available. It’s an amine technology. Let me turn it over to Omar to provide more details, but we will be doing the works. CRC will be doing the work. Go ahead, Omar.

Just a little bit more color on the technology. It’s not a new technology. It’s an amine plant that was put in place with our cryogenic gas plant several years ago, but we are repurposing, adding equipment to it to get to the point where we can execute this project. So to answer your question, this is a proof in place.

We have a proven technology that we control within our field, and that truly excites us. We have a lot to demonstrate nationally regarding the viability of carbon capture and storage. There are many factors to consider, such as interstate pipelines and concerns about CO2 injection. However, what we have developed at Elk Hills is the opportunity to consolidate everything in one location, which simplifies many variables, including emission capture. We are confident that this will succeed, and we understand the capital costs involved. This positions us to begin injection by 2025, and I am very enthusiastic about this prospect.

Great. And interesting also to hear you talk about third-party RSG certification being something on track for next year. I was just curious which program or regime are you using for that?

I’m not certain if there are confidentiality constraints that prevent us from discussing it, but there are two major national companies, and most companies in the USA would be one of them.

Okay. Great. And just sort of a general question. It’s clear, as you described the different projects, you’ve already disclosed the ones you’re in the process of putting together that there are a lot of moving parts going on all at once. And I wonder, in your exploration of different opportunities, is there much opportunity that you see in sort of like specifically the waste gas type of industrial plant, whether it’s water treatment or I don’t know how far along sort of carbon capture from ag sources is in the state. But just anything you can tell me about that would be great.

Yes, absolutely. So like I said, there’s a lot of synergies between what we’re doing and what California wants to have happen. And a lot of the waste, you can talk about forest management that we have issues with fires in the state, part of it is the lack of forest management. And we have companies like NLC who we announced are partnering today that are looking for that ag waste. We’ll spend the money to clean up the forest and then we can turn that into clean energy. So that’s part of the overall objective, part of the strategy we’re trying to advance here. But maybe I’ll turn it over to Chris Gould for any additional comments he has here.

Yes. Just to build up on that, when you look at the proximity of our reservoirs, they are in the Central Valley. They’re very close to ag waste in terms of feedstocks and that’s why you see several of these projects are utilizing waste for the production of these renewable fuels, including NLC. So we are doing that and we’re doing it where it strategically makes sense relative to the advantage we have where our CTV storage reservoirs are located. The same is true in Northern California with CTV II through V. That is in a very strategically located near forest waste and forest trimmings, which as Francisco mentioned, are a huge challenge that we can help solve for the state by using that as a feedstock. And in addition to the proximity to that feedstock, the reservoirs and the greenfields are in proximity to the demand centers to the west, such as the Bay Area for the products that get created out of that. So again, location, location, location. It’s very important where these reservoirs are. We’re a first mover in that core space and that region and we feel advantaged towards these waste product streams.

Great. Thanks a lot.

And ladies and gentlemen, that’s all the time we have for questions today. I’d like to turn the conference back over to the management team for any closing remarks.

Thank you for joining us today. We will be presenting at several investor conferences in November and December and also in early 2024. We look forward to seeing everybody soon. Thanks again.

Thank you. Ladies and gentlemen, this concludes today’s conference call. We thank you all for attending today's presentation. You may now disconnect your lines, and have a wonderful day.