California Resources - Q3 2023

Transcript

Operator (participant)

Good day, and welcome to the California Resources Corporation Q3 Earnings Conference Call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press Star then one on your telephone keypad. To withdraw your question, please press Star then two. 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.

Joanna Park (VP of Investor Relations and Treasurer)

Welcome to California Resources Corporation's Q3 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 Q3 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.

Francisco Leon (President and CEO)

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're 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 Q3, we continued to deliver strong results, producing 85,000 barrels of oil equivalent per day and generating $71 million for free cash flow.

We remain on track with our 5%-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 shows CTV I on track to receive the first draft Class VI 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 to 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-$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 plant 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, help make greenfield projects competitive with great products that are transported to California from thousands of miles away. Furthermore, CRC and CTV get 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 de-risk the new energy projects and enable commercial scale CCS quicker than many others in this 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 on-tap 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. 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?

Nelly Molina (EVP and CFO)

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 increasing oil prices during the quarter, managed 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 PSC effects.

We have actioned 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 Q3 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 $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 our Kern County EIR.

The first is by utilizing updated field-level EIRs. The second is by pursuing natural gas projects within the Sacramento Basin, and finally, through developing a more vast 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 a schedule of 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 Q1 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.

Francisco Leon (President and CEO)

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're 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?

Operator (participant)

Thank you. If you would like to ask a question, please press star then one on your telephone keypad. If you're using a speakerphone, we ask that you please pick up your handset before pressing the keys. To withdraw your question, please press star then two. Today's first question comes from Kalei Akamine with Bank of America. Please go ahead.

Kalei Akamine (VP of Equity Research Oil and Gas)

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 revision in the quarter. Presumably, your permitting constraints were already anticipated, but the market seems to be interpreting that maybe there's a new message back 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.

Francisco Leon (President and CEO)

Hey, Kale. Yeah, so in the CapEx, there's just, there were some delays in Q3 facility spend, that we, we expect to finish here before the end of the year. So it's really nothing more than timing on, on some of the facilities projects that we laid out. So I wouldn't read too much into that. And in 2024, we've, we've laid out some of the big catalysts that we see. We have, that we're still not ready to, to put out guidance, for 2024, but, there's, there's some important aspects, to, to take into account as you, as you model next year. First one is the, the business transformation work, cost reduction efforts, $55 million, annualized run rate savings.

Team did a phenomenal job bringing those in, and we've effectively executed on most of that, and we're not stopping there. We're going to keep looking at new ways of working together and reducing some of that cost structure, which we brought down by about $2 a barrel. We also have a resource adequacy contract around our power plant, where we see an incremental $45 million of capacity associated with that plant. As a reminder, that plant makes on resource adequacy about $50 million per year in 2023. So this is almost a doubling of that payment to be on standby for the grid. So we have some really exciting catalysts coming up next year.

We also have a maintenance of the plant, which we want to make sure it's running in tip-top shape. So, we disclose that as well. So, we still don't have any new information around permits. We still have a view that first half of the year, next year, you should assume a 1 rig program. In the second half of the year is where we expect to go back to three or four rigs, a little bit more normalized run rate in terms of drilling activity.

Kalei Akamine (VP of Equity Research Oil and Gas)

... 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 stack, 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?

Francisco Leon (President and CEO)

Yeah, Kalei, I think you got it right on the framing. Just to underscore the California market dynamics, California needs more natural gas today. We import, as a state, over 92% of the gas consumed. We're the fifth largest economy, a lot of industrial and commercial needs for the gas, beyond residential, and the gas is brought from other states. It's not under long-term contracts. So the reason it comes to the West Coast is to find better pricing, and that better pricing might now will be competing with LNG export facilities built in other parts of the U.S. So there's a big problem that California has, and introduces big risks to baseload power.

And our commitment, in a number of ways, is to find solutions on, from an energy perspective to the state. We have a lot of gas. We haven't highlighted in the past, in the past couple of years, our gas resource, but we went out earlier this year, started looking at, okay, can we high grade a number of locations that are within existing fields, that are near facilities, near customers? And that's the— today, we're announcing the results of that effort. Also by making, pursuing RSG designation, we really want to highlight and contrast the gas that we're importing. Not all gas is the same. Gas comes from other basins that is fracked, and there's more fugitive emissions in other states.

You want it to be California produced, and we want it to be CRC produced. So we're excited about the prospects of being there in the very, very near term. We're not ready to talk about economics, but as we've laid out, structurally, there's a structural premium to natural gas in California, which we expect to persist for years to come. And having that local resource that can contribute to the needs of the state is going to be critical. So our positioning is very strong, and our ability to make good returns for the shareholders is going to be right on par with oil. This doesn't mean that we're not looking to drill more oil wells.

We're convinced that low carbon intensity oil and gas will be here to stay for the long run and multiple decades. The state needs the oil and the gas, and we can provide both. We're bringing forward the gas side of the equation that we really haven't talked about before, but feel really good about the potential of our assets.

Kalei Akamine (VP of Equity Research Oil and Gas)

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?

Francisco Leon (President and CEO)

Yeah, it's too early to put it into numbers, but you know, just to highlight the resource base a little bit more, when we talk about Western San Joaquin, that tends to be wet gas, primarily at Elk Hills in Buena Vista. So fields that already have a lot of that facilities, infrastructure in place, it's about drilling for those wells. A little bit deeper formations, but known to us being very productive for a long time. So as we're focusing on those gas wells, we have the added benefit of generating NGLs from that production. As you move north to Sacramento, that's dry gas. So very limited gas processing requirements, already a lot of infrastructure in place, markets, proven markets out there.

So it's also more about getting the permits and going after drilling. We still need to decide what pace we want to develop this. We're still moving towards putting economics into the projects and that we can disclose, but we feel, again, very, very excited about the positioning. What's changed in California, a state that short gas, but consumes it in big quantities. I think the... What you saw a change is, it started, I mean, we talked about it earlier this year, $47 per Mcf natural gas pricing here in the state, where the rest of the country was around 4. So more than a 10X-...

Premium in a state that decides to import gas, 92% is imported, you better have a gas storage solution in state. Otherwise, you're going to be very susceptible to market shocks and volatility and aging infrastructure. So I think that was a wake-up call that we need more local production, that we need more storage. The storage fields in California just got expanded in terms of capacity that you can store, that should help moderate, at least, this winter, some of the prices, but we'll see. At the end of the day, the demand is still very strong. And I think, again, it's a realization that being isolated and independent on imports, not having that energy security is a risk and a problem for the state.

Operator (participant)

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

Scott Hanold (Managing Director and U.S. Exploration & Production Analyst)

Yeah. Hey, thanks. When you were in your prepared comments talking about the current county EIR and looking at the second half of 2024 and doing some more drilling, you kind of mentioned obviously, potentially more drilling in the Sacramento Basin for gas sidetracks, and then obviously exploring the field level EIRs. You know, 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?

Francisco Leon (President and CEO)

You do need permits for sidetracks, 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 a hearing more than likely in the Q1 first half of next year. So that's still moving forward. We don't have any new updates other than, you know, the briefs have been completed, and the decision is likely early next year. But we see multiple paths to getting back to drilling wells.

And in sidetracks, it's an exciting opportunity, different permitting process, but ultimately, in line with the expectation to satisfy all the requirements from 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 growing more and more comfortable that there will be a solution in the second half of next year.

Scott Hanold (Managing Director and U.S. Exploration & Production Analyst)

Okay. Okay, then just to clarify again, you are actively getting permits for in the Sacramento Basin for gas wells. You are getting... You are pursuing permits in the sidetracks and field-level EIRs. So you are all doing that at this point in parallel with, you know, hoping the current county EIR comes through right now. Is that a fair statement, or is that something that you still work for?

Francisco Leon (President and CEO)

No, no, we're pursuing all fronts. We still haven't received a new permit this year, to be very clear. But we are pursuing all the fronts that we laid out as solutions towards getting back on track. So all of the above, current county EIR, field level EIR, sidetracks, or drilling outside of current county, the team is working on all of them. And yeah, we look forward to getting back, you know, on the phone in the February of next year with our plans for 2024.

Scott Hanold (Managing Director and U.S. Exploration & Production Analyst)

Got it. And then, maybe a little bit on the CMB business. You talked about the Elk Hills gas plant, and you know, obviously, it'd be, I guess, the first brownfield one 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 and LCFS eligible, and are you sharing that credit with the JV? So, you know, is there some benefit to, like, CRC by itself, you know, through this process as well?

Francisco Leon (President and CEO)

There is. We, the way to think about this project is CRC is investing into the capture equipment. It's a little bit different from what we ultimately will do on bigger scale because we, this is a pre-combustion capture system. Low capital requirements with a piece of equipment, with the CGP I cryogenic plant, already functioning and operating. This is an add-on to that facility, low capital pre-combustion, and that's a CRC expense. Yes, you, we will look for 45Q, we'll look for sale CFS, we'll look for all the incentives that are available to CCS. On top of that, the plant, there's benefits to CRC on the plant itself.

We expect a higher yield of NGL, specifically propane, a little bit more production as well. You should—I mean, we are reducing the emissions, not entirely, but we are reducing the emissions of the plant system, so should expect a carbon tax reduction. So there will be—there are economics specific to CRC beyond CCS, right? So, so the way to think about it is the capture system is what earns the 45Q. We pay a fee, storage fee to the JV, inconsistent to what we are asking others to pay, but there are multiple benefits for CRC as well that accrues to the CRC shareholder. So it's a very nice project, nice, nice win.

I wish we had the ability to control all aspects of projects in terms of CCS. That's not the case, but this one is a great proof point, a great way to showcase and that things are working. And very importantly, this is the way to get CCS, CO2 on the ground by 2025. Should be the fastest in the state and ultimately earn the 45Q credits and solve a lot of the questions out there in terms of feasibility of CCS. So having more control points is very helpful to get to that answer.

Leo Mariani (Managing Director and Senior Energy Analyst)

Thank you.

Operator (participant)

Thank you. Our next question comes from Leo Mariani with Roth MKM. Please go ahead.

Leo Mariani (Managing Director and Senior Energy Analyst)

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's been cutting you a check so far in 2023, you know, for that amount, and that amount sort of doubles next year? Does this flow through your sort of electricity, you know, 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 there would be great.

Francisco Leon (President and CEO)

Yeah, Leo, great, great question. So you know, as you know, the state of California has a big, big penetration of renewable energy, and that doesn't work 24/7. So you require base load from different sources to make sure the lights are on in the state. 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 resource adequacy and what it means.

Jay Bys (EVP and CCO)

Yeah, thanks. Just to be really clear, the state's not actually paying for the capacity. Anybody serving load in the state, in CAISO in particular, is required to have capacity to back that load. So whether that's a utility or an aggregator, they have to secure the capacity necessary to back up the load which they're serving. So they are, in fact, the party paying CRC to make this capacity available. Historically, there had been maybe more lax treatment in how much and to the extent by which certain parties would back up their supply using this marketplace, but CAISO has become very resolute that they want, they do want, people to be backing up their loads. So you're seeing a price that's reflective of the true market value of this capacity today.

The fact that we have an asset that's readily available at all times is certainly attractive to the marketplace.

Francisco Leon (President and CEO)

And, Leo, just to add one more to clarify. So we have 550 megawatts at Elk Hills. We use about a third of that power for our own consumption in the oil field, and two-thirds is available to sell to CAISO and to utilities. So this is a way to guarantee that supply through 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 struggling to keep up otherwise.

Leo Mariani (Managing Director and Senior Energy Analyst)

Okay, well, 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, you know, such as power pricing, input costs, et cetera, are you getting an extra $45 million next year in the business?

Francisco Leon (President and CEO)

Correct. That's, that's exactly what—and typically that comes in the Q3. That's what we got just now, the payment for 2023. These are contracted capacity that, that the team's already executed on. So it's an incremental $45 million of, of cash. Correct.

Leo Mariani (Managing Director and Senior Energy Analyst)

Okay, great. Thank you for the clarification. And then just on the $55 million of cost savings, which you're expecting, you know, 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 here?

Francisco Leon (President and CEO)

Yeah, from a modeling perspective, I would apply it in 2024, Leo. We are seeing already some of those savings this quarter, but there's offsets, right? There's severance costs, there's a number of things that you have to as you go through big cost reductions that you have to take care of. So you will see the full impact of the $55 million plus for 2024.

Leo Mariani (Managing Director and Senior Energy Analyst)

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

Francisco Leon (President and CEO)

Yeah, so we're looking for a cleanup language around Senate Bill 905, which is the beginning of the conversation around pipelines in California. We are, you know, there's no new update. We're anticipating beginning of next year when the budget gets set by the state to have the next opportunity for the legislature to pass the language that ultimately creates the framework for CO2 regulation. So look for that early next year in terms of new information. But, you know, our view is that the energy transition cannot wait, and that's why we're excited about our greenfield projects, excited about the project that our capture to storage project at Elk Hills.

We have the ability to make all of this a reality as we wait for things like the CO2 pipeline regulation to get passed. So, you know, this co-location of emissions on top of the reservoirs really gives us an advantage over the rest of the market in terms of being able to get the cash flows from this growing business. So, but in terms of the pipeline, we feel there's really good support from the administration, from the legislators. So again, hoping beginning of next year is when we get some progress made in that front.

Operator (participant)

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

Nate Pendleton (Energy Analyst)

Good morning. Thanks for taking my questions.

Francisco Leon (President and CEO)

Morning.

Nate Pendleton (Energy Analyst)

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?

Francisco Leon (President and CEO)

Hey, Nate. Yeah, so, I mean, as we have in a strategy to build multiple areas around the state for the pore space and the CCS business. In Elk Hills, we happen to have all aspects of the business in one place: surface, minerals, emissions. But as we move to other parts of the state, we do have to acquire land to make sure we have the right size of the plume and that we've accounted for all the different elements to it. So the $20 million that you're seeing of easements anticipated in the Q4 of this year is to expand some of our land holdings.

As we get ready to submit permits, as we get ready to make the business a reality in other parts of the state, we're buying land that we can develop over time. So that's what that is. It's difficult to predict the intensity of that spend going forward. But what you can see, if you go through our slide deck, you can see a lot more specific details as to what we've been doing at CTV II and CTV III. So where we don't, you know, where we're building new sites, we're submitting permits. We have a long queue.

The easements is for the next wave of projects that are in the CTV IV, V, VI category, where we're looking to perfect those reservoirs and building the strongest position that we can in a market that is competitive. So, we have seen where there is, I would say, competition out there for the land rights. We don't necessarily see immediately this competition submitting permits, but we know they're out there, so some big developers that are looking to build their own CCS platform. So that's, you know, without being specific as to who's out there, there is demand for land, there is demand for Pore Space.

You just don't hear it because the companies are not necessarily public or they are too big for, for this to register. But we, we do see demand, but we feel really good about our positioning that we're building and, and building scale and multiple, multiple projects, so we can grow the business beyond what we laid out for the market.

Nate Pendleton (Energy Analyst)

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

Francisco Leon (President and CEO)

Yeah, absolutely. So commercially, I think, our team made a great decision to retain an option to participate. That gives us access into new markets and how those markets are coming together. As we develop the clean energy park at Elk Hills, as we bring in new technology forward and enable these projects, understanding the value of their proposition and their offtake agreements is critical to the success of our CCS franchise. So certainly there are some projects that are going to be better fit. There's going to be projects that are more mature, and there's going to be an appetite to invest in some of these projects. We have the option alongside with Brookfield, so we go in together.

We understand the scalability of the markets, the pricing points, the positioning that we have. So if we feel there's a strong return opportunity, then, you know, it's something you'll see us invest in. And if we think they're going to take a little bit longer to develop, then we may not. So it's good to have the option. I think we're going to face the first decision here early next year in Lone Cypress. We feel it's a very attractive project to develop the first clean hydrogen offering at scale in the state. Again, a fast-track to market, a low-cost producer, potentially, given all the advantages that we talked about it being at the Clean Energy Park. So we're approaching that FID decision.

First, we have to get the Class VI permit, and then we'll make a decision on the project. So, we're looking at it. It's very difficult to be prescriptive because the projects are so different, and their funding requirements are different. The capital behind them is different. But I do like having the ability to think through the market of every project and how that's going to play in California.

Nate Pendleton (Energy Analyst)

Absolutely. Thanks for taking my questions.

Operator (participant)

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

Scott Gruber (Managing Director and Senior Analyst of U.S. E&P and Oilfield Services & Equipment)

Yes, just staying on the capture project at the Elk Hills gas plant. You know, does the economic range there, 50-70 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.

Francisco Leon (President and CEO)

Thanks, Scott. Yeah, so the 50-75 is the range of what we see in California as being the value for pore space for storage-only projects. So whether it's our emissions or third-party emissions, that's the rate to pay for pore space, and that's what this is signalling. There may be a passthrough of credits, there may be cash. Those are negotiations that are happening between the emitters and the JV. So it could be a combination of the two. I think the way to think about this project is you get 45Q, which is, by the way, an after-tax number. So you gross up that for before tax, and it's over $100 per ton.

Then we're going to look to apply for LCFS pathway, because this is a project that ultimately feeds a power plant that goes to providing power for the oil field, and you're bringing lower carbon molecules and electrons, in this case, into the mix. We feel it qualifies for LCFS, so we're starting that project. We also pay in California carbon tax for any form of emissions throughout the state. Any industrial group has to pay those carbon taxes. So we see this as being an offset by reducing the emissions and less greenhouse gas cost to CRC. And as I talked about before, there's propane and an incremental yield. So, the economics for—we have to look at the economics two ways, right?

The economics for the JV are, as we discussed, is $50-$75 per ton, give you an unlevered return of between 10%-30%, big range, but that's what we can disclose right now. So this project will be consistent on that basis. But on top of that, there's a CRC economics, which brings in twofold our participation in the JV, but also the added increases and benefits that we see beyond 45Q. Could be credits, but definitely more propane. It's a good thing and an avoidance of carbon tax. So, good returns all around, anticipated. It also it's a light capital per ton project, so capital for this system is on the lower end, so we see very strong returns across the board.

Scott Gruber (Managing Director and Senior Analyst of U.S. E&P and Oilfield Services & Equipment)

I appreciate all that color. And then turning to your asset sales, it looks like the PNA 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, you know, the cost associated with that? And then, you know, just ultimately, what's the cost to, you know, clean up the property, you know, PNA, all the wells on the property, rezone, and get it ready for sale? Do you have a better sense for the costs associated with that?

Francisco Leon (President and CEO)

Yeah, thanks for the question. So we're making really good progress on the 1-acre property. So as a reminder, we have the large field, Huntington Beach, which is 90 acres. That's going to be. That's going to take more time to abandon and monetize, but we are focused on a another field that's about 5 blocks away, which is 1 acre. We refer to it as Fort Apache. We're making really good progress there. We've abandoned, we completed abandonment of the wells that were producing in there. So that's done. We're in the process of completing all the surface abandonment.

We're working with the city and regulators to get that site ready to be sold, and we're looking to call for offers here in the Q4. So what we want to do, to answer your question more specifically, is once we have a $1 per acre value established by the market, that's when we would like to talk about cost as well, right? So to give a read-through of what a one-acre abandonment to sale looks like in this part of the world, right? So we want to give an all-in kind of answer to the process that ultimately can be applied to the 90-acre property as well, alongside with some timeline to the bigger property.

The focus right now is on the one acre, and feel we're making good progress, so more to come.

Scott Gruber (Managing Director and Senior Analyst of U.S. E&P and Oilfield Services & Equipment)

Got it. We'll await those details. Thank you.

Operator (participant)

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

Noel Parks (Managing Director of CleanTech and Exploration & Production)

Hi, good morning.

Francisco Leon (President and CEO)

Morning.

Noel Parks (Managing Director of CleanTech and Exploration & Production)

Just a couple of things. In your discussion about the capture and storage project and the pre-combustion capture system, you talked a little bit about it. I'm not really familiar with those systems. But curious about who or if you can characterize what sort of equipment vendor you'd be using for that. Is that highly proprietary technology, something that or something that's widely available?

Francisco Leon (President and CEO)

Yes, it's yes, available. It's amine technology. Let me turn it over to Omar to provide more details, but we, we will be doing the work. CRC will be doing the work. But go ahead, Omar.

Omar Hayat (EVP of Operations)

Yeah, just a little bit more, just a little bit more color on the technology. It's not, it's not a new technology. It's an amine plant that was put in place with a 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 the proof in place. Yeah.

Francisco Leon (President and CEO)

So a proven technology within our control, within our field. And that's what gets us really excited, because at the end of the day, we have nationally a lot of things to prove in terms of the viability of CCS. And there's a lot of moving parts, from interstate pipelines in other places to some concerns about injecting of CO2. But, you know, what we created at Elk Hills is this opportunity to have it all in one place, take a lot of the variables away, and including here the emission capture, which ultimately we know it's going to work. We know what the capital cost is going to be. And this gets us into a fast track to be injecting by 2025. So, really excited about it.

Noel Parks (Managing Director of CleanTech and Exploration & Production)

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

Francisco Leon (President and CEO)

I don't know if we're bound on some confidentiality to talk about it, but it would be one of the... There's two big national companies that most companies use. It would be one of them.

Noel Parks (Managing Director of CleanTech and Exploration & Production)

Okay. Okay, great. And just sort of a general question. It's clear, as you describe the different projects you've already disclosed and 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 the, you know, 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.

Francisco Leon (President and CEO)

Yeah, 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. 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.

Chris Gould (EVP and CSO)

Yeah, just to build on upon 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 2 through 5. 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.

In addition to the proximity to that feedstock, the reservoirs in 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 in that region, and we feel advantaged towards these waste product streams.

Noel Parks (Managing Director of CleanTech and Exploration & Production)

Great. Thanks a lot.

Operator (participant)

Thank you. 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.

Francisco Leon (President and CEO)

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.

Operator (participant)

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. Goodbye.