Good day, and welcome to the California Resources Corporation Third Quarter Earnings Conference Call. [Operator Instructions] 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.…

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 $1.1 billion share repurchase program in place with $497 million of capacity remaining through June 2024. In addition…

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?

[Operator Instructions] Today’s first question comes from Kalei Akamine with Bank of America. Please go ahead.

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. So the CapEx, there’s just -- there were some delays in third quarter facility spend that we expect to finish here before the end of the year. So it’s really nothing more than timing on some of the facilities projects that we laid out. So I wouldn’t read too much into that. And in 2024, we’ve laid out some of the big catalysts that we see. We have -- we’re still not ready to put out guidance for 2024, but there’s some important aspects to take into account as you model next year. First one is the business transformation work, cost reduction efforts, $55 million annualized run rate savings. The team did a phenomenal job bringing those in. And we 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, we -- that plan makes on research 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 disclosed 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 one rig program in the second half of the year is what we expect that to go back to three or four rigs, a little bit more normalized run rate in terms of 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, 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 we’ll 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 from an energy perspective to the state. And we have a lot of gas. We haven’t highlighted 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 RSE 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, the 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 in multiple decades. The state needs the oil and the gas and we can provide both. We’re just providing the -- we’re bringing forward the gas side of the equation that we really haven’t talked about before, but I feel really good 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 put it into numbers. But 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 and Buena Vista. So fields that already have a lot of the 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 it’s refocusing 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 excited about the positioning. What’s changed in California, a state of short gas, but consumes it in big quantities, I think the -- what you saw change is started -- I mean, we talked about it earlier this year, $47 per Mcf of natural gas pricing here in the state whereas 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 wakeup 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 dependent on imports, not having that energy security is a risk and a problem for the state.

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. And then just to clarify again, you are actively getting permits in the Sacramento Basin for gas wells, you are getting -- you’re pursuing permits in the sidetracks and [indiscernible] yards. So you’re all doing that at this point in parallel with hoping that Kern County EIR comes through right now. Is that a fair statement? Or is that something that you’re still working towards?

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, Kern County EIR, field level EIR, sidetracks or drilling outside of Kern County, all are -- the team is working on all of them. And yes, we look forward to getting back on the phone in the February next year with our plans for 2024.

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?

There is. So we -- the way to think about this project, the CRC is investing into the capture equipment. It’s a little bit different from what ultimately we’ll do on bigger scale because this is a pre-combustion capture system. So low capital requirements with a piece of equipment with the CGP1 cryogenic plant already functioning and operating. So this is an add-on to that facility, low capital pre-combustion and that’s a CRC expense. So yes, we will look for 45Q. We’ll look for LCFS. We’ll look for all the incentives that are available to CCS. But 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 the carbon tax reduction. So there will be -- there are economics specific to CRC, beyond CCS, right? 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, consistent to what we are asking others to pay, but there are multiple benefits for CRC as well that accrues to the CRC shareholders. So it’s a very nice project, 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 that things are working. And very importantly, this is the way to get CCCI on the ground by 2025, should be the fastest in the state and ultimately earn the 45 good credit 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.

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, thanks. Just to be really clear, the state is not actually paying for 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, partly paying CRC to make this capacity available. Historically, there had been maybe more lax treatment and 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 load. So you’re seeing a price that’s reflective of the true market value of this capacity today. And the fact that we have an asset that’s readily available at all times is certainly attractive to 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 third 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 -- and typically, that comes in the third quarter. That’s what we got just now the payment for 2023. These are contracted capacity that the team has already executed on. So it’s an incremental $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, Leo. We are seeing already some modal 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.

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?

Yes. So we’re looking for clean-up language around Senate Bill 905, which is the beginning of the conversation around pipelines in California. We are -- 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’ll ultimately increase the framework for CO2 regulation. So we’ll look for that early next year in terms of new information. But 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 are captured 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 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. 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.

Thank you. And our next question today 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?

Nate, yes. So we have a strategy to build multiple areas around the state for the pore space in 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 boom 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 fourth quarter of this year is to expand some of our landholdings. As we get ready to submit permits, as we get ready to make the business reality in other parts of the state, we were 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 -- we’re building new sites, we’re submitting permits. We have a long queue. The easement 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. Some big developers that are looking to build their own CCS platform. So that’s -- 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 this to register, but we do see demand. But we feel really good about our positioning that we’re building and building scale and multiple projects so we can grow the business beyond what we laid out for the market.

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. 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 the -- 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 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. I 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 as being between 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.

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?

Scott, yes, so the $50 million to $75 million 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 signaling. There may be a pass-through of credits. There may be cash. Those are negotiations that are happening with 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’re also paying 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, this $50 to $75 per ton give you an unlevered return of between 10% to 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 credit, but definitely more propane. It’s a good thing in avoidance of carbon tax. So good returns all around anticipated. It also is 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.

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. So we’re making really good progress on the one acre property. So as a reminder, we have the large field Huntington Beach, which is 90 acres. That’s going to be -- it’s going to take more time to abandon and monetize. But we are focused on another field that’s about five blocks away, which is one acre. We referred to it as Fort Apache. We’re making really good progress there. We’ve abandoned -- we completed abandonment of the wells that we’re 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 fourth quarter. So what we wanted to do, to answer your question more specifically, is once we have a dollar per ag for value established by the market, that’s when we would like to talk about cost as well, right? So to give a read through, 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 time line to the bigger property. But the focus right now is on the one acre, and I feel we’re making good progress. So more to come.

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.

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

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 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 I’m really excited about it.

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 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 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.