California Resources Corp (CRC) 2023 Q4 法說會逐字稿

Good day and welcome to the California Resources Corporation fourth-quarter and year end 2023 conference call (Operator Instructions) Please note this event is being recorded. I would now like to turn the conference over to Joanna Park, Vice President of Investor Relations and Treasurer. Please go ahead.

Welcome to California Resources Corporation fourth-quarter and year end 2023 conference call. Prepared comments today will come from our CEO, Francisco Leon and our CFO, Nelly Molina. Following our prepared remarks, we will all be available to take your questions. Please limit your questions to one primary and one follow-up.

Our remarks today include forward looking statements based on current expectations. Actual results may differ materially due to factors described in our earnings release and in our SEC filings. We undertake no obligation to update these statements as a result of new information or future events.

We will also discuss our pending merger with Aera. We encourage you to read our merger proxy statement when available because they will contain important information. Copies of this and other relevant documents will be available free of charge on our website and on the SEC's website.

Additional information about the individuals participating in our proxy solicitation, such as our directors and officers and their interest will be provided in our merger proxy statement. We've also provided information reconciling non-GAAP financial measures discussed today to the most directly comparable GAAP financial measures on our website as well as in our earnings release. I will now turn the call over to Francisco.

Thank you, Joanna. Welcome, everyone, and thanks for joining us. I realize we just held a call about two weeks ago when we announced our exciting agreement to merge with our energy. So we will keep our comments relatively brief, but we do have some important information to share with you. We will cover three topics today. First, we will summarize our 2023 results on ours and how our strategy created significant value to shareholders.

We took decisive steps to strengthen our asset base, lower our cost, and grow our carbon management business. These steps position us to continue to build value in 2024 and beyond. Second, we will cover an update on our CCS business, real estate portfolio and merger with Aera. Lastly, we will summarize our 2024 outlook and steps we will take to deliver another year of strong results.

Let's talk about 2023. We accomplished a lot over the last year, our E&P operations had a strong year with a low base decline, which we achieved by deploying less capital than we had forecasted. Our team continued to find new and innovative ways to reduce cost and enhance margins. We accomplished these things with a continued focus on safety.

In 2023, the team achieved the company's lowest total recordable incident rate excluding the period during COVID, our carbon management business continued to build for the future as we reached first mover milestones such as the EPA's release of the state's first craft Class VI permits for CCS that will accelerate the decarbonization of California.

In addition, the California Direct Air Capture Hub in partnership with leading DAC technology companies such as ClIMEWorks and Avnos, was selected for DOE funding. We continue to prove that CRC is a different kind of energy company. We have a quality asset base with oil and gas fields that have low declines, which coupled with strong realizations allow us to generate meaningful free cash flow.

This is a powerful combination allowing us to maintain annual production levels using about half of our discretionary cash flow this means the other half can be used to maintain our strong balance sheet and also return cash to investors. Over the last three years, we have generated $1.25 billion of after-tax cash flows, of which we returned over $750 million to shareholders while also building a strong cash position.

Our merger with Aera once completed will further strengthen these cash generation capabilities and differentiate the CRC value proposition from peers. During 2023, we launched an initiative to reduce costs and streamline operations across the business. We achieved about $65 million in sustainable annual run rate cost savings.

And as we look ahead, we will remain focused on managing our existing cost structure and continuous improvement of our operations. CRC has proven its ability to successfully operate in California to help the state accomplish its goals. There is no better example, then our anticipated combination with Aera. Our transaction will create a stronger enterprise to scale, complementary fit and the potential for $150 million of annual synergies with upside, which we will deliver within 15 months post close.

The merger with Aera will reduce the company's breakevens and put us on stronger footing to compete against out-of-state and out of country suppliers, which is good for California's local energy supply and very importantly, the environment. With Aera, we more than double our premium pore space, and we'll be better positioned to decarbonize hard-to-abate sectors for the economy as well as to capture our own emissions.

Our increased pore space capacity will make us the partner of choice. We are confident we will sign additional projects from both brownfield and greenfield to rapidly expand our carbon management business in the San Joaquin Basin as well as in other parts of the state.

In 2023, we submitted EPA Class VI permit applications for two new reservoirs, CTV 4 and CTV 5, adding an incremental 51 million metric tons of CO2 storage capacity. The storage reservoirs are strategically located in Northern California in proximity to major emission sources. Throughout 2023, we advanced five greenfield and one brownfield projects that added 860,000 metric tons per year of CCS.

Four of these projects were our proposed CTV Clean Energy Park at Elk Hills and two were in Northern California. This week, the EPA and Kern County will hold a final hearing for our 26R draft permits. Over the past two years the team has been carefully preparing for this event, and we're excited about the economic, social and environmental benefits it could bring to California.

Once we receive the final permit for the 26R reservoir, we plan to make a final investment decision on our previously announced pre-combustion capture project at our Elk Hills cryogenic gas processing plant with the expected annual injection of 100,000 metric tons of CO2.

This will be CRC's first CCS project and will enable a normal 7% reduction in carbon emissions intensity from the Elk Hills power plant and pave the way for the first injection of CO2. By the end of 2025. Receipt of Class VI permits were 26R we'll also advance our Elk Hills Hydrogen Project.

This project will provide nearly 65 tons per day of clean hydrogen and CRC will sequester over 200,000 metric tons of CO2 per year at CTV 1. CRC and Brookfield will continue to evaluate a potential equity investment in this project. We look to FID this project in the second half of 2024. We have other CCS accretive deals in the works and look forward to sharing further updates later this year.

Before I hand it over to Nelly to cover financial results. Let me give you an update on our real estate portfolio. I am happy to announce that we have entered into an agreement to sell a 0.9 acre parcel known as Fort Apache for about $10 million to a local real estate developer.

Recently, we finished plug and abandonment operations on six wells and remove some surface infrastructure, which cost us about $2 million. This transaction provides a good indication of the potential value of the Huntington Beach field.

As many of you know, we have about 90 acres located along a one mile track from Pacific Coast Highway at Huntington Beach. There, we operate a mature oil field that produce about 3,000 barrels per day. We plan to permanently plug and abandon about 48 of the 350 or so idle inactive wells during 2024. As we remediate the property, we will continue to advance rezoning, re entitlements and other due diligence to prepare this unique asset for sale down the road.

There are additional details in today's deck. And now I'll hand it over to Nelly to cover financial results. Nelly?

Thanks, Francisco. Our 2023 financial results exceeded expectations with higher than expected free cash flow, a solid balance sheet with ample liquidity and a near zero leverage ratio at year end. We have carefully balance our cash flow priorities using capital discipline to maintain a strong balance sheet and sustainable cash returns to shareholders.

In 2023 our reservoirs performed exceptionally well with entry to exit gross total production decline approximately 6%, in line with our initial expectations. This was made possible with lower than initially expected capital of $185 million, demonstrating an improved capital efficiency of our operations. The average net production for the year was 86,000 BOE's per day with oil comprising 60% of volumes.

For the year, we delivered $653 million in cash flow from operations and $448 million of free cash flow call. These strong financial results allowed us to reduce debt by $55 million in second half of the year. We implemented $65 million in 2023 through our business transformation initiative, which will be reflected in our 2024 results. We will continue to prioritize cash returns to shareholders and the combination with Aera enhances visibility.

In 2023, we returned nearly half of our free cash to shareholders. Over the last three years, a total of $813 million or 65% of total free cash flow generated was returned through buybacks, dividends and repurchase debt. We recently increased the authorization under our share buyback program by nearly 25% to $1.35 billion and extended its term through the end of 2025.

Upon closing of the Aera merger, we intend to raise our dividend once again. Now let me quickly summarize our fourth quarter results, which were in line or better than the preliminary results we released in early January. We generated $65 million in free cash flow and adjusted net income of $67 million or $0.93 per diluted share.

Our strong quarterly results were driven by lower operating costs and higher net margin from power sales. For quarter production averaged 83,000 BOE's per day and oil averaged 50,000 barrels per day. Non energy costs were below expectations, reflecting a partial effect of the savings we actioned last year as part of our business transformation initiative efforts to improve margin.

We also completed a $35 million sale of non-operated interest, a Round Mountain, which had an associated production of about 900 barrels per day. We ended the year with nearly $1 billion in liquidity and about $500 million in cash. We are very pleased with the exceptional 2023 results, the strong foundation of our balance sheet and the trajectory of the business as we look into 2024, expanding our portfolio and accelerating value. Next, Francisco will talk of our outlook for next year.

Thanks, Nelly. Before opening the call to take your questions, I want to quickly discuss our 2024 outlook. For 2024 we have again prioritized free cash generation and expect total capital investments of $320 million in the midpoint of our guidance range or about half of our expected cash flow from operations. In 2024 at $80 Brent and $3.25 and NYMEX and using our current capital plan, the business is expected to generate approximately $280 million in free cash flow.

This will support returns to shareholders through our dividends and our opportunistic share buyback program. In addition, we will continue to reduce debt and maintain our strong balance sheet. With the cost savings achieved today, non-energy operating costs are expected to be nearly 6% lower year-over-year. We expect full year production to average around 80,000 BOEs per day, with about 60% oil.

This plan assumes a four drilling rig program starting in the second half of 2024 and anticipates a successful resolution of the Kern County EIR litigation and resumption of a normalized level of permit approvals that support a multiyear program. In case Kern County EIR litigation takes longer than expected, and CRC is not able to receive drilling permits.

We plan to run a one-rig program with us $200 million to $240 million total capital program and an expectation of a 5% to 7% decline. Similar to our '23 program. To be clear, we will only increase activity to four rigs if permitting process improvements supports a multi-year drilling program. In the near term, we are laser-focused on getting the Aera merger closed.

We expect that the transaction will close in the second half of the year. We have provided some detailed information in our deck for standalone CRC for the first quarter and full year. CRC is incredibly well positioned today and our anticipated combination with Aera will make us financially stronger and more resilient.

Our conventional energy business has important skill today and our people are finding innovative ways to safely enhance margins and supply California with local and lower carbon energy. We're excited about the growth prospects we see on the horizon through our carbon management business and our leadership role in accelerating the decarbonization of California.

Thanks for your time today and your investment in CRC. Operator, please open the lines for questions.

We will now begin the question and answer session. (Operator Instructions)

Scott Hanold, RBC Capital Markets.

I think some are just out of curiosity. Are you all receiving permits? I know you're running a dual path, but are you receiving oil and gas permits under the original process? And if you are, I mean, are you actually receiving them? And if the litigation does not go on in favor of Kern County, what does that make 2025 look like? Would you be able to start ramping up rigs as you accumulate and permits under the old process?

Hey, Scott. So we are not receiving permits for new wells. What we're doing though, is getting permits for capital workovers. So if you look at the way that CRC has performed now for multiple years, very low-decline corporate decline through the business, adding first OpEx, workovers and then capital workovers brings are all in decline somewhere in the high single digits.

then to get to a stay flat scenario, we drill new wells. So right now, we're sitting with a permit on hand for a full-year program and no incremental permits have come through. But we feel that we can deliver a very similar program that we did last year in '23 and that you saw in the results today.

What we said is with one-rig program, we can get to a 5% to 7% base decline after investments. We did that in '23. And we also said is repeatable. So we'll do that in 2024 if Kern County EIR not reinstated. And we expect that to continue into 2025. So we have enough permits on hand, we have visibility into workovers to be able to have this a repeatable model on the scenario what Kern County doesn't get resolved.

Okay. And just to clarify, you said you don't get out, if the EIR isn't resolved. You have currently permits in hand to run that one-rig program to '25 as well. That what I heard?

Yes, correct. We would have we have multiple years of permits in hand that we can.

Okay, got it. Okay. And then on the cover management side, I guess I'm going to stick to the topics of permits. Obviously, you're in the public comment period. So I appreciate the fact. It's probably limited things you all I can say. But in anything that you would have heard from some of the young comment period that you thought was interesting in a positive way.

And if you have any color on, I guess the time line of getting, you know, hopefully the final approval looks more like a late June-ish type timeframe right now. Any color on why the EPA kind of moved it to that timeframe?

Yes. So we continue with the Class VI permit. They're excited about getting to the public comment period right now, it's public information. It's in the tracker in terms of how the EPA is thinking about it. I wouldn't say there's any delays. We've agreed to do a 90-day public comment period. That's still very much within the time line and we've been moving checking milestones as we go on a way that's, again, consistent with what we see on the EPA tracker.

And we've been preparing we're getting ready for multiple years to get to this point, but maybe I'll turn it over to Chris to give a little bit of a perspective on what we're hearing on the ground and the hearings today with the EPA. So there's a lot of excitement, a lot of preparation that goes into one a day like today.

But maybe, Chris?

Yes, thanks. Hi, Scott. Yes, great question. Very timely because as Francisco mentioned, the hearing is today as well as the final workshop. It's being conducted jointly by EPA Region 9 as well as our Kern county. So looking forward, to the conclusion of that today. As you recall with the completion today, there will have been four of those workshops in the 90-day comment period that Francisco referenced, and that's by comparison to the other classics Wabash in Indiana that had none.

So in fact, we have had the opportunity to really participate and see what the public and the communities have to say about this, and we're encouraged by it . I've been to all of them virtually or in person, including today later. And the comments have been largely supportive, as you can imagine, from a community in Kern County. That's excited about the energy transition.

There is a broad level of support that we have been able to observe in all of those workshops. And therefore, we're really looking forward to tonight. You'll see in that tracker that EPA has always accounted for roughly a three to four months after the hearing which is on schedule for today. That three to four months is the inclusion of those public comments into a final permit, which is why we have set the guidance around the second middle of the year are based on EPA's tracker.

Appreciate the color, guys. Thanks.

Kalei Akamine, Bank of America.

Hey, guys, good morning. It's Kalei Akamine from Bank of America. My first question goes to Huntington Beach where you're pursuing this real estate valuation unlock. So thanks for the additional disclosures, as I think it helps provide a range of valuation. But what I think surprised us is the pace of the remediation. If you simply measured by the rate of plugging the wells, this could easily be a multi-year process.

So hoping that you can comment how you see that timing playing out? That's the first part. And the second part would be how do you see the value of the PDP wedge at Huntington Beach because at some point on this, we phased out?

Hai Kalei, we're very excited about being able to sell this more property for Apache 0.9 acres for $10 million. So it's an $11 million per acre valuation. So obviously we needed to be able to provide that proof point to the market and the larger property rights or the 90 acres in Huntington Beach. The objective is to optimize the valuation and ultimately to get value recognition in our stock price, meaning we would sell today if the right offer comes along, right, there's no, nothing holding us back from capitalizing on that valuation.

Now as we look at not only the continuous development and abandonment of the field, there's a lot of steps that we have to take to get to that optimal valuation. If we sold today, then abandonment, remediation, re-entitlements gets priced into the offer. That's our view. If that's not the case again, we would sell it as soon as we can.

But assuming that there's a number of steps that we're going to be a CRC prepared to handle, which is abandonment of wells and the re-entitlement, then it's going to be a multiyear process, again to find the best value for the land. And so the abandonment we control fully the pace of abandonment should not be an indicator of how long this will take, we can accelerate the abandonment.

But ultimately, what we need to shore through is the ability to re-entitle the property so that we can have real estate development, which is going to be the highest and best use of the property. And we're going to work with the city of Huntington Beach. We need to work with State Lands Commission. We need to talk to the Coastal Commission.

These are processes that take some time ultimately to clear out the more we advance the ball, the higher the offer, it's going to be. So yes, we could sell it today again to maximize the value, which is the objective here. It's better to keep producing the field. We have the benefit of about 3,000 barrels gross from the property that we use the cash to pay for the abandonment.

So it's a self-funding, self-contained abandonment program, and we'll continue doing that until we can get line of sight to a process where we have a land that we can sell without taking a big deduct. And so again, that I wouldn't read anything into the abandonment piece because we can completely control that. It's really more about the negotiations and discussions with city officials and the re-entitlement of the property. So I would think thing this takes a few years to unlock.

So four to five years is what I would say is to get the full process completed. We don't know for sure, but we started and we're pushing forward to trying to maximize the value and bring them that value forward as quickly as we can.

Yesh, I appreciate that. And it makes sense that there is a pathway to maximizing value there and the more work that you put into it, the more valuable the net present value of that transaction becomes to you.

My second question goes to the Aera deal. So our understanding is that there is that retirement liability. Can you talk to us about what that is and what it means in terms of an annual spend rates? And on top of that, can you talk about your ability to push that liability out, whether that's through increased activity or other means?

Yes. So Aera and CRCR have both been very aggressively pursuing abandonment and plugging and abandonment of wells. I think that the spend that they have historically is very consistent with ours. I can't really comment, we haven't put out the rest of the information Aera. We need to get a little bit further along in terms of closing the deal.

But the Europe properties are tend to be shallower, so they may have more wellbores, but they also have much more limited debt to in terms of differences between the asset bases. But I will provide more color as we go forward. We haven't released any of that information and more detail on the assets, but we'll do so as we get the proxy filed as we get closer to the completion of the HSR process.

So it's -- but again, the point to be as we've been abandoning wells on both sides. We have good program, ARO programs in place. We're also looking to deploy technology to reuse wellbores for clean energy for water rights for CCS. So we looked at a wellbore in California as having multiple lives in multiple uses. So excited to have to look at the Aera assets through that lens.

So is it fair to say that on the last comment that if you were to see opportunities to reuse the wellbores, you would be able to moderate the pace of ARO spend?

Yes, we're actively looking at that for our portfolio, Kelei and Aera would be applied the same way. There's opportunities really good, exciting opportunities of bringing produced water to surface that can be treated and used for agriculture.

And you don't want to be drilling separate wellbores for that. If we can reuse an existing wellbore that's going to be a much better option. We're also looking at things like enhanced geothermal technology that uses the heat in the rocks on from steam flooding or for multiple decades to try to bring clean energy to surface.

So we're looking at a lot of places to deploy some money to bring that technology to California. And I think there's some exit multiple uses multiple lives to these wellbores, and we're excited to add to bring that to fruition.

I appreciate the comments. That's my two. I'll leave it there.

Nate Pendleton, Stifel.

Morning, thanks for taking my question. Building on some earlier comments. When reading through some of the supporting documents for the 26R draft permit. It seems to us that there is broad support from the local community at a high level. Can you speak for a moment about the role you see for energy transition projects such as CCS in California and specifically related to California communities that have historically been dependent on oil and gas revenues?

Yes, Nate, I'll tag-team this with Chris, but absolutely. I think the we have a very unique market in California where you have a state government that's pushing in really in favor of an energy transition, but we also have a state that has relied on oil and gas revenues to support the communities to pave the road to pay for libraries and fire stations.

And a lot of that cash flow and the tax revenue that's collected by the counties is really supports a quality of life for the community. So a transition away from oil and gas into some new technology needs to satisfy not only the environmental requirements of the state, but also supplement the income that the counties and everybody receives.

So we're excited to be able to do both extremely well with CRC platform is not being mutually exclusive, but one that can continue to deliver oil and gas, low-carbon oil and gas better than anything that comes from imports, but also advancing the technology and the investments on the clean side. So we see us being the leader, cementing our leadership on both and really trying to drive those solutions that end up in the right in the right place for the state. But maybe I'll ask Chris to see if he has any more comments.

Yes, I'd just add to that, that (technical difficulty) already demonstrate the willingness and ability to execute on the energy transition. The example I would give is the build-out of solar in the county where it's been prolific the largest software installations that provides energy to the state in addition to the oil and gas that's provided now.

So it's really the heart of the energy transition, and it has a track record and moving forward in that regard, carbon capture is just the next opportunity set that they can build on the success that they've already demonstrated with solar and other wind and other forms of energy. And that's why we're confident that it's a great place to do business.

Thanks for the detail and staying on CCS, is there any update you can provide on potential CO2 pipeline regulations for the state that would enable transportation of CO2 site of field boundaries?

Yes. So we're looking Senate Bill 905 cleanup bill. We expected to be in the agenda for the legislature around May or June when the budget is announced, as you're anticipating some progress there. We've been engaging with the legislative group that's pushing this bill forward to make sure we have our views in represented there and we believe there's support from legislators and the administration and the California Air Resources Board. So confidence that it's going to get addressed in 2024.

As a reminder, there is also work happening at the federal level through thePHMSA regulations that could also work in California is not able to get there first. So it's really a question of who can get there. First is it California, is it Feds, but that we're looking to advance CCS through pipeline regulation.

We also are working on a strategy where we're doing a lot of activity within field boundaries and that's one of the greenfield projects that we announced and now brownfield projects with Aera. If you're able to contain the emissions within field boundaries, you can start advancing projects of demonstration that CCS is a technology that we all think is going to be in terms of decarbonizing the state and start test stepping into being a cash flow generator type projects as we look forward the pipeline regulations to come through.

But ultimately the state's going to be successful in reaching its objectives, we're going to need pipelines to be able to move CO2 throughout the state. So looking forward to getting resolution either through a state process on 905 or through the federal regulations.

Appreciate the color and thanks for taking my question.

Leo Mariani, Roth MKM.

I wanted to focus a little bit on the standalone CapEx and production guidance for 2024 for CRC. I just wanted to make sure I kind of understood the numbers here on the midpoint of your production guide, looks like around a 7% annual decline. I guess that's kind of a little above maybe what I had thought given that you guys are running four rigs in the second half of the year.

I know that you've kind of said that probably that number's about right with a one-rig program, but you're doing a little bit more for that guide in the second half of the year? And then just with respect to the capital, I know you guys talked about kind of a low $300 million maintenance capital level.

But your guide this year is kind of $300 million to $340 million of capital and clearly that's maybe a little bit less than maintenance activity in '24, just given that you're only running one rig in the first half, so maybe you could just kind of close the loop on the guide and maybe there's some timing differences here that explain some of this?

Yes, Leo, so remember we announced that we sold a property Round Mountain about 900 barrels at the end of last year. So when you're looking at the decline, if you need to factor that in there, there's an asset sale. We've also had some weather impact here as we started the year.

But, so from the rest of the perspective, the way to look at is we're looking at 2024 under the scenario where we can ramp up to four rigs. We're looking at a stay flat scenario where we can maintain 80,000 BOE's throughout the year with ultimately less capital to get to a level that we have talked about before.

The $300 million to $340 million also includes capital on maintenance of our Elk Hills power plant and some one-time items and so do we see that as a scenario that hadn't we haven't developed now for some time where we have the permits or the incremental rigs, if we were too able to achieve that, then what would happen and that's what we're solving for in that higher scenario.

So you put to $300 million to $340 million of capital and the free cash flow at the prices that we assume it's about $280 million. If we're not able to get the Karen County resolution and we step down to or maintain just a one-rig program for the year.

Then the capital program steps down to $200 million to $240 million. So around roughly $100 million less. And then that accrues to about a free cash flow of about $350 million, right? So those are the rough math numbers. We wanted to provide the bookends as we've already demonstrated on the low end, what our assets and our team are able to deliver with a one-rig program, which is that 5% to 7% decline.

We also wanted to provide the restoring and going back to normal levels of activity. And that's the flat case. So now you have and both bookends to be able to triangulate on your model.

Okay. That's helpful. And then just wanted to follow up on a couple of the other numbers in here. Looks like cash taxes for the fourth quarter came in a little bit above the previously provided guidance range. Wanted to get a sense on that and expectations for first quarter and full year '24 on cash taxes?

And then with respect to share buybacks, looks like those have kind of stepped down the last few quarters was kind of limited in third- quarter and then you didn't have anything in the fourth quarter. So just wanted to get a sense of how we should think about that heading into 2024 and perhaps there are some restrictions on that due to the air deals. So any clarity to kind of provide whether or not buybacks are a pretty important part of that process here this year would be great?

Yes. So on the tax side, we had a gain on the Round Mountain asset, and that's what you're seeing in terms of incremental cash tax in 4Q, there's always going to be timing. We're a full taxpayer and the timing of cash taxes, it's difficult to predict on a quarterly basis. So it could be lumpy but at the end of the day, we would have for a full taxpayer.

We've disclosed that before and I think we also gave you the first quarter cash tax numbers to deploy plug into your model. So what ultimately the increase that you saw in the last quarter is due to the Round Mountain again.

Noel Parks, Tuohy Brothers Investment Research.

Hi, good morning or good afternoon for us. Just a couple of questions. So, in your remarks you mentioned with the Aera acquisition, you're confident that you're going to have more brownfield and greenfield CCS potential projects ahead.

And I'm just wondering if you could talk a little bit about what that would look like with the combined companies. And just wondering, is it a matter of this helping deals get closed more quickly just because you know you have more heft or is it a matter of allowing a larger enterprise or series of companies to do a broader set of deals across more geographies? So does it speed things up, simplify anything?

Yes. So Aera deal is very helpful in multiple ways. We're able to add more pore space in Kern County, which we really like. So to the tune of 54 million tons of incremental pore space in fields that are in our backyard. So as we're thinking through connecting brownfield emitters, too, our different sites, having different entry points and different storage capacity is very helpful.

We're excited about the market. There are some discussions ongoing. If we aggregate all the people we're talking to, it's about 20 million metric tons of emissions per year. So the market potential is and it's large and it's exciting to think though it's about really where we're at is how do you connect it?

So that's where we need the pipes and where do you store it? As we can develop more pore space quickly, I think we're going to be well positioned to be able to receive the CO2 and ultimately bring castles forward or developing more pore space and a lot of the new course basis in the northern part of California.

But anything that we can bolt on to Kern County and bring other projects that will have future potential, whether it's through our own production and reducing increasing the pore space as we deplete our reservoirs or by acquiring some of our Aera's fields that have that potential. It's an exciting proposition that just again brings more certainty into the brownfield market.

Now the greenfield, as I discussed, there's generations of emissions that Aera brings to the table that are going to be easy to capture or within fully within our control. If you think about confidence in bringing those emissions forward, the best case scenario is to have those emissions on top of the reservoir.

So co-location and you want to have full control of those submissions as we showed with our gas processing pre-combustion project, that gives us much more certainty to get to the finish line, the highest percent of it, the incentive. So air allows us to do that through some of the emissions, including and co-gen, so they have in their portfolio.

So we like the Aera deal for multiple reasons and a lot on the traditional oil and gas business in the synergies. But one thing to look for is how our team is going to tackle and is going to think through the year our properties and entitle, bring those accelerate those and bring those to life sooner than probably the current owner was expecting.

Great. And I'm thinking about the Class VI permits and of course that I can't final approval that will be the such a milestone and then the same for subsequent permit approvals. And once that happens sort of post EPA approval, what is the handover like to either further regulatory involvement? Or I wonder, does it change in terms of like a district office steps and another federal entity or DOE or somebody takes the lead?So, what comes next after the program?

So the EPA is the primary agency that approves Class VI permit. It's a federal permit. And but it's working closely with Kern County, where we're going to have the first project out of the gate. And the Kern County is running a parallel path to also get on all of the local permits in place. So maybe I'll turn it to Chris to describe that in more detail.

So first time on EPA, The final permit comes out, but then the process, it ultimately continues with us with the county that the conditional use permit to construct that Francisco was referencing, if you will, receipt of that and then we go FID and then we begin the process to first injection in 2025 as planned. But obviously, as we go with those permits in hand, we'll continue to do things like free injection testing and complying with the conditions in the permit that EPA set forth and as we lead up the first injection.

And then ultimately, that's like immediately what's next right after the permits are in hand. And then ultimately, there's an ongoing process in the Class VI for monitoring, reporting, verification being able to claim that 45Q credits.

Obviously, we'll be doing that in accordance with the permits and at both the EPA level and then county as well in terms of what we're committing to do to continue to advance carbon management more broadly there, but specifically any requirements at the field level, we'll continue to do throughout the life of the project. So it's a near term steps to complete and move on to construction for first injection and ongoing monitoring and verification and things of that nature.

This concludes our question and answer session. I would like to turn the conference back over to Francisco Leon for any closing remarks.

Thanks for joining us today. We'll be presenting at several investor conference in March, and we look forward to seeing you. Thanks a lot.

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