Good day and welcome to the California Resources Corporation Fourth Quarter and Year End 2023 Conference Call. Please note this event is being recorded. I would now like to turn the conference over to Joanna Park, Vice President of Investor Relations and Treasurer. Please go ahead.

Welcome to California Resources Corporation’s 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 interests will be provided in our merger proxy statement. We have 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 Aera 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 and how our strategy created significant value for shareholders. We took decisive steps to strengthen our asset base, lower our costs, 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 the 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 costs 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 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 our 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. 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 than our anticipated combination with Aera. Our transaction will create a stronger enterprise to scale, a 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 doubled our premium for space, and we will be better positioned to decarbonize hard-to-abate sectors for the economy as well as 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 IV and CTV V, adding an incremental 51 million metric tons of CO2 storage capacity. These storage reservoirs are strategically located in Northern California in proximity to major emission sources. Throughout 2023, we advanced five greenfield and one brownfield project that added 860,000 metric tons per year of CCS. All 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 permit. 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 expected annual injection of 100,000 metric tons of CO2. This will be CRC’s first CCS project and will enable an almost 7% reduction in carbon emissions intensity from the Elk Hills power plant, paving the way for the first injection of CO2 by the end of 2025. Receipt of Class VI permits for 26R will 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 I. 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’m 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 removed 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 on Pacific Coast Highway at Huntington Beach. There, we operate a mature oil field that produces about 3,000 barrels per day. We plan to permanently plug and abandon about 48 of the 350 or so idle and active wells during 2024. As we remediate the property, we will continue to advance rezoning, reentitlement, 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.

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 balanced 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 declining 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 BOEs per day, with oil comprising 60% of volumes. For the year, we delivered $653 million in cash flow from operations and $468 million of free cash flow. These strong financial results allowed us to reduce debt by $55 million in the second half of the year. We implemented $65 million in annual run rate savings 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 a combination with Aera enhances this ability. 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 to buybacks, dividends, and repurchase debt. We recently increased the authorization under our share buyback program by nearly 25% to $1.35 billion and its extended 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. Fourth quarter production averaged 83,000 BOEs 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 margins. We also completed a $35 million sale of non-operated interest around Mountain, which had an associated reduction 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 about the 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 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 to date, 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 current 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 a $200 million to $240 million total capital program, and an expectation of a 5% to 7% decline, similar to our 2023 program. To be clear, we will only increase activity to four rigs if the permitting process improvement supports a multiyear 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 stand-alone 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 are 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.

The first question comes from Scott Hanold with RBC Capital Markets. Please proceed.

Hey, thanks. Just out of curiosity, are you all receiving permits? I know you are 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 in favor of Kern County, what does that make 2025 look like? Would you be able to start ramping up rigs as you accumulate permits into 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, we have very low corporate decline, adding first, OpEx workovers, and then capital workovers brings our all-in decline to 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 permits 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 that you saw in the results today. What we said is, with a one-rig program, we can get to a 5% to 7% base decline. After investments, we did that in '23, and we also said it’s repeatable, so we’ll do that in 2024 if Kern County EIR is 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 repeatable model assuming Kern County doesn’t get resolved.

Okay. And just to clarify, you said if you don’t – if the EIR isn’t resolved, you have currently permits in hand to run that one rig program to 2025 as well? Is that what I heard?

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

Okay, got it. And then on the cover management side, I guess I’m going to stick to the topics of permits. Obviously, you are in the public comment period. So I appreciate the fact that there are probably limited things you all could say, but anything that you would have heard from some of the comment period that you thought was interesting in a positive way? And if you have any color on, I guess, the timeline of getting 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 are 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 are any delays. We have agreed to do a 90-day public comment period, which is still very much within the timeline. We’ve been checking milestones as we go in a way that’s, again, consistent with what we see on the EPA tracker. 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 perspective on what we’re hearing on the ground. The hearing is today with the EPA. So there’s a lot of excitement and a lot of preparation that goes into a day like today. So maybe, Chris?

Scott, yes. Great question, very timely because, as Francisco mentioned, it’s – the hearing is today as well as the final workshop, it’s being conducted jointly by EPA Region 9 as well as Kern County, so looking forward to the conclusion of that today. As you recall, there has been – with the completion today, there would have been four of those workshops in the 90-day comment period that Francisco referenced. That’s by comparison to the other Class VI 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 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 based on EPA’s tracker.

Appreciate the color, guys. Thanks.

The next question comes from Kalei Akamine of Bank of America. Please go ahead.

Hi, 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 valuations. But what I think surprised us is the pace of the remediation. If you simply measured pace by the rates of plugging the wells, this could easily be a multiyear process. So hoping that you can comment on 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, that needs to be phased out?

Hi, Kalei, so yes, we’re very excited about being able to sell this more property, Fort Apache, 0.9 acres for $10 million. So it’s an $11 million per acre valuation. And so that was – we needed to be able to provide that proof point to the market. The larger property, right, so the 90 acres in Huntington Beach, the objective is to optimize the valuation and ultimately, to get value recognition in their stock price, meaning, we would sell today if the right offer comes along, right? There’s 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 are a lot of steps that we have to take to get to that optimal valuation. If we sold today, then abandonment remediation and reentitlement 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 the well and the reentitlement, then it’s going to be a multiyear process, again, to find the best value for the land. 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 sort through is the ability to reentitle 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 the 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 is 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 on the property that we use the cash to pay for the abandonment, which are 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 land that we can sell without taking a big deduct. So again, 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 reentitlement of the property. So I would take – I think 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 try to maximize the value and bring that value forward as quickly as we can.

Yes. I appreciate that. 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 present value of that transaction becomes to you. My second question goes to the Aera deal. So our understanding is that there is a retirement liability. Can you talk to us about what that is? And what it means in terms of an annual spend rate? 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 CRC have both been very aggressively pursuing abandonment and plugging on abandonment of wells. I think 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 on Aera. We need to get a little bit further along in terms of closing the deal. But the Aera properties tend to be shallower. So they may have more wellbores, but they also have much more limited debt in terms of the differences between the asset bases. But I will provide more color as we go forward. We haven’t released any of that information in more detail on the assets. But we’ll do so as we get the proxy filed and as we get closer to the completion of the HSR process. But again, the point should be as we’ve been abandoning wells on both sides, we have good programs, ARO programs in place. We’re also looking to deploy technology to reuse wellbores for clean energy and for water rights for CCS. So we look at a wellbore in California as having multiple lives and multiple uses. So, we’re excited to have – to look at the Aera assets through that lens.

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

Yes, we’re actively looking at that for our portfolio, Kalei, and Aera would be applied the same way. There are opportunities, really good, exciting opportunities to bring 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 for multiple decades to try to bring clean energy to the surface. So we’re looking at a lot of places to deploy some money to bring that technology to California. And I think there are, like I said, multiple uses and multiple lives to these wellbores, and we’re excited to bring that to fruition.

I appreciate the comments. That’s mine too. I will leave it there.

Thanks, Kalei.

The next question comes from Nate Pendleton with Stifel. Please go ahead.

Good 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? Specifically related to California communities that have historically been dependent on oil and gas revenues.

Yes, Nate, I’ll – we’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 and 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 and to pave the roads to pay for libraries and fire stations. A lot of that cash flow and the tax revenue that’s collected by the counties really supports the quality of life for the community. So a transition away from oil and gas and 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. We see – our CRC platform has not been mutually exclusive, but one that can continue to deliver oil and gas, low carbon oil and gas better than anything that comes from imports, while also advancing the technology and the investments on the clean side. So we see us as being the leader, cementing our leadership on both and really trying to drive those solutions that end up 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 the county has already demonstrated the willingness and ability to execute on the energy transition. The example I would give is the build-out of solar in the county, right? It’s been prolific with the largest solar installations. It provides energy to the state in addition to the oil and gas that’s provided now. So it’s really at the heart of the energy transition, and it has a track record of 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 CCUS, is there any update you can provide on potential CO2 pipeline regulations for the state that would enable transportation of CO2 outside of field boundaries?

Yes. So this is – we’re looking at Senate Bill 905 Cleanup Bill. We expect it to be in the agenda for the legislature around May or June when the budget is announced. So 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 represented there. And we believe there’s support from legislators and the administration and the California Resources for. So confidence that it’s going to get addressed in 2024. As a reminder, there is also work happening at the federal level on the FEMSA regulations that could also work if California is not able to get there first. So it’s really a question of who can get there first. Is it California or is it the Feds, but we’re looking to advance CCS through pipeline regulation? We also are working on a strategy where we’re doing a lot of our activity within field boundaries. And that’s what 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, have demonstration that CCS is the technology that we all think is going to be in terms of decarbonizing the state and start testing into being a cash-generating type projects as we look for the pipeline regulations to come through. But ultimately, if the state is 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 of 905 or through the federal regulations.

Appreciate the color. Thanks for taking the questions.

The next question comes from Leo Mariani with ROTH MKM. Please go ahead.

I wanted to focus a little bit on the stand-alone CapEx and production guidance for 2024 for CRC. Just wanted to make sure I kind of understood the numbers here. At the midpoint of your production guide, it 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 is 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. And in '24, just given that, you’re only running the one rig in the first half. So maybe you could just kind of close the loop on the guide and maybe there are some timing differences this year that explain some of this.

Yes, Leo. So remember, we sold – we announced that we sold the property Round Mountain, about 900 barrels at the end of last year. So when you’re looking at the decline, 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 from a reservoir perspective, the way to look at it 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 BOEs throughout the year, with ultimately less capital to get to that BOE level that we had talked about before. The $300 million to $340 million also includes capital and maintenance of our Elk Hills power plant and some one-time items. So do we see that as a scenario that hadn’t – we haven’t developed now for some time when we have the permits or the incremental rigs if we were to be able to achieve that, then what would happen, and that’s what we’re solving for in that higher scenario. So you put $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 current county resolution and we step down or maintain just the 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 bookings as we have already demonstrated on the low end, what our assets and our team are able to deliver with a one-rig program, which is at 5% to 7% decline. We also wanted to provide the restoring and going back to normal levels of activity, and that’s a stay-flat case, right. So now you have both bookings to be able to triangulate on your model.

Okay. That’s helpful. And I just wanted to follow up on a couple of the other numbers in here. It looks like cash taxes for the fourth quarter came in a little bit above the previously provided guidance range. I wanted to get a sense on that of 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 in the last few quarters. It was kind of limited in the third quarter, and then you didn’t have anything in the fourth quarter. So, I 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 Aera deal. So, any clarity you could kind of provide on whether or not buybacks are a pretty important part of the process here this year, it would be great.

Yes. So on the tax side, we had a gain on the Round Mountain asset. That’s what you are seeing in terms of the incremental cash tax in 4Q. There is always going to be timing. We are 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 are a full taxpayer. We have disclosed that before. And I think we also gave you the first quarter cash tax numbers to plug into your model. But ultimately, the increase that you saw in the last quarter is due to the Round Mountain again.

The next question comes from Noel Parks with Tuohy Brothers Investment Research. Please go ahead.

Hi. Good morning. Good afternoon for us. Just a couple of questions, so in your remarks, you mentioned that with the Aera acquisition, you are confident that you are going to have more brownfield and greenfield CCS potential projects ahead. And I am just wondering if you could talk a little bit about what that would look like with the combined companies. And I was just wondering, is it a matter of this helping deals get closed more quickly just because you have more heft, or is it a matter of allowing a larger enterprise or a series of companies to do a broader set of deals across more geographies so to speed things up, does it simplify anything?

Yes. So the Aera deal is very helpful in multiple ways. We are 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 are thinking through connecting brownfield emitters to our different sites, having different entry points and different storage capacity is very helpful. We are excited about the market. There are some discussions ongoing. If we aggregate all the people we are talking to, it’s about 20 million metric tons of emissions per year. So, the market potential is large and exciting to think through. It’s about really, where we are at is how do you connect it. So, that’s where we need the pipes. And where do you store it? And as we can develop more pore space quickly, I think we are going to be well positioned to be able to receive the CO2 and ultimately, bring cash flows forward. We are developing more pore space, and a lot of the new pore spaces are in the Northern part of California. But anything that we can bolt on to Kern County and bring other projects that we 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 Aera’s fields that have potential, it’s an exciting proposition that just again brings more certainty into the brownfield market. Now, in the greenfield, as I discussed, there is a generation of emissions that Aera brings to the table that are going to be easy to capture or fully within our control, right. So, 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 emissions. As we showed with our gas processing pre-combustion project, that gives us much more certainty to get to the finish line and the highest percent of the incentives. So, Aera allows us to do that through some of the emissions through steam flooding and co-gens that they have in the portfolio. So, we like the Aera deal for multiple reasons. And a lot on the traditional oil and gas business and the synergies, but one thing to look for is how our team is going to tackle and is going to think through the Aera properties and try to bring those – accelerate those and bring those to life sooner than probably the current owner was expecting.

Great. And thinking about the Class VI permits, and of course, that upon final approval, that will be such a milestone, and then the same for subsequent permanent approvals. 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 district office steps and other Federal entity, DOE or somebody takes the lead? Sort of what comes next after the permit?

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

Yes. Well, so first one on EPA, right. The final permit comes out, but then the process ultimately continues with us with the county, 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 for first injection in 2025 as planned. But obviously, as we go with those permits in hand, we will continue to do things like pre-injection testing and comply with the conditions in the permit that EPA has set forth as we lead up to the first injection. And then, ultimately, that’s like immediately what’s next after the permits are in hand. And then ultimately, there is an ongoing process in the Class VI for monitoring, reporting, verification, and being able to claim the 45Q credits. Obviously, we will be doing that in accordance with the permits at both the EPA level and then the county as well in terms of what we are committing to do to continue to advance carbon management more broadly there, but specifically any requirements at the field level, we will continue to do throughout the life of the project.

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 will be presenting at several investor conferences 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.