Good afternoon and welcome to the California Resources Corporation 2022 First Quarter Earnings Call. Please note this event is being recorded. I would now like to turn the conference over to Joanna Park, VP of Investor Relations and Treasurer. Please go ahead.

Thanks. Welcome to California Resources Corporation’s first quarter 2022 conference call. Participating on today’s call is Mac McFarland, President and Chief Executive Officer; Francisco Leon, Executive Vice President and Chief Financial Officer, as well as the entire CRC executive team. I’d like to highlight that we have provided slides on our Investor Relations section of our website, www.crc.com. These slides provide additional information into our operations and first quarter results. And we’ve 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’s conference call contains certain projections and other forward-looking statements, and these statements are subject to risks and uncertainties that may cause actual results to differ. Additional information on factors that could cause our results to differ are available in the company’s 10-Q and 10-K. A replay will be made available for 30 days following the call on our website. As a reminder, we have allotted additional time for question and answer at the end of our prepared remarks. We ask that participants limit their questions to a primary and one follow-up. With that, I will now turn the call over to Mac.

Thank you, Joanna. 2022 began with a reminder about the importance of reliable and affordable energy as well as a continued focus on energy transition, and CRC made progress on both. First, our core low-carbon intensity E&P business delivered on expectations. Quarterly production was in line with guidance, which accounted for our previously announced CGP1 Maintenance, along with the Lost Hills divestiture. The business generated $61 million of free cash flow during the first quarter after the impacts of these two events. If you normalize for the CGP1 outage, our free cash flow would have been $105 million. Due to a favorable commodity outlook and strong anticipated returns, we are expanding our drilling program in the Los Angeles Basin by adding an additional rig in our Wilmington Field for a total of 5 drilling rigs in our overall operations. We are raising our 2022 oil production by 1,000 barrels of oil per day, raising the 2022 midpoint guidance of our EBITDAX by approximately $88 million and the midpoint free cash flow guidance by nearly $53 million for the full year. Additionally, throughout the quarter, we continued to advance our commitment to the energy transition. On the permitting side, CRC’s Carbon Management team submitted 2 Class VI permits for an incremental 80 million metric tons of CO2 sequestration for two new projects in the Sacramento Basin, creating a second CO2 storage network in the San Francisco Back Bay area. With these two permit applications, we are more than halfway to our 2022 goal of 200 million metric tons of complete permit applications submitted. On Carbon TerraVault 1, we continue to have a very constructive conversation with our emitters representing approximately 20 million tons of emissions per year. Our intent remains the same on Carbon TerraVault 1. We are targeting year-end 2022 for selection of the first 1 million ton per annum emitter contract. Additionally on CTV 1, we have submitted project permits, which include the current county conditional use perm, a current county environmental impact report and EPA monitoring, reporting and verification plan. We are working to submit an LCFS application for CTV 1 in the third quarter of this year. These efforts highlight CRC’s uniquely positioned asset base that allows us to provide much-needed low-carbon energy today and net zero fuel for the future. As we envision the net zero future, we believe it will be necessary to leverage existing infrastructure to distribute low-carbon and net zero solutions by creating a lower and more specifically, an emissions-free fuel. We are therefore excited about our prospects of creating the first net zero carbon barrel in California. These technology advances, technologically advanced projects can create additional energy transition jobs in our state while also offering California’s fuel with a substantially lower carbon intensity than that of an imported barrel and further lowering our overall CO2 emissions and the state’s carbon emissions. Therefore, this net zero energy is the solution, and emissions are the enemy. So let’s focus on eliminating emissions. A recent report by the Intergovernmental Panel on Climate Change, or the IPCC, recently cited carbon dioxide removal as an essential step to meet the targets of the Paris Accord, validating our view of the importance of building out our carbon management business via Carbon TerraVault to store third-party emissions, thereby reducing atmospheric CO2 concentrations. In addition to this, it is imperative that CRC finds ways to abate our own emissions and make progress towards our own full-scope 2045 net zero goal as well. Full scope being not only Scope 1 and 2 but also offsetting Scope 3 emissions for a true full scope net zero. We have evaluated our portfolio and estimated that we have approximately 200 million barrels of potential CCS+ reserves at our Elk Hills field utilizing CO2. This means CRC has the opportunity to permanently sequester CO2 emissions while replacing some of our production with an incremental supply of net zero barrels. For the past 12 months, we have analyzed and reviewed the DOE-supported FEED study results for our CalCapture project at CRC’s 550 megawatt Elk Hills power plant. This project captures the flue gas off the power plant for permanent storage in oil-producing reservoirs. We concluded that further evaluation of operational strategies and cost proposals may yield better results and increase the viability of this project. As a result, we have agreed to explore the development of Next Carbon Solutions, or NCS, technology based on a FEL2 or pre-FEED study, which suggests significant capital reduction and operational improvements could be made to the original FEED study. NCS has performed over 11 FEL FEED studies and has identified opportunities that work with low-concentration CO2 emissions similar to those at the Elk Hills Power Plant. NCS is expected to conduct this FEED study over the next 6 plus months and positions us for an investment decision by the end of 2023. The project is slated for the Stevens Reservoir at Elk Hills, which has similar characteristics to CTV 1, is compliant with LCFS requirements and eligible for 45Q credits. This means permanent CO2 storage. The project is expected to yield approximately 1.4 million tons of injected CO2 emissions per annum or 28 million tons for the life of the project while producing an incremental 7,000 barrels of net zero oil per day. To put things in perspective, California leads in domestic electric vehicle sales with approximately 200,000 sales in 2021. Through CRC’s CalCapture project, the equivalent emissions from 300,000 gas-fueled vehicles will effectively be removed each year from the road, further supporting California’s climate goals and the Paris Climate Accord. Said differently, the captured emissions equate to powering 300,000 gas-fueled passenger vehicles every year with net zero fuel to create net zero tailpipe emissions. We see this as one of the most efficient and economical ways to implement the energy transition broadly while leveraging the state’s existing infrastructure. This full-scope net zero barrel will be made in California by Californians in a state that has ambitious climate goals but also relies on crude imported from high-carbon intensity sources with less stringent environmental standards to meet its demand. We believe carbon management is a natural extension of our core competencies. CRC is able to bring scalable and commercial carbon management solutions to help advance the energy transition for a lower carbon future. Switching gears, with ample liquidity of $744 million, we maintained our disciplined investing approach and solid financial foundation. We continue to see our equity deeply underappreciated. Therefore, we are increasing our share repurchase program by $300 million to a total of $650 million and extending it through the second quarter of 2023. We believe this is the best path to providing returns to shareholders. Again, I’d like to thank the employees for their dedication and hard work. Our low carbon intensity E&P and carbon management teams continue to deliver strong results. Thank you for being here today. And with that, I will turn the call over to Francisco.

Thanks, Mac. Good afternoon, everyone, and thank you for joining us on this call. As Mac mentioned, 2022 began on a good note for CRC. During the first quarter, we produced 88,000 net barrels of oil equivalent per day, in line with our expectations given the planned CGP1 maintenance from last year’s sales. Speaking of CGP1, I would like to highlight that work was performed safely and ahead of schedule. I would like to thank the team for their efforts. CRC has generated positive free cash flow for the last five quarters in a row with $61 million during the quarter and $206 million of adjusted EBITDAX. This demonstrates CRC’s significant cash generation capability and potential for sustainable shareholder returns. In fact, after investing in our 4-rig drilling program and advancing our carbon management business, we returned over 100% of the first quarter’s free cash flow through a combination of our share repurchase program and our $0.17 per share dividend. Given the confidence in our assets and commodity backdrop, we are expanding our SRP by $300 million through the second quarter of 2023 for a total program of $650 million. We’re also declaring a $0.17 per share dividend for the second quarter. Commodity realizations remained strong across all our streams. For the remainder of 2022, we expect realizations to be within historical norms. Despite these strong realizations, our legacy RBL credit agreement hedges continued to be a headwind, resulting in a quarterly $181 million cash loss. Moving forward and taking into consideration the additional flexibility within the revised RBL amendment, our forward hedging strategy will focus on maintaining financial discipline, protecting our downside while supporting our capital allocation objectives, including investments in our E&P assets, growing carbon management business, and shareholder return initiatives. With respect to the new RBL amendment, post-quarter end, CRC successfully amended the RBL credit agreement for two key items subject to a 1.5x or lower leverage test. First, CRC will no longer have minimum or rolling hedging requirements. The second item allows us for an unlimited restricted payments basket, providing additional flexibility for share repurchases or other shareholder returns and investments in our carbon management business. As we turn to the cost side of the business, on Slide 9, we saw a total quarterly operating cost rise by nearly $2 per BOE quarter-over-quarter, mainly as a result of lost production from CGP1. In addition, increases in natural gas prices drove energy-related operating costs 22% higher on a per BOE basis from the previous quarter. Per unit non-energy operating costs were mostly in line with expectations, accounting for the CGP1 plant turnaround. As a result, we expect our per barrel non-energy operating cost to return to our normal levels for the remainder of the year. During the quarter, we invested $99 million of capital, which includes $65 million of E&C and capital workovers and approximately $15 million for CGP1 maintenance. Given the improved commodity environment and the expected results of our drilling program IRRs of over 100%, we are adding a fifth rig at our Wilmington Field in Los Angeles. This rig is expected to bring an additional 1,500 net barrels of oil per day to our exit production, assuming flat current prices. I’d like to take a moment to discuss our Wilmington Field assets. These are high-quality water floods with high cumulative recoveries, low decline rates, and low maintenance capital needs. We expect IRRs of new wells to be above 160% at current commodity levels with paybacks of around 1 year, which is similar to the rest of our 2022 drilling program. We continue to see the strength of our assets and the depth of our inventory performing above our expectations. I’d like to remind you that the PV-10 of our proved reserves at 2021 SEC prices was $6.2 billion, which is close to $8 billion at $80 Brent and is more than double our current enterprise value. We expect our 2022 drilling program to deliver NPV of $445 million or $5.73 per share and bring forward value to our PDP, which already represents approximately 84% of the company’s value. We continue to see significant portfolio optionality in our loaded client assets with a large number of drilling locations in vast mineral acreage. With close to 14 years of reserve life, we can continue to self-fund our low-carbon E&P business, sustainably deploy additional shareholder returns, and fund our carbon management activities. The first quarter of 2022 was CRC’s largest quarter of share repurchases to date, further demonstrating CRC’s commitment to shareholder returns. We have repurchased approximately 239 million since the inception of the program, resulting in the repurchase of approximately 7% of our shares that we had at the emergence. Even after a quarter of higher capital investment and shareholder returns, we continue to build our cash balance to $328 million at the end of the quarter, up from $305 million of cash at the end of 2021 and improved our already strong net leverage ratio of less than 0.5 times. Moving to our 2022 corporate guidance on Slide 15 and given the rise in longer-term outlook for commodity prices, we are adjusting our '22 guidance to reflect $98 oil price and $5.30 natural gas price as well as the impact of an additional rig in the Los Angeles Basin, higher energy prices and some reclassifications. In summary, we are raising our oil production guidance by 1,000 net barrels per day, primarily due to the addition of the Wilmington Field rig. We’re raising our 2022 full year operating cost guidance by $40 million, primarily due to higher natural gas prices, which are driving our energy costs up. As a reminder, this increase is a net benefit to CRC as we are net long natural gas. We are raising our 2022 E&P capital program by $25 million due to the addition of the Wilmington Field Basin. Additionally, on the carbon management front, we’re adjusting our full year estimate of carbon management capital to remove approximately $15 million of expected lease acquisition costs that will be treated as carbon management expenses instead. Reflecting all these changes, we’re increasing our 2022 capital program by $10 million. Finally, we expect to pay between $30 million to $40 million in cash for the year. As a result, we are raising our corporate free cash flow and adjusted EBITDAX guidance by 17% and 11% at the midpoint, respectively. Of note, prior to our carbon management business spending, CRC is expected to generate between $425 million and $480 million of free cash flow from the E&P business. To conclude, CRC has a great start to the year, operating safely and prioritizing high return projects. On an exit to exit rate, we plan to maintain production this year while only spending approximately $275 million of drilling and workover capital. We are excited to continue to develop our low-carbon intensity assets and with the addition of our 5th rig. Additionally, we continue to build CRC’s carbon management business as we explore additional options to further drive value and increase shareholder returns. Please note that we have provided detailed analysis of our quarter financial and operational results and our 2022 guidance and the attachment to our earnings release. Thank you. And I’ll now turn the call back over to Mac for closing remarks.

Thank you, Francisco. In conclusion, we continue to believe that CRC is well positioned for the future and to lead the energy transition as an E&P company. The company has a sound financial position, well-managed operations, and a growing carbon management business. Thank you for your interest in CRC and for joining us on today’s call. We will now open the line for questions.

Our first question will come from Scott Hanold with RBC Capital. You may now go ahead.

Yes. Thanks, all. My first question on this CalCapture revisiting it now with NCS, can you give us a little bit of background? Obviously, you had the DOE study, you all guided in there. How did you get to the point where you looked at this new potential solution? Is it something that’s in place already in other areas that can demonstrate you can do that capture to lower cost? Did you go to them? Did they come to you? Can you just give us a little sense of the background and really what the key factor is that makes you a little bit more excited about this other process?

Yes, sure. First, hi, Scott, how are you?

Good.

So, we have interacted with NCS next decade over the course of – as we started developing out the carbon management business. As we went through the FEED study – and I’m going to turn this over to Shawn Kerns, who’s leading the effort here, but our Chief Operating Officer. As we went through the FEED study and came to the conclusion in the DOE FEED study, we were also in the background working with other carbon management activities, some of which with next decade, thinking about how to use capture equipment. We came to the realization that over time, things start to optimize as we proceeded through. So that’s why we’re embarking on this new FEED study with NCS. I’m going to turn it over to Shawn to talk about some of these benefits.

Thanks, Mac. This is Shawn. Yes. As Mac mentioned, we were advancing our work on the FEED study with the DOE originally. In parallel with that, we continued to engage with other technology parties that were bringing us different solutions to capture the carbon. A lot of this technology has been around; it just hasn’t been applied at this scale. We were able to learn some things through the first FEED that were really encouraging when we started engaging with Next Decade on the technology. They bring a lot of experience and have looked at this around the world. We’re excited to have them looking at our Elk Hills plant here. As you know, it’s right there at Elk Hills on top of our storage reservoir. So we’re excited to be advancing this project.

Great. And then my follow-up question is I’m going to stick on, obviously, the carbon management side of things. But I guess recently the LCFS credits have been a little bit weaker. Can you give us a sense of what your view of that market is? What’s going on there? Where do you think it’s going to go? And also, how does that impact the economics of some of these projects you’re looking at with where those credits have gone here recently?

Yes, Scott. First of all, I don’t think that we would underwrite projects based on the spot price of LCFS. If you’re using a type curve, they were already pulled down a bit. When we think about it, we think about the total opportunity set being LCFS at a price as well as 45Q on our underwriting these projects. Obviously, we’re going after the highest value projects first. But with respect to the LCFS market, let me turn that over to Jay, our Chief Commercial Officer.

Good morning, Scott. As Mac pointed out, none of our projects have been examined or evaluated using the spot price of LCFS, even considering various outcomes. Tangibly, to achieve California's carbon mutual objectives and timelines specially involving electrification, you’re going to need to see some modification to this program. Today’s program made it easy.

And Scott, in the longer term, as Jay says, we remain fairly bullish on the implementation to get to net-zero in California by 2045. We believe that’s the principal push that’s going to change regulations, change markets, change the LCFS, and add things to the LCFS program. We remain – we believe that will drive prices back up. It’s going to be necessary to expand that to get to net-zero, and you’ll have to go higher up on the marginal cost curve as some of these places we’re trying to capture carbon from. Eventually, to get to zero, you’ll have to drive prices higher.

Okay. And as part of that question, do you have a sense of what’s caused some of the recent pricing pressure?

Everybody has a theory in particular points to their culprit. But the most widely circulated culprit has been the movement of ethanol outside of the state.

Our next question will come from Leo Mariani with KeyBanc. You may now go ahead.

Hi, guys. I wanted to quickly touch base on the decision to add the rig here at Wilmington. When does that rig show up? I was a little surprised to see that it would only bump CapEx by $25 million there. Is it a pretty limited program here in ‘22? Because you all did talk about like a 1,500 barrel a day impact to the exit rate.

Yes, Leo, this is Shawn. The rig starts in the second half of the year. That amount of capital is just for the program for the remainder of 2022.

Okay. I also wanted to ask about cash taxes. You all didn’t really book anything in the first quarter from what I can see in the financials. And you hope that you’re going to start having to pay some cash taxes here, just given where prices are in 2022?

Leo, this is Francisco. Yes, we do see us being some cash taxes. In fact, we’re paying cash taxes. If you compare our guidance for this quarter, it came down from prior guidance given the law change here in California that limited our ability to use our NOLs. Our guidance is lower. But we do expect to pay some cash taxes this year.

Okay. I mean is that going to be limited? Do you think you ramp up to being more of a full payer next year? Can you just give us any high-level sense, if we continue to see high commodity prices?

Yes. It really depends on where the prices go. But I would say we’re seeing NOLs that are not in this. You would expect if prices continue where they are, that the EBITDAX goes back to more of our statutory tax rate, which is much lower right now. It really depends. But I would see us closer to that full tax payment in the coming years if prices stay where they are.

Okay. And then just a question on LOE. I saw you have raised the LOE guidance a little bit here in ‘22. I guess if I just take your first quarter run rate LOE and kind of multiply it by 4, it puts me a little bit above the annual guide. I think first quarter was kind of low on production for the year. Since first quarter, we’ve only seen energy costs come up. Was there something unique about the LOE in the first quarter where you’re confident it’s going to start coming down in subsequent quarters? Can you just give me a little information on that?

Leo, I’m going to let Francisco give you the specifics. The easy answer is it’s just the denominator, right? It’s the number of barrels produced, and the quarter was impacted by CGP1. Therefore, it drives a $1 per BOE up. If you make that adjustment, we’d be shown in a couple of days; you’ll get back to more of a normalized run rate. If you take a look at the full year guidance, I don’t think we reflected it 4x the first quarter.

Yes, that’s right. There is some seasonality in cost. But as Mac is saying, it’s really – we have fewer barrels flowing in the quarter due to CGP1 that gets normalized starting in April. Our guidance reflects our view of where costs are going to be; ultimately, everything should return to the levels we had before the maintenance.

Okay. And then just lastly on the hedging, I just want to get sure I understand the messaging here. Are you signaling that’s going to be more limited hedging going forward and maybe just using more floors or collars and then trying to give yourselves some upside here? Can you just give me a little color around the hedging?

Yes, Leo. Page 23 in the presentation provides an overview by quarter of the forward look on some of the hedges broken down by a couple of things. I think one of the things that Francisco covered was that we amended the RBL to not require hedges at the levels we’ve previously seen. We had done that once before, but we have further removed that requirement now with this RBL amendment. When we exited bankruptcy, we had a number of hedges that had to be there for a rolling period of time. Those hedges plus subsequent maintenance of that RBL covenant account for 90% of the hedges put on. Our go-forward position in what we call strategic hedges is where we’re focusing. I’m going to let Jay answer that.

Yes. Let me give you a little more color on the background that kind of talked at the higher level. At the time of emergence, there was a covenant that required the company to hedge 75% of its crude production for 2 years and 50% for the third year. That was done in the $40 to $45 price environment, as you might expect the impacts were significant. If you’re looking at Page 23, that would be the first row. If you go down one row, that’s reflective of two things. First, we had an ongoing obligation to maintain that 50% on a rolling basis. Again referencing back to the $40 to $45 price environment, we moved the hedge more prices that were significantly from the $40 range to the $60-plus range. Those transactions are captured in mid-second half. The third line is reflective of a fairly limited number of transactions that rented since then. Additional hedges in any material regard have not been added since fall of '21. You add these together, that’s where you come up with the total of the head mark. Going forward, as mentioned by Francisco, this RBL agreement provides a great deal more flexibility. It gives us more flexibility in terms of quantum and in terms of the tools we use. We’re going to be focused on the hedging program on maintaining the pretax cash flows. We’ve got down a whole activity; we’ve got debt service, we’ve got the carbon business, we’ve got returns to shareholders, and that’s what will guide our hedging going forward.

I would just add, Leo. I think your question was where do you see hedges going forward. Right now, if you look at '23, obviously, because of the program that was put in before, it’s lighter on the legacy hedges that we put in for the RBL that provides an uptick to our cash flow and EBITDAX. Given the hedge levels we have out there, we’re comfortable right now with our hedge position. That’s why we haven’t really hedged since the fall of 2021. Things could change in the market, and we may change that, but we’re comfortable now.

Our next question will come from Doug Leggate with Bank of America. You may now go ahead.

Good morning, guys. Thanks for taking my question. Mac, one of the ways to amplify your leverage to the commodities to lean into a little bit more activity and you’ve done that by adding a rig back at Wilmington in the first quarter. I’m just curious how you’re thinking about the go-forward picture because, obviously, the commodity deck and your exposure to that has changed dramatically since you came out of bankruptcy. So, as you think about what you inherit the CEO versus outlook you have today, how do you think about whether you might want to get another one of your assets and trying to recover some of the production lost over the last five years?

Good morning Doug. Thanks. Look, in the fourth quarter or late last year, we brought on a fourth rig. Now we brought on a fifth rig. We continue to think about how we deploy our capital across the portfolio that brings shareholder returns through the drill bit or in the carbon management business. We want to be very prudent about where we are. You are right, with the commodity backdrop, we continue to export, that’s why we are bringing on this fifth rig. We are constantly evaluating should we bring on another rig, given the market conditions or should the market conditions change as we also lay down rigs. But right now, our intent is to stick with the five-rig program, continue to evaluate and be ready to deploy a sixth rig if the markets, if we choose, but the market is receptive to that as part of our portfolio management. But maybe you want to expand on how we think about cash and deployment to the drill bit, Francisco?

Hey Doug. This is Francisco. So, yes, first of all, I think most of our deals are operated by CRC. We have high NRI, so it gives a lot of control over the movements on adding more rigs. We have a big inventory of projects. The one, I guess, pleasant surprise has been the move in natural gas prices; it’s putting gas projects into the mix as we look at the portfolio options. Given the prices right now, we are able to check the box and deliver on shareholder returns, and we’d be able to continue funding our carbon management business. We said we would evaluate and stay flexible on where the next rig would go, and we’re seeing very attractive returns on our wells. We chose the elevation in Wilmington; they were ready to go, had a number of great projects and wells, we are drilling 10 wells there. We will continue looking; we have quite a bit more inventory that’s ready to go this year. We will just have to make that decision on what the next order goes.

Well, guys, I appreciate the answer. You have taken the words out of my mouth for my second question, which is the relative capital allocation between oil and gas. I am going to save my carbon questions through our ESG next week. Thank you. But as it relates to – if you go back and look at legacy CRC, there was a pivot a number of years ago to think about the more aggressive development of the gas assets in your portfolio. That’s really where I wanted to go here because you are not hedged on gas. My understanding is the permitting backlog was quite rich on the gas opportunities relative to the oil opportunities. I’m just wondering if you could flesh that out just a little bit more, Francisco, if you don’t mind, in terms of what that could look like? Is it a significant gas opportunity currently within CRC?

Doug, you must be reading our minds at some point because it’s a very recent conversation we have been having about the Sacramento Basin, our big gas field, obviously, with the changes in that commodity, which has been substantial over the last couple of months. We have looked at it. We are not committing or saying we are willing to do anything. But it is definitely a topic at the top of our minds. In fact, Francisco, Shawn, and I were just talking about what that opportunity might look like. So, nothing to say here, but it’s almost like you are inside our heads, Doug.

Yes. And Doug, just the ratio of oil versus gas, given where gas is right now, it really comes into play. We are the largest natural gas player in the States. It’s not just the Sacramento Basin, but we can also build more gas in Elk Hills and BV. We do have the inventory. We haven’t had to think about gas relative to oil. But that ratio is getting to be much more attractive, and those gas flows are becoming much more competitive.

Our next question will come from Scott Hanold with RBC Capital. You may now go ahead.

Hey. Thanks. One follow-up here. Looking at the buybacks and the pace of what you all are doing, obviously, you made a pretty big step-up and extended the window a little bit. Can you remind us if – how you go about that? Is it very opportunistic? Do you have a 10b5 plan in place? Have you also considered looking at privately negotiated transactions to absorb some of the liquidity from the non-traditional holders?

Hey Scott, yes. The open market 10b5 has been historically how we’ve been doing the program. We find that it’s a really good way to participate in the market as we buyback our shares. We do have capacity to look at other forms of buybacks going forward. But for now, we are staying flexible and observing where the market is going.

Our next question will come from Eric Seeve with GoldenTree. You may now go ahead.

Hey. Good morning guys. Thanks for the call. Great to see you guys increasing activity levels. I just wanted to see if you could provide a little bit more clarity on what the production cadence might look like as we head into Q2 and to the end of the year? One specific question, just trying to understand, it seems like at the Q4 presentation, the exit rate oil guidance was around to keep it flat at around 58.5 a day. Just wondering if now, we should be expecting that to be 1,500 barrels of oil per day higher by virtue of the expanded drilling program?

Yes. Hey Eric, how are you? The simple answer here is that it’s that darn PSC. As we came into the year, we were more in the low 80s and now we are in the mid-90s. Because of that, we lose barrels of net production. We offset more than simply our new 1,500 a day on exit. But Francisco, anything to add to that?

No. I mean we had talked about offsetting the barrels that we sold on the Lost Hills sale. Prices have stayed the same, flat to where we were the last time we had our earnings that would have indicated we had some growth. We’ve seen an increase in oil prices. For every $1 change in Brent prices, we lose 100 barrels to the PSC effect, and it goes the other way as well. We have seen $15, $20 moves in oil prices. We lose the net production that way. So, the activity with the fifth rig should help to offset that.

Yes. It’s one of the ironic things. Eric, we lose the barrels through the PSC prices going up; we will take the prices going up.

Right. I appreciate that. Great. As we think about the production progression moving from sort of Q1 to the rest of the year, is oil production going to be climbing throughout the year to get back to that 58.5 level? Is that how we should think about it? And it looked like on the gas and NGL side, when you adjust for the processing plant being down, it looks like production was almost flattish from Q4 to Q1. Can you just give me a little bit more help on what I should see for both streams in the remaining quarters?

I think you are right on the NGLs and the gas. If you think about prudently adding this rig in the second half, as Shawn said, we will see that production creep up towards the exit rate, obviously. That production will creep up in the second half of the year because that offsets the PSC effect. The PSC effect goes down for the full year because of the prices on the front end being even higher. That gets eaten back into or up taken care of throughout the second half of the year. Those are very degrees of difference to, Eric. It’s not big swings in our production.

Our next question will come from Ray Deacon with Petro Lotus. You may now go ahead.

Yes. Hey Mac. Good morning. I had a question on a couple of questions on the CO2 sequestration side. Is – from an E&C standpoint, if I look at the number of permits that are pending, I see 14 or so. Do those permits require that you have a plan? Do you know what kind of equipment is going to be used yet is what I am asking?

Yes. I’m going to let Chris Gould, our Chief Sustainability Officer, tackle that question.

Yes. Hey. Good morning. To the EPA website for the Class VI permit, is that correct?

Exactly, right, just checked it.

Understood. Yes. The permits on the website are administratively complete, meaning the EPA has gone through, looked at the permits, and said all the modules have been submitted. After that review, they make it onto the website and post it. Following, they go through the technical review process, and at that point, hopefully, you get the permit. In terms of identification of equipment, to get through the process, we hold ourselves to a high standard on what we submit technically in terms of capture and all the other elements that make up a desirable project are in the permit. I can’t speak to all the permits that are on that website, but that’s our standard.

Okay. Got it. So, if you are about to file another permit, you will be if I am reading this correctly, I think four out of the five that are submitted in California. How is the process going, communicating with these guys and moving forward? How does it seem to you?

Yes. We have received on our first permits for Carbon TerraVault 1. We have a schedule and understand the details of 18 to 24 months. Carbon TerraVault 1 reservoirs are world-class and high tender for CO2 geological sequestration. Our permit filing is on the website. We believe it’s technically complete. We received a full round of comments from the EPA on the first reservoir that we submitted, A1A2 back in August of last year, and we are in the process of responding as well as for the second reservoir in that application. We are pleased with the constructive dialogue and feedback we are receiving from the EPA and are confident in the timelines that we outlined.

Got it. That’s great. At what point – I remember you went into a lot of detail about the stages of development, and I was just wondering how far out do you need to get before project finance becomes an option?

Yes, Ray, it’s Mac. Page 17 of our deck has a dent chart outlining this with respect to CTV 1. Our view is that we need to get the permit in order to underwrite to the FID on the first project. As we get more comfortable with subsequent permits and their status, we might be able to change that timing. But right now, we’re looking to line up emitters, line up debt, as well as our overall underwriting case. We plan to go for FID effectively, a day after we receive the permit, something like that, that’s our plan. We continue to advance emitter discussions, and as Chris said, he and his team have had a constructive dialogue with the EPA on advancing these permits. We think we will achieve that for the first Carbon TerraVault 1 by the end of next year. I hope that answers it.

Yes, it does. Thanks very much.

Thank you and thanks to everyone who joined our call today. I appreciate your interest in CRC. We continue to believe we are very well-positioned as a low fuel – low carbon intensity fuel for today and a net-zero fuel for the future. Have a good day. Thank you.

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