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. And 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. And 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, thereby 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 to represent approximately 20 million tons of emissions per year. And our intent remains the same on Carbon TerraVault 1.…

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 on last year 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 of our streams. And for the remaining 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 the investment in our E&P assets, growing carbon management business and shareholder return initiatives. With respect to the…

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. Operator?

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. Did – 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 conclusion the DOE FEED study, we are also in the background working other carbon management activities, some of which with next decade, thinking about how to use capture equipment. And we came to the realization that over time, things start to optimize as we proceeded through. And 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. And in parallel with that, we continue to engage with other technology parties that were bringing us different solutions to capture the carbonate of fills. As you know, a lot of this technology has been around. It just hasn’t been implied at this scale. And we were able to learn some things through the first FEED that we’re really encouraging when we started engaging with the next decade on the technology. They bring a lot of experience. They have looked at this around the world. And we’re really 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, the – 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. So first of all, I don’t think that we would underwrite projects based off of – depending upon where the LCFS project is. If you’re using a type curves, they were already pulled down a bit. And so – 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. And 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 candies various outcomes. Tangibly, with California to achieve its carbon mutual objectives and time line they want to specifically involving electrification, you’re going to need to see some modification to this program as it means fully. Today’s program made it easy.

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

Okay. And as part of that question, do you all 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 in outside of the state.

Got it. Thank you.

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

Hi, Leo.

Hi, guys. I wanted to quickly touch base on the decision to add the rig here at Wilmington. When does that rig show up? And I guess 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 they 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. And so 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. We – if you compare our guidance for this quarter, it came down from prior guidance given the law change here in California that was released our ability to be able to use so manual. So we do – so the guide is lower. But we do see ourselves paying some cash taxes this year.

Okay. I mean is that going to be kind of limited? Do you think you ramp up to be 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. I mean it really depends where the prices go. But I would say we’re seeing NOLs and those are not in this. So you would expect if prices continue where they are, that the EBITDAX still goes back to more of our statutory tax rate, which were much lower right now. So I mean it really depends. But I would see was 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. And I think first quarter was kind of low on production for the year. And since first quarter, we’ve only seen energy costs come up. So was there something unique about the LOE in the first quarter where you’re confident it’s going to start coming down here in the 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. And so therefore, it drives a $1 per BOE up. And I think that 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. So – and then if you take a look at the full year guidance, I don’t think we’ve reflected it 4x the first quarter.

Yes, that’s right. I mean, there is some seasonality in cost. But as Mac is saying, it’s really – we have less barrels flowing or less BOEs flowing in the quarter due to CGP1 that gets normalized starting in April. So that’s – our guide reflects our view on where the costs are going to be, which ultimately, everything is normalized back to where we were before the maintenance.

Okay. And then just lastly on the hedging, I just want to get to make 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 you all selves some upside here. Can you just give me a little color around the hedging?

Yes, Leo. So 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 requirement at the levels that we’ve previously seen. We had done that once before. But we have further removed that requirement now with this RBL amendment. But when we exited bankruptcy, we had a number of hedges that had to be there to put on for a rolling period of time. Those hedges plus subsequent maintenance of that RBL covenant and I’m going to turn this over to Jay. Basically account for 90% of the hedges put on. Now with respect to our go-forward position in what we call strategic hedges, which is the third bucket there, 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. But at the time of emergence, there was a covenant, 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. I mean, 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 of all, we had an ongoing obligation to maintain that 50% on a rolling basis. And in addition to that, again, referencing back to the $40 to $45 price environment, we moved the hedge more prices that were originally keratin 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. I would point out that, frankly, additional hedges in any material regard have not been added 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 and Mac touched on the RBL agreement provided a great deal more flexibility. It gives us more flexibility in terms of quantum. It also gives us more flexibility in terms of tools we use. So again, you’re going to find we’re going to be focused on the hedging program on maintaining the pretax cash flows. I mean we’ve got down a whole activity. We’ve got debt service. We’ve got the carbon business. And we’ve got returns to shareholders. And that’s what going to guide our hedging going forward.

I would just add, Leo. I think your question was where do you see hedges going forward. And 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 obviously provides an uptick to our cash flow and EBITDAX. And I would also say that given the hedge levels that we have out there, we’re comfortable right now with our hedge position. And that’s why we haven’t really hedged since the fall of 2021. Now, things changed 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 a good one of your assets and trying to recover some of the production lost over the last 5 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 portfolio brings shareholder returns through the drill bit or in the carbon management business. And we want to be very prudent about where we are. Now, you are right, with the commodity backdrop, we continue to export, that’s why we are bringing on this fifth rig. We are evaluating – 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 we have most of our – as you know, most of our deals are operated by CRC. We have high NRI, so it gives a lot of control with the movements on adding more rigs. And we do have the 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. And we were able to – given the prices right now, we are able to basically check the box, deliver on shareholder returns, we would be able to continue funding our carbon management business. And then we said we would evaluate and stay flexible where the next arc would go, and we are 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. And we will just have to make that decision and what the next order goes.

Well, guys, I appreciate the answer. You have kind of 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 the next week. So, thank you for that. 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 more aggressive development of the gas assets in your portfolio. So, that’s kind of really where I wanted to go here because you are not hedged on gas. And my understanding is the permitting backlog was quite rich on the gas opportunities relative to the oil opportunities. So, I am just wondering if you can maybe 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, which is 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. And we are already the largest natural gas players are in the States. It’s not just the Sac Basin, but we also can build more gas in Elk Hills and BV. So, we do have the inventory. We haven’t had to think about gas relative to oil. But it’s – that ratio is getting to be much more attractive and those what gas flows are becoming much more competitive.

That’s terrific. Thanks very much and I look forward to seeing you next week. Thank you.

Thanks Doug.

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

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

Hey Scott, yes, so open market 10b5 has been historically, have we been doing the program. But we find that as a really, 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, I mean we are staying flexible and you are seeing where the market is going.

Thank you.

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? And 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 and 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? Good to hear from you. The simple answer here is that it’s that darn PSC. As we came into the year, we were more in the 80, low-80s and now we are in the mid-90s. And because of that, we lose barrels of net production. We have offset more than simply offset those with this new 1.5 or 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. And now, 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 have seen an increase in oil prices. So, that – if you remember, for every $1 change in Brent prices, we lose 100 barrels to the PSC effect, and it goes the other way as well. So, we have seen $15, $20 move in oil prices. So, we lose the net production that way. So, the activity in – with the fifth rig should help to offset that.

Yes. And it’s one of the ironic things. Eric, we are losing the barrels through the PSC prices are going up, we will take the prices going up.

Yes, seems like a good problem. Just as we think about the production progression moving from sort of Q1 to the rest of the year, should – is oil production going to be sort of slowly 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, it looks like 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 kind of what I should see for both streams in the remaining quarters?

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

Right. I appreciate that, great. Well. Thanks for that commentary. Thanks for the color and all the transparency you guys are giving and just want to sort of voice what I think Paul was – Doug was getting at, which is that we are definitely supportive of the increase in drilling activity. And I imagine that the returns in Elk Hills must be spectacular with this gas and NGL price environment and look forward to seeing what you guys can do in the second half.

Okay. Thanks Eric.

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

Yes. Hey Mac. Good morning. I was – I had a question on – a couple of questions on the CO2 sequestration side. Is – from an E&C standpoint, is there – 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, like do you know what kind of equipment is going to be used yet is what I am asking?

Yes. I am 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. I mean I think what you see on that website are permits that are the administratively complete, which means the EPA has gone through, looked at the permit and said all of the different modules have been submitted. So, subsequent to that review, they make it onto the website and post it. And then after that, they go through the technical review process and then at that point, hopefully you get the permit. But in terms of identification of equipment, I think is what your question was, certainly, to get through the process, we hold ourselves to a very high standard on what we submit technically in terms of capture and all the other things that make up a project are desirable to be in a permit. I can’t speak to all the permits that are on that website, but that’s as we hold ourselves.

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. So, I guess how is the process going, communicating with these guys and moving forward? How does it seem to you?

Yes. So, we have received on our first permits for Carbon TerraVault 1. We have a schedule. We understand the details of 18 months to 24 months. Carbon TerraVault 1 reservoirs are world-class, high tender for CO2 geological sequestration. And we – our permit filing was obviously on the website. It’s administratively complete. And again, we believe 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 the second reservoir in that application as well. We are very pleased with the constructive dialogue and the feedback that we are receiving from the EPA and confident in the timelines that we outlined.

Got it. That’s great. And I guess 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 sort of a dent chart that outlines this with respect to CTV 1. And 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 the status of where they are, we might be able to change that timing. But right now, what we are looking to do is line up emitters, lineup debt as well as our overall underwriting case and go FID effectively, call it, a day after we received the permit, something like that, that’s our plan. And so that’s why we continue to advance the emitter discussions. And as Chris said, he has been – he and his team have done a nice job in having a constructive dialogue with the EPA on advancing these permits. And we think we are going to do that on the first Carbon TerraVault 1 by the end of next year. I hope that answers it.

Yes. It does. Thanks very much.

Thanks Ray.

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

Yes. 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.