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spk05: Good afternoon and welcome to the California Resources Corporation 2022 First Quarter Earnings Call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the Start key followed by 0. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press Start and 1 on your telephone keypad. To withdraw your question, please press Start and 2. 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.
spk01: Thanks. Welcome to California Resources Corporation's first quarter 2022 conference call. Participating on today's call is Max McFarland, President and Chief Executive Officer, Francisco Leon, Executive Vice President and Chief Financial Officer, as well as the entire CRC C-suite 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 10Q and 10K. A replay will be made available for 30 days following the call on our website. And as a reminder, we have allotted additional time for question and answer at the end of our prepared remarks. We ask that the participants limit their questions to a primary and one follow-up. With that, I will now turn the call over to Matt.
spk06: 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. Poorly 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 CGP-1 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 five drilling rigs in our overall operation. 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 continue to advance our commitment to the energy transition. On the permitting side, CRC's carbon management team submitted two 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 WHO REPRESENT APPROXIMATELY 20 MILLION TONS OF EMISSIONS PER YEAR. AND OUR INTENT REMAINS THE SAME ON CARBON TERRAVOLT 1. WE ARE TARGETING YEAR END 2022 FOR SELECTION OF THE FIRST 1 MILLION TON PER ANIM EMITTER CONTRACT. ADDITIONALLY ON CPV 1, WE HAVE SUBMITTED PROJECT PERMITS WHICH INCLUDE THE CURRENT COUNTY CONDITIONAL USE PERMIT, A CURRENT COUNTY ENVIRONMENTAL IMPACT an EPA monitoring, reporting, and verification plan. And we are working to submit an LCFS application for CTD1 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. Second, 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, projects, technologically advanced projects can create additional energy transition jobs in our state while also offering Californians 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 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 terrible 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 one and two, but also offsetting scope three 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 plus reserves at our Elk Hill field utilizing CO2 recovery, meaning 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 cow capture project at CRC's 550 megawatt Elk Hills power plant. As a reminder, 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 for 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. Additionally, 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 six 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 CTU1 and is compliant with LCFS requirements and eligible for 45Q credits. Said simply, 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, and produce 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, and 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 And 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 EMP and carbon management teams continue to deliver strong results Thank you for being here today. And with that, I'll 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 expectation, given the planned CGP-1 maintenance and lost sales 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 unit tax. This demonstrates CRC's significant cash generation capability and potential for sustainable shareholder returns. In fact, After investing in our four 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 17 cents per share dividend. Given the confidence in our assets and commodity backdrop, we're expanding our SRP by 300 million through the second quarter of 2023 for a total program of 650 million. We're also declaring a 17 cent per share dividend for the second quarter. Commodity realizations remain 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 continue to be a headwind, resulting in a quarterly 181 million cash loss. Moving forward and taking into consideration the additional flexibility within the revised RVL 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 EMP assets, growing carbon management business, and shareholder return initiatives. With respect to the new RVL amendment, Post quarter end, CRC successfully amended the RVL credit agreement for two key items subject to a one and a half times or lower leverage test. First, CRC will no longer have minimum or rolling hedging requirements. The second item allows us for a limited restricted payments basket, providing additional flexibility for share repurchases or other shareholder returns and investments in our carbon management system. As we turn to the cost side of the business, on slide nine, we saw total quarterly operating costs rise by nearly $2 per VOE, quarter over quarter, mainly as a result of lost production from CGP-1. In addition, increases to natural gas prices drove energy-related operating costs 22% higher on a per VOE basis from the previous quarter. Per unit non-energy operating costs were mostly in line with expectations. accounting for the CGP-1 plan turnaround. As a result, we expect our per barrel non-energy operating costs 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 P&C and capital workovers and approximately $50 million for CGP-1 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 Long Beach. This rig is expected to bring an additional 1500 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 one 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 perform above our expectations. I'd like to remind you that the PV10 of approved reserves at 2021 SEC prices was $6.2 billion, which grows to $8 billion at $80 brands, and it's 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 brings forward value to our PDP which already represents approximately 80% of the company, 84% of the company's value. We continue to see significant portfolio optionality in our low-decline assets with a large number of drilling locations and 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 activity. 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, all from 305 of cash at the end of 2021, and improve our already strong net leverage ratio of less than half a turn. Moving to our 2022 corporate guidance on slide 15, and given the rise in longer-term outlook for commodity prices, we're adjusting our 2022 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 four-year operating cost guidance by 40 million, primarily due to higher natural gas prices, which are driving our energy costs are driving up our energy costs and the cost of gas where our steam flows. As a reminder, this increases a net benefit to CRC as we see we are net long natural gas. We are racing our 2022 EMP capital program by 25 million due to the addition of the warming fuel rate. 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 to $40 million in cash for the year. As a result, we are raising our corporate pre-cash flow and adjusted EBITDA 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 and $480 million of free cash flow from the EMP business. To conclude, CRC has a great start to the year, operating safely and prioritizing high return projects. From an exit to exit rate, We plan to maintain production this year while only spending approximately $275 million of BNC and work over capital. We're excited to continue to develop our low carbon intensity assets and with the addition of a fifth grade. 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 on our 2022 guidance and the attachment to our earnings release. Thank you. And I'm not trying to 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'll now open the line for questions. Operator?
spk05: We will now begin the question and answer session. To ask a question, you may press star then 1 on your telephone keypad. If you're using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press Start in 2. At this time, we'll pause momentarily to assemble our roster. Our first question will come from Scott Hanold with RBC Capital. You may now go ahead.
spk03: Yeah, thanks, all. You know, my first question, you know, on this CalCapture, you know, revisiting it now with NCS, can you give us a little bit of background? You know, obviously, you had the DOE study. You all got it 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 it at a capture at a 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?
spk06: Yeah, sure. First, hi, Scott. How are you? Good. We have interacted with MTS 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 Kern, who's leading the effort here, but our chief operating officer. As we went through the feed study and came to conclusion with the DOE feed study, we are also in the background working other carbon management activities. some of which with next decade, you know, thinking about how to use capture equipment. And we came to the realization that over time, things start to optimize as we proceed through. And so that's why we're embarking on this new speed study with NCS. I'm going to turn it over to Sean to talk about some of the benefits. Yeah, thanks, Pat. This is Sean. Hey, yeah, you know, as Mac mentioned, you know, we were advancing our work on the feed study, uh, with the DOE originally, and in parallel with that, we continue to engage with other technology parties that were, you know, bringing us different solutions to capture the carbon at all skills. Um, as you know, a lot of this technology has been around. It just hasn't been applied at this scale. And 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. They've 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 reservoirs, and so we're excited to be advancing this project.
spk03: Great. And then my follow-up question is, you know, I'm going to stick on, you know, obviously the carbon management side of things. But, you know, I guess, you know, recently the LCFS credits have been, you know, a little bit weaker. Can you, you know, 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, you know, how does, you know, that impact the economics of of some of these projects you're looking at with where those credits have gone here recently?
spk06: Yeah, Scott. So, you know, 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 the type curve, they were already pulled down a bit. You know, when we think about it, we think about the total opportunity set being LCFS at a price as well as 45Q 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. Morning, Scott. Yeah, as Matt points out, none of our projects have been examined or evaluated using a spot-sized LCFS. They've been handicapped to various outcomes. California to achieve its carbon neutral objectives and timeline they want to, specifically involving electrification, you're going to need to see some modification to this program as it moves forward. Today's program may look different. Scott, in the longer term, I think as Jay says, we remain fairly bullish on the implementation to get to the net in California by 2045. And if you believe that that's the principal push that's going to change regulations, change markets, change the LCFS, add things to the LCFS program, you know, we remain, you know, 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 with some of these captures, you know, some of these places that we're trying to capture. carbon from, and so that would eventually, if you get to zero, you'll have to drive prices higher.
spk03: Okay, and as part of that question, do you all have a sense of what's caused some of the recent pricing pressure?
spk06: Everybody has their theory in particular and points to their culprit, but the most widely circulated culprit has been the movement of ethanol to California and outside the state.
spk03: Got it. Thank you.
spk05: Our next question will come from Leo Mariana with KeyBank. You may now go ahead.
spk02: Hey, guys. 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 you all did talk about like a 1,500 barrel a day impact to the exit rate.
spk06: Yeah, Leo. This is Sean. 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. Okay.
spk02: I also wanted to ask about cash taxes. Y'all didn't really book anything in the first quarter from what I can see in the financials. Y'all think you're going to start having to pay some cash taxes here, just given where prices are in 2022?
spk06: Hey, Leo, this is Francisco. Yes, we do see us paying 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 large change here in California that released our ability to be able to use some NOLs. So the guide is nowhere, but we do see ourselves paying some cash taxes this year.
spk02: Okay. I mean, is that going to be kind of, limited? Do you think you ramp up to be more of a full payer next year? Can you just give us any high-level sense if we continue to see high commodity prices?
spk06: Yeah, I mean, it really depends where the prices go, but I would say we're using NOLs and those are not endless. So, you know, you would expect if prices continue where they are, that the tax bill goes back to more of our statutory tax rate, which we're much lower right now. So, I mean, it just really depends. But what I would see was closer to that full tax payment in the coming years if prices stay where they are.
spk02: Okay. And then just a question on LOE. I saw you all raise 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 four, 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 have 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?
spk06: Let Francisco give you the specifics. The easy answer is it's just the denominator, right? It's the number of barrels produced in the quarter was impacted by CGP1. And so therefore, it drives the dollar per BLE up. And I think that if you make that adjustment, as we've shown in a couple of these dates, you'll get back to more of a normalized run rate. And then you can take a look at the full year guidance. I don't think we've reflected the four times the first quarter. Yeah, that's right. I mean, there's some seasonality in cost, but as Mac is saying, it's really, you know, 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 gets normalized back to where we were before the maintenance.
spk02: Okay. And then just lastly on the hedging, um, just want to get a, make sure I understand the messaging here. Uh, are y'all signaling it's gonna be more limited hedging going forward and maybe just using more, you know, floors or collars and, and trying to give y'all itself some upside here. Can you just give me a little color around the hedging?
spk06: Yeah, Leo. So page 23, uh, and the presentation provides an overview by quarter of the forward look on, on 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 that at the levels that were 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 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 and what we call strategic hedges, which is the third bucket there, I'm going to let Jay answer that. Yeah, let me give you a little more color in the background. That kind of talks at the higher level, but at the time of emergence, there was a covenant that required the company to hedge 75% of its crude production for two years and 50% for the third year. That was done in a $40 to $45 price environment, and 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. In addition to that, again, referencing back to the $40 to $45 price environment, we've moved the hedge floor prices up that were originally contracted significantly from the $40 range to the $60 plus range. Those transactions were captured in the second month. The third line is reflective of a fairly limited number of transactions that landed since then. I would point out that Frankly, additional hedges, in any material regard, have not been added since fall of 21. You add these together, that's when you come up with the total of the hedge mark. Going forward, as mentioned by Francisco in that question too, 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 the tools we use. Again, you're going to find we're going to be focused on the hedging program on maintaining pre-tax cash flows. I mean, we've got downhole activity, we've got debt service, we've got the carbon business, and we've got return to shareholders. And that's what's going to guide our hedging going forward. I would just add, Leo, I think your question was, where do you see hedges going? you know, 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 were put in for the RBL. That obviously provides an uptick to our cash flow and feedback. 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 change in the market, and we may change that, but we're comfortable now.
spk05: Our next question will come from Doug Legate with Bank of America. You may now go ahead.
spk06: Thanks, Charlie. Good morning, guys. Thanks for taking my question. Mike, one of the ways to amplify your leverage to the commodity is to lean into a little bit more activity, and you've done that by adding a rig back at Wilmington with this quarter. I'm just curious how you're thinking about the goal 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 inherited as CEO versus the outlook you have today, how do you think about whether you may want to get a bit more aggressive in trying to recover some of the production loss over the last five years? Good morning, Doug. Thanks. Look, in the fourth quarter, or late last year, we bought on a fourth rig. Now we've bought on a fifth rig. We continue to think about how we deploy our capital across the portfolio. That portfolio being shareholder returns, through the drill bit, we're in the carbon management business. And we want to be very prudent about where we are. Now, you're right. With the commodity backdrop, we continue to explore. That's why we're bringing on this fifth rig. We are evaluating, we're constantly evaluating, should we bring on another rig, given the market conditions, or should the market conditions change and 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 six-rig if we choose that the market is receptive to that as part of our portfolio management. Maybe you want to expand on how we think about cash and deploying it through the drill bit, for instance. Hey, Don. This is Francisco. So, yeah, first of all, I think, you know, we have most of our, as you know, most of our fields are operated by CRC. We have high NRI, so it gives a lot of control with the movement on adding more rigs. And we do have a big inventory of projects. The one, I guess, pleasant surprise has been the move in natural gas prices. It's putting gas year projects into the mix. as we look at the portfolio options. And, you know, we were able to, given the prices right now, we're able to basically check the box, deliver on shareholder returns, be able to continue funding our carbon management business. And then we said we would evaluate and stay flexible where the next dollar was going. 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're doing 10 wells there. We will continue looking. We have quite a bit more inventory that's ready to go this year, and we'll just have to make that decision on what the next dollar goes to. Well, guys, I appreciate the answer. You've kind of taken the words out of my mouth for my second question, which is, the relative capital allocation between oil and gas i'm going to save my my carbon questions throughout esg event next week so thank you for that but 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 um more aggressive development of your of the gas assets in your portfolio so i'm that's kind of really what i wanted to go here because you're not hedged on gas um and my understanding is it's the the permitting backlog is quite rich on the gas opportunity relative to the oil opportunity so i'm just wondering if you can maybe flesh that out just a little bit more at francisco if you don't mind in terms of um you know what that what that could look like is there a significant gas opportunity currently within that crc You know, Doug, you must be reading our minds at some point because it's a very recent conversation we've 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 months, we've looked at it. We're not committing or saying we're going to do anything, but it is definitely a topic that's at the top of our minds. In fact, Francisco, Sean, and I were just talking about what that opportunity might look like. So nothing to say here, but it's almost like you're inside our heads, Doug. Yeah, Doug, just it's the ratio of oil versus gas. Given where gas is right now, it really comes into play. And we're already the largest natural gas producer in the state. It's not just the Sac Basin, but we also can build more gas in Elk Hills and ED. So 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 that's why gas flows are becoming much more competitive. That's terrific. Thanks very much indeed. I look forward to seeing you next week. Thank you. Thanks, Don.
spk05: Our next question will come from Scott Hanold with RBC Capital. You may now go ahead.
spk03: Hey, thanks. One follow up here and just, you know, looking at the buybacks and the pace of what you all are doing, obviously, you made a pretty big step up in it and extended the window a little bit. But, you know, can you remind us if, you know, how you go about that? Is it very opportunistic? Do you have a 10B5 plan in place? And also, have you considered, you know, looking at privately negotiated kind of transactions to suck up some liquidity from the non-traditional holders?
spk06: Hey, Scott. Yes, so open market 10B5 has been historically how we've been doing the program. We find that as a really good way to participate in the market and buy back our shares. We do have capacity to look at other forms of buybacks going forward, but for now, I mean, we're staying flexible and just seeing where the market's going.
spk03: Thank you.
spk05: Our next question will come from Eric Seave with GoldenTree. You may now go ahead.
spk04: Hey, good morning, guys. Thanks for the call. Great to see you guys increasing activity levels. Just wanted to see if you could provide a little 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 seemed 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 1.5 thousand barrels of oil per day higher by virtue of the expanded drilling program.
spk06: Yeah. Hey, Eric, how are you? Good to hear from you. The simple answer here is that it's that darn PSC. You know, as we came into the year, we were more in the 80s, low 80s, and now we're in the mid-90s, and because of that, we lose barrels on net production. We have offset more than, you know, people we offset those with this new 1.5 or 1,500 a day on exit. But, Mr. Francis, do you need to add to that? No, I mean, so, you know, we had talked about offsetting the barrels that we sold on the last hill sale and that price has stayed the same flat to where we were at the last time we had our earnings. That would have indicated we had some growth. We've seen an increase in oil prices so that, you know, if you remember for every $1 change in brand prices, we lose 100 barrels due to the PSA effect, and it goes the other way as well. So, you know, we've seen $15, $20 move in oil prices, so we lose the net production that way. So the activity with the fifth rig should help offset that. Yeah, and it's one of these ironic things, Eric, where losing the barrel through the PFC because prices are going up, we'll take the prices going up.
spk04: Yeah, it seems like a good problem. Just as we think about the production progression moving from sort of Q1 to the rest of the year, 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 looked like when you adjust for the processing plant being down, it looked 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?
spk06: I think you're right on the MGLs and the gas. And if you think about, we had this rate in the second half, as Sean said, you'll see that creep up towards the exit rate, obviously. And so that's going to creep up in the second half of the year because that's replacing the PFC effect. So the PFC effect's down for the full year because of the prices on the front end are 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. Okay. Okay. Those are very degrees of difference, though, Eric. It's not big swings in our production.
spk04: Right. I appreciate that. Great. Well, thanks for that commentary. Thanks for the call 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're 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 I look forward to seeing what you guys can do in the second half.
spk06: Thanks, Eric.
spk05: Again, if you have a question, please press star then 1. Our next question will come from Ray Deacon. with Petro Lotus. You may now go ahead.
spk07: Yeah. Hey, Mac. Good morning. I had a couple of questions on the CO2 sequestration side. 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? That's what I'm asking.
spk06: Yeah, I'm going to let Chris Gould, our Chief Sustainability Officer, tackle that question. Yeah, hey, good morning. I'm curious to the EPA website for the Class 6 permit. Is that correct? Exactly right. I just checked it. Understood. Yeah, I mean, I think what you see on that website are permits that are being 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, you know, hopefully you get the permit. In terms of identification of equipment, I think is what your question was, certainly today... 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 the standard we hold ourselves to.
spk07: Okay. Got it. about to file another permit, you'll be, if I'm 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?
spk06: Yeah, so we've received on our first permits for carbon tariff all one. We have a schedule, we understand, with the U.K. of 18 to 24 months. Carbon-Terra-Vault-1 reservoirs are world-class high standard for CO2 geological sequestration, and our permit filing was obviously on the website. It's administratively complete, and again, we believe technically complete. comments from the EPA on the first reservoir that we submitted, A1-A2, back in August of last year, and we're in the process of responding as well as the second reservoir in that application as well. We're very pleased with the constructive dialogue and the feedback that we're receiving from the EPA and confident in the timelines that we've outlined.
spk07: Yeah, that's great. Yeah, 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?
spk06: Yeah, Ray, it's Mac. Page 17 of our deck has sort of a Gantt chart that outlines this with respect to CTV1. And our view is that we need to get the permit in order to underwrite and go to 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're looking to do is line up emitters, line up 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 talk. And so that's why, you know, we continue to advance the emitter discussions. And as Chris said, he and his team have done a nice job in having a constructive dialogue with the EPA on advancing new permits, and we think we can do that on the first carbon-terrable one by the end of next year. Hope that answers the question.
spk07: It does. Thanks very much. Thanks, Ray.
spk05: This concludes our question and answer session. I would like to turn this conference back over to Matt McFarland for any closing remarks.
spk06: Yeah, thank you. And thanks for everyone who joined our call today. Appreciate your interest in CRC. We continue to believe we're very well positioned as a low fuel, low carbon intensity fuel for today and a net zero fuel Have a good day. Thank you.
spk05: The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.
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