California Resources Corporation (NYSE:CRC) Q1 2023 Earnings Call Transcript

California Resources Corporation (NYSE:CRC) Q1 2023 Earnings Call Transcript May 2, 2023

Operator: Hello! And welcome to the California Resources Corporation First Quarter Earnings Call. All participants will be in listen-only mode. . Please note, today’s event is being recorded. I’d now like to turn the conference over to your host today Joanna Park, Vice President of Investor Relations and Treasurer. Please go ahead ma’am.

Joanna Park: Welcome to California Resources Corporation’s first quarter 2023 conference call. Participating on today’s call are Francisco Leon, President and Chief Executive Officer as well as the entire 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 our first quarter results. 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, we are making some forward-looking statements based on current expectations. Actual results could differ due to factors described in our earnings release and in our periodic SEC filings.

As a reminder, we have allotted additional time for Q&A at the end of our prepared remarks. We ask our participants to limit their questions to a primary and one follow-up. With that, I’ll now turn the call over to Francisco.

Francisco Leon: Thank you, Joanna. Good morning everyone and thank you for joining us. I’m very pleased to be here talking to you today as CEO of CRC, as we continue to build a different kind of energy company, focused on generating the highest cash flow from our low carbon intensity assets and advancing our carbon management business. My remarks today will focus on three key areas: First, our record financial performance in the quarter, which was driven by a strong operational execution and leading natural gas position. Second, the progress we made advancing our plans to reposition the business to unlock shareholder value. And finally, the growing strength of our carbon management business as we continue to take steps to enable California’s clean energy goals.

Turning to our quarterly results, we’re off to a great start for the year. Record financial results showcased the quality of our low decline assets and the benefit of a diverse hydrocarbon E&P portfolio. We successfully maintained flat oil production quarter-over-quarter on 31 million of drilling and completions and work over capital. We drilled nine wells and two sidetracks and ended the quarter with one drilling rig at Wilmington and 39 maintenance rigs. Our reservoirs offer stack pace, which means we can recomplete and sidetrack existing wells to add pay at attractive returns. This type of activity is highly economic and allows us to bring on production at a fraction of the cost of the new well. For the balance of the year, we intend to increase our work over activity and execute a one rig drilling program.

We have secured all the necessary drilling permits for our 2023 capital program and are working to build incremental permit inventory for next year. Another highlight for the first quarter was the California commodity markets. Because the state operates as an energy island, California realizations reflect the demand for energy and tend to be higher than national benchmarks. Both NGLs and natural gas realizations were above expectations and crude realizations were within guidance. To be more specific, NGL and natural gas realizations benefited from colder than normal weather and the lack of in-state production. In the case of natural gas, our realizations for Q1 were approximately 630% of NYMEX. As a reminder, California imports approximately 90% of the natural gas consumed in the state.

When demand exceeds local production plus incoming supply, the market relies upon natural gas in storage to make up the difference. In the case of January and to some degree February, California found itself with limited natural gas inventories and storage and limited local supply of production. As the state’s largest natural gas producer, our roughly 12 Bcf of production was available to meet the needs of the state. These factors helped drive record results and facilitated another quarter of shareholder returns. The company generated pre-tax free cash flow of $263 million, of which approximately $79 million was returned to shareholders. This consisted of $20 million in dividends and $59 million in share repurchases. Since implementation of our share repurchase program in May of 2021, we have bought back approximately 15% of the company’s outstanding shares.

Combined with our fixed dividends of $1.13 per share, we have returned back to shareholders approximately 22% of our current market cap in less than two years. We intend to continue with our active shareholder program and have $567 million remaining under the total, board approved $1.1 million authorization. We also ended the quarter with robust liquidity of $931 million, including $477 million of cash-on-hand. CRC’s committed to maintaining a very strong financial foundation, and we will continue our focus on achieving greater financial flexibility and commitment to shareholder returns. As we look to the balance of the year, we have increased our 2023 after-tax free cash flow guidance by 8% to $415 million at the midpoint of our range to reflect our strong first quarter ‘23 performance.

This is partially offset by lower commodity pricing assumptions for the rest of the year, timing of capital, changes to working capital and higher cash taxes. We have provided detailed analysis about our quarterly financial and operational results on our 2023 guidance in the attachments to our earnings release and in our slide deck. Turning to our continued strategic realignment of the company’s operations and structure, we announced yesterday the appointment of Nelly Molina, as CRC’s new CFO effective May 8. I could not be more excited to welcome Nelly to CRC. She is a seasoned energy executive with more than 25 years of corporate finance, capital markets and project financing experience and breaks an extensive background in the development of energy infrastructure projects in the natural gas and power sectors.

Nelly joins us from Sempra Energy, where she most recently served as Vice President of Audit Services and Vice President of Investor Relations. I look forward to introducing her to you in the weeks and months ahead and I know we will benefit greatly from her expertise in navigating today’s evolving energy industry. In addition to the changes in leadership, we are also focused on pursuing operational excellence. As mentioned last quarter, we launched a cost reduction and business transformation initiative to align with our activity levels and build a more efficient organization. We are targeting annualized run rate cost reduction goal of $25 million to $50 million to be implemented by the end of this year. We have identified $20 million of reductions to-date and are working to expand the scope and scale of cost reduction efforts during Q2.

Another key element of our plan is to achieve increased financial flexibility. This quarter we have successfully reaffirmed our $1.2 billion borrowing base and amended our RBL facility to increase the duration and improve the terms. These changes will enable us to make additional investments in our carbon management business and further support our shareholder return program, as well as help pave the way for a potential separation of the carbon management business. We will continue to evaluate ways to increase our financial flexibility as the year progresses. As we discussed last quarter, we are evaluating the separation of our carbon management business, Carbon TerraVault, as part of our ongoing efforts to optimize the value of our portfolio.

Outgoing CRC, CEO Mac McFarland is serving as the Chair of the Board of Carbon TerraVault and we have been working closely together to determine the best path forward. The carbon management business is still in the early stages and there are important milestones that we are working to reach before initiating a potential separation, such as an EPA Class VI Permit Approval, Project FID, Line of Sight to First CO2 Injection and first cash flow among others. We are continuing to build out the leading carbon storage business in California. In the first quarter we have made further progress by signing two new Greenfield Storage Only CDMAs, a Green Hydrogen Project in the Sacramento basin, and a Renewable DME project at our Elk Hills net zero Industrial Park.

These projects target 140,000 metric tons of CO2 injection per annum on a combined basis. We now have four CDMAs in place for a combined injection rate of 610,000 metric tons per year, representing reservations of about 12% of our pore space. Further, we submitted Class VI permit applications for a new development area, which we call CTV IV, for an additional 34 million metric tons, bringing CTV’s total potential permitted storage to 174 million metric tons or over 85% of our stated 2027 target of 200 million metric tons. The CTV team continues to file permits for additional vaults across California to expand our leading position in the state. We are targeting receiving our first Class VI draft permit from the EPA for CTV I by the end of the year.

In summary, we’re excited about our continued progress in executing our strategic repositioning. In the first quarter of 2023, we had record financial performance, which allowed us to increase our full-year guidance. We also advanced our cost-cutting initiatives and continue to reposition our business to unlock additional shareholder value. And finally, we further expanded our California leading carbon management strategy to support California’s clean energy goals. Thank you for joining us on the call today. We’ll now open the line for questions. Operator?

Q&A Session

Operator: Yes, thank you. . And the first question comes from Scott Hanold with RBC Capital Markets.

Scott Hanold : Thanks. Good morning or good afternoon all. And my first question, it may feel like a little bit of multifaceted one, but let me try here. You’ve made progress on obviously starting up the new CDMAs and how do you – and more of those, I guess recently were some of the lower capital intense in your agreements. And how do you think about the mix of these projects going forward? Do you want to see some more of the kind of the front end projects to increase the scale of EBITDA or do you feel confident. I know you said you’re only about 12% on total reservations right now, but do you feel confident in the larger quantum of getting that storage permitted, so that scarcity factor isn’t really as much of a concern. So I know it’s kind of a bit of a multifaceted question, but ultimately I’m just trying to think about the higher relative EBITDA opportunity and if a potential offset would be exercising some of the equity stake options?

Francisco Leon: Hey Scott, yeah we’re focused on both. So greenfield, four CDMAs on greenfield is really good progress, no question about that, and you had the tailwinds from the IRA increase in the incentives, so definitely that’s helped put projects together. It also helps that we can co-locate these greenfield projects at Elk Hills in the Sacramento area. So it just – it’s an easier process to get to a CDMA. Existing point sources, we talked about it before, but they are still going to price discovery right. Where are the credits here across the value chain and you also have to solve forward transportation, how do you move this yield to across the state. We know there’s a lot of interest in Sacramento ensuring that CCS is successful.

Everyone understands that transportation is part of the equation, and we’re hoping there’s some uncertainty right now. We’re hoping that uncertainty is clarified in the near term. But I’m confident we’re going to be delivering both projects, certainly the going to point source, the ability to deploy more capital, but also increase the EBITDA is something that we’re focused on with our partners in Brookfield. So we’ll do a little bit of both. I think if you looked at the types of projects that we see in the Q, are the types of projects that we’re reviewing. You see a pretty good mix between them. It just so happens as we’re kind of building, kind of this new business live in front of everybody that the first four projects are the greenfield, but that’s not – this business is not going to be exclusively for Greenfield.

We’ll bring some points for projects into the fold hopefully in the near term.

Scott Hanold : Yeah, and how about the exercising and the equity options on those?

Francisco Leon: Yeah, we’re so – we preserved the option to invest into the equity of all four projects and started with Grannus and Lone Cypress that have been in the works for longer. We’re reviewing not only the cost profile of those businesses, but the market in a lot of cases by hydrogen. That is not a very well developed market quite yet, but there’s a lot of interest. And that also requires understanding the off take contracts and in the depth of the market, in what do they best best place the hydrogen and the ammonia. Ammonia is already tied to a co-op in Sacramento. So we’re evaluating both. We like to have a decision this year on Lone Cypress in particular. That’s going to be the first project we’re reviewing the equity.

There’s a lot to do, but we’re excited. We think these markets will develop nicely in California. There’s a lot of support again by IRA, hydrogen has 45V that supports it, but we’re seeing a lot of potential demand for the product. So at both Brookfield and CRC, we have retained that ability to invest in the equity and it’s something that gets us very excited about participating in this new energy verticals.

Scott Hanold : No, I appreciate them and this sounds like you’re putting a lot of depth in the thought of around this. My follow-up question is on those cost savings you talked about, and can you give us a little bit of color on – I think you said 20 million, there’s kind of a line of sight on it right now. But what kind of specific cost savings are you really seeing and what are you targeting. And I’m kind of curious with using I guess that A&M service. What specifically was the reason of going like outside to have somebody come in and do that versus doing stuff like CRC. What can you do on your own, that they can come in and help you with?

Francisco Leon: Yeah Scott, so we were looking for ways to change how we work. CRC does a lot of things really well. It’s a company that has been operated under the strictest regulations pretty much in the U.S. So there’s a lot of – there’s the team that works well. We are – all have very high operating standards, but we need to change how we work. We need to bring cost in line with activity levels. So that requires a kind of a business transformation, not just a cost-cutting exercise. So we need to question everything. We need to question, how we’re organized, we need to question where we prioritize and ultimately look for to make decisions to take some costs out of the system. You know, the team got to work right away after we came last quarter and described this initiative.

And $20 million in a couple months, it’s a pretty good, good win. And again, we’re trying not to, this is not a deferral, this is not removing one-time cost. These are run rate savings, these are permanent savings that we want to take out of the system. So we’re evaluating contractors, we’re evaluating contracts, chemical contracts for example. How do we use different – how do we ultimately make decisions across the board? And we’re questioning everything, right? It’s a good opportunity for a refresh. It’s a good opportunity to say, ‘okay, can do we do better and drive that culture going forward?’ We brought A&M; one, they are a very good team; two, we want to get that external perspective. California tends to be isolated from what’s happening in the rest of the U.S. We want to bring best practices, and we want their help assessing and ultimately accelerating some of these cost-saving efforts.

We’ve taken a lot of cost out of the system historically at CRC. So the next phase is really one that requires kind of a transformation of how we work, and we felt it was best done with some outside help. So I’m very focused on these cost-reduction exercises, and we’re getting a lot of great organic support from the team, presenting new ideas on how do we make this company better.

Scott Hanold : Got it. I appreciate it. Thank you.

Francisco Leon: Thank you.

Operator: Thank you. And the next question comes from Doug Leggate with Bank of America.

Kalei Akamine : Hey, good morning. This is actually Kalei on for – well, for myself. Francisco, following your announcement last quarter regarding a potential separation of CCUS from E&P, we received a lot of its imbalance on the power plant; what’s the valuation, what’s the G&A burden, what does the power market look like? So could you comment on whether it’s core to your oil and gas business or whether it’s a better fit for a standalone CCUS business, noting that there are potential synergies with gas capture. And maybe to add on here, I remember a few years ago, you guys did that deal with . Therefore, if you did something with the power plant here, it wouldn’t be the first time, but even in that deal, there was an option to buy it back after a period of time. So that suggests to me that there may be some constraints in how you think about structuring it.

Francisco Leon: Hey Kalei, so yeah, I mean I think we have a big advantage in the state by owning a power plant at Elk Hills. It’s been truly a great asset for us and it really helps us stay away from the grid, at least for part of our fields, which helps us bring down costs alongside with it. So the plant delivers – about one-third of the power goes to the oil field and two-thirds gets sold to Cali so and utilities. So it’s been a good profitable asset for us historically. We have the opportunity to make it better, to be able with a capture system, be able to deliver net zero power in a state that’s really hungry for these types of offerings. So we’re evaluating where this asset fits best on a go-forward basis. I mean I think the prospect of having net zero is appealing to everybody, but you also have to be able to undertake or capture, which as we talked about in the past, it’s a capture system on a low concentration stream of CO2, which is going to be on the higher end of the cost spectrum, right?

So how do we make that investment? How do we finance that type of capital call and ultimately what does the asset, the long, is it more on CRC or is it more on Carbon TerraVault? These are the sort of things we’re working through. We did release the collateral from the banks to the RBL and we’re looking to have the flexibility, so that we can put that asset to work in the best way possible. Right now the way I see the power plant, even though it’s a great unique asset industry, the California E&P companies, we see that asset trading as an E&P multiple, right. So having an ability to see the financials, right, so the things – some of the things you’re asking, having the visibility to clearly showcase how good this plant is and how it can get better by making it a net zero power plant, I think it’s going to be a great value add and a way to unlock value.

So we’re working through it, nothing definitive. Hopefully, at least I gave you some of the groundwork here as we’re working through these types of assets and where do they best fit in case we do separate the businesses going forward.

Kalei Akamine : The quick follow-up there, and I hope you don’t count this as my second question, but there was a feed study that was performed about two years ago. And for whatever reason, you guys are performing a second feed study. Can you give us an update on what the status is on that feed study that you’re currently performing?

Francisco Leon: We’ll see if it’s your second question or not, depending on what the next one looks like. No, I’d say it’s a great question Kalei. So we did a feed study with Fluor a few years ago, and now we’re doing a second feed study with NextDecade. You have to understand, the reason we have two feed studies, and we’re going to continue looking at the cost, is that there hasn’t been a capture system put into a natural gas power plant facility of this scale anywhere in the U.S. before. So we want to make sure that we have the cost right. I mean, the technology is really not a new technology. It’s not something that concerns or maybe the scale does, but it’s really trying to drive that cost down. We’ve had a lot of inflationary pressures over the last two years.

We want to make sure it’s the project that not only delivers that ability to reduce that CO2 emission footprint, but it’s also a profitable project. So what you’re going to continue seeing from us is really working to that cost profile. How do we best set up? How do we finance this power plant, so that we can make CalCapture happen? We’re targeting FID next year, right? So we’re working through it; we’re soliciting input. There’s a lot of companies that are bringing new ideas, bringing new technology and looking at the supply chain differently. And we’re going to look to award the project to whoever can deliver the best price and ultimately get us a project that we feel comfortable that can be executed on. So we’re working through it.

Kalei Akamine : I appreciate that. My real second question is on natural gas. So obviously, really big numbers this quarter. Hoping that you can help us understand how to model your exposure. Is it mid-week or is it spot? Is it city gate or is it SoCal border? I think any help here would be appreciated, because given the tightness in California, it seems like this could be reoccurring.

Francisco Leon: So I’ll start and then I’ll turn it over to Jay to give a more in-depth answer. So we do feel this is a California through the regulation and through the penetration of renewables that gas is going to be absolutely needed, not only in the near term, but as we go forward as baseload. So we were well positioned as the largest natural gas producer in the state and we see these spikes happening more and more. So definitely, it’s something that the state, that’s an energy island. It’s kind of decided that’s what we’re going to be. So these natural gas assets that we own through both power and owning the Sacramento Basin and Elk Hills and Buena Vista areas all have gas in the right places. It gives us a lot of flexibility when we see this market shocks to be able to reposition our assets and go out and try to deliver that gas for the state. But maybe Jay, if you can cover a little bit of the pricing around that.

Jay Bys : Yeah, let me kind of touch on the basic precept here. More times than not, we’re going to find ourselves looking to be close to, if not at, the first of the month index. We’d prefer not to carry a lot of gas into the daily market during any particular month. Now, in advance of that bid week cycle or during the bid week cycle, we may take some limited fixed price positions that just simply seem, frankly attractive given the circumstances that are taking place. Gas for the most part is produced relative to a SoCal border index, but as you may or may not be aware, we maintain long-haul transportation from the field on Kern River and we’ve got a fairly significant position on the SoCal gas system in terms of BTS, so. This is kind of where the semantics get a little bit goofy I’m afraid, that some people call this trading and we call it marketing and asset management.

And the fact is we keep a set of tools around that work very well together. We’ve got gas production, some of the liquid points in the state. We maintain that transportation as I mentioned. We’ve got some of the most dependable generating capacity in the state and we’ve got really the right folks around to make those decisions. So when the market needs power, we move more gas to the power plant; when the market needs gas, we’re able to bring more gas to the market. So in general I think you should probably look at any particular monthly cycle, look for the first of the month index, reflective of kind of a 80/20 SoCal border/PG&E City Gate index.

Kalei Akamine : I appreciate that response.

Francisco Leon: Thanks Kalei.

Operator: Thank you. And the next question comes from Leo Mariani with ROTH MKM.

Leo Mariani: Why don’t you just delve in a little bit more to a few of the numbers, you know sort of around the quarter. You’re looking at a CapEx, it was quite a bit sort of below guidance, and then just follow up on the gas price question. I guess what I looked at sort of SoCal border, City Gate, it didn’t really matter. I had a hard time getting to the 21.50 that you guys put up in the quarter. So maybe there’s kind of some other semantics around the pricing or some other local markets that are kind of less visible outside of these indices that get reported by data agencies like Bloomberg or sort of whatnot that drove that. But any more color on how to get to the 21.50 and then again, just CapEx nicely below the guide here, so any thoughts on that.

Jay Bys: Sure. As I mentioned kind of a couple of months ago, we did execute a few opportunistic fixed price trades during the mid-week cycle. But one thing that kind of gets lost and we’re trying to get a whole bunch of the weeds when it comes to natural gas pricing is, when you see an index posted, natural gas doesn’t necessarily trade in the physical market at that price. There are times of the year when it trades at a discount and there are times of the year when it will trade at a physical premium. So for example, to get physical gas at the SoCal border, you may end up paying more than the border price, you know buy physical gas in index plus number. So we had a fair number of index plus numbers transacted in our book for the months of January and frankly February, both are very strong.

A lot of different points in the western gas market. Physical gas was trading at significant premiums to the individual posted financial indexes. So combine the opportunistic trades, it’s the limited number we had and that small variation and I think we’ll get there pretty quickly. Again, I’m not sure Q1of ‘23 will be representative of what we see for the balance of the year. I think you’re going to find that our gas prices are probably large measures, excluding the fact that we’ve got a shortage of gas and inventory right now. I think you’re going to find that more reflective of the national gas price.

Leo Mariani: Okay, that was very helpful and it makes a lot of sense. And then just kind of sticking with some of the numbers on the quarter here, so we’re going to understand walking based in gas production. It was down around $10 million a day this quarter versus last. Historically that gas production has been pretty steady. It doesn’t really move around much, you know sort of by quarter. Was there any like maintenance or downtime, or is this more of you guys maybe directing more of that gas to the power market and kind of less to the volumes, you know sort of sold market here in the quarter. Just looking for any color on that.

Francisco Leon: Yeah, I know the gas Leo really was impacted by weather. That’s you know – you had facilities down because of the high winds and that affected our gas production in particular. So that’s really what happened in the quarter. We do have some maintenance projects throughout the year, but I think Q1, you can attribute most of that change to weather.

Leo Mariani: Okay, no, that’s helpful and then just on the regulatory front here, kind of any update on just the general permitting situation for only gasoline permits in California. I know the current county EIS is still a ways away in the decision, but apart from that can you maybe just talk to whether or not permits are kind of coming outside of those Kern County areas?

Francisco Leon: Yeah, so yeah, no update on the appeal around Kern County EIR, so that’s still ongoing. As we said before, we expect that to take some time, so. We are getting workover permits in Kern County and throughout the state, so those are flowing. We also filed a for three of our largest fields in Kern County to be able to do field level EIR. That gives us an alternative to be permitting back in the San Joaquin Basin in Kern County. We’re building inventory outside of Kern, looking at our gas wells in the Sacramento basin and continue to get, you know looking at the south and LA basin as well. As we said before, we have all the permits in the drilling campaign that we need for ’23. So really all we’re doing right now is creating as many options as possible for 2024. So working through those, but again no permits in Kern County yet, other than workover permits which are flowing.

Leo Mariani: Okay, but it sounds like generally speaking you guys are able to probably get permits outside of the Kern County EIS. That’s something you can still obtain here?

Francisco Leon: Yeah, I mean we were – like I said, we have all the permits that we need in Wilmington, so that’s in good shape. We do expect to get permits outside of Kern County.

Leo Mariani: Okay, thank you.

Operator: Thank you. And the next question comes from Nate Pendleton with Stifel.

Nate Pendleton: Good morning and congrats on a strong quarter. Regarding trucking CO2 at your Carbon TerraVault site that you alluded to earlier, can you provide any details around whether you’re exploring the use of low emissions trucking at other sites and are there any noteworthy costs or throughput implications that we should be thinking about?

Nate Pendleton: Great, thanks. And stepping back out a bit, over the past few months we’ve been tracking an increasing number of classics permit, both in California and across the country. At high level, can you speak to how Carbon TerraVault is differentiated in this growing industry and how you plan to capitalize on your first mover advantage going forward?

Nate Pendleton: Got it. Thanks for taking my questions.

Francisco Leon: Thanks Nate.

Operator: Thank you. And the next question comes from Noel Park with Tuohy Brothers Investment Research.

Francisco Leon: Hi!

Francisco Leon: Yeah, no, I mean I think we have a lot of conversations ongoing, and I think you’re only able to see the four that we brought forward in terms of CDMA. We’re evaluating multiples of what we brought in. As we talked about before, we feel we’re over-subscribed. So that means we’re talking to many more parties than we have capacity for. So there is a selection process right, so you know obviously we are dealing with people that have the credibility and that can bring these projects forward. Where we can get permits locally as well and that are serving a market need and in that these projects are ultimately going to have strong long term off-takes to be able to lock in returns and ultimately do incremental financing.

So there is a selection process, right, that’s why we moved. We’re not doing MOUs just for the sake of announcing that we’re making progress. We’re really focused on conditions precedent. We’re finalizing contracts that have a much more need to them, because we want to make sure we can – we are building this all these projects that need to be able to all to come together, so that we can get to our injection targets by 2025 and then 2027 and 2028 for the 5 million tons. So we are selecting right, we have this funnel and we are kind of high grading the projects that we think can get to the finish line and provide good returns for us and Brookfield, our partner. So, it’s hard to say what we are not considering without being specific. But I would say, what you see is a high graded list of projects that we feel very strongly that we can execute on.

Francisco Leon: Thanks Noel.

Operator: Thank you. And the next question comes from Eric Seeve with GoldenTree.

Eric Seeve: Hey guys, thank you for the call. Another follow-on question regarding the CO2 business. In terms of the projects in the queue, I know that you’re still talking to, you gave us some color earlier. It’s a mix of greenfield and brownfield, that was interesting. I’m curious in terms of the potential size of those projects. Is it in line with the size of the projects you’ve already announced and when I talk about size, I’m talking about 1 million tons of CO2 sequestered each year. Are the remaining projects are they similar size or are there some bigger chunkier ones out there. Any color on that would be appreciated.

Francisco Leon: Hey Eric! So remember, we’re dealing with a total addressable market of 400 million tons of emissions in California, right. So there’s definitely as you said, chunky mission sources out there. And naturally if you’re having to put investment on capture, if you’re having to connect points for us to sink and put pipelines in place, you’re going to have a scale naturally to those points for projects. Now, having said that, we look at all of these projects, we look at proximity toward tanks. We look at that counterparty and we look at the commercial aspects of the injection payment, right. So in order if we do, a full CCS as a service, . It’s hard to answer that question, but we are looking at multiple size projects throughout the state, but there are some big emitters that need solutions right there.

There are emitters out there that right now they are paying $30 per ton on carbon tax and that’s increasing every year. They are also probably going through, trying to replicate what we’re doing and finding out that sub-surface and permitting is probably not a core competency. So we’re having those dialogues, we’re educating, we’re trying to land the right deal on the right partner and expect some point source legacy emissions, hopefully in the near term. But we’re working through it, but again the size of the price is big. It’s just a matter of figuring out ‘okay, what’s the best place to store this year too and agreeing to terms.’

Eric Seeve: Great, thank you. And one follow-up. I mean it seems like Elk Hills is really well suited to get a lot of attractive projects here, but it sounds like you’re going to be well over subscribed. Are there – is there more potential storage space in that field that you guys are evaluating?

Francisco Leon: Yeah, for sure. I mean Elk Hills 47,000 acres, a simple property with a power plant with natural gas, with a lot of elements to bring new technology into the field. We’re looking for ways to add incremental pore space. I mean we’ve already extended expanded one of our permits in 26 hours. So yes, ultimately yes, as we draw more oil and gas we’re creating pore space, right, and at some point that pore space and the injection too maybe more valuable than we’re extracting. That’s not the case today, but it could be. So the key is having those tanks that we know, and understand really well, and as the market comes together and as we see the value of installing CO2, we will be looking for ways to create more pore space, at Elk Hills or even near proximity down there.

We do see a lot of running room in the Sacramento area. There’s a lot of near emissions near there and we are building a very, very nice portfolio of assets. So creating these two options I think gives us the most access to the market that we can see.

Eric Seeve: Terrific, thank you. And second question is with – as we model out the production, oil and gas production throughout the remainder of the year, just trying to understand is there any – other than potential impacts from adverse weather, are there any scheduled maintenance down that would impact the quarterly production cadence or should we just, can we sort of annualize the sort of rate we see progressing from Q1 to Q2.

Francisco Leon: Yeah, so we’re providing Q2 guidance. There is – one of our plants in Elk Hills was down for maintenance a couple of weeks ago, but that’s reflected in the guidance for Q2. What we said is, because we’re only going to do drilling activity with permits on hand, so effectively that’s one rig for the rest of the year. We see production declining between 5% to 7% for the year, entry to exit. So that number still looks good to us as we go here, so more – production held up very nicely in Q1. Then we started seeing a little bit of a decline in Q2 and that would be the case for the rest of the year. So it’s not going to be copy paste Q1. You should look at the guidance and the trend. We do see a 5% decline for the year.

Operator: Thank you. And this concludes both the question-and-answer session, as well as the conference itself. Thank you for taking today’s presentation. You may now disconnect your phone lines.