California Resources Corporation (NYSE:CRC) Q2 2024 Earnings Call Transcript

California Resources Corporation (NYSE:CRC) Q2 2024 Earnings Call Transcript August 7, 2024

Operator: Good day, and welcome to the California Resources Corporation Second Quarter 2024 Earnings Conference Call. All participants will be in a listen-only mode. [Operator Instructions] After today’s presentation, there will be an opportunity to ask question. [Operator Instructions] Please note this event is being recorded. At this time, I would now like to turn the conference over to Joanna Park, Vice President of Investor Relations and Treasurer. Please go ahead.

Joanna Park: Good morning and welcome to California Resources Corporation’s second quarter conference call. This is our first call, following the closing of our Aera merger and we are excited to share our progress. Prepared comments today will come from our CEO, Francisco Leon; and our CFO, Nelly Molina. Following their remarks, we will be available to take your questions. With us on the call, we also have other members of our senior leadership team. By now, I hope you have had a chance to review our earnings release and our supplemental slides. We have 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 will be making some forward-looking statements based on current expectations. Actual results may differ due to factors described in our earnings release and in our periodic SEC filings. Thank you for joining us today. I will now turn the call over to, Francisco.

Francisco Leon: Thanks, Joanna and welcome, everyone. We are incredibly excited about the road ahead and the value creation levers, we have for existing and future shareholders. CRC is a markedly stronger company today and we’re demonstrating what it means to be a different kind of energy company. Before discussing our second quarter financial and operating highlights, I want to spend a few minutes outlining the strength of our business strategy. We are committed to generating value for shareholders, and we do that by increasing our company’s cash flow per share, despite California permitting headwinds, our focus on improving margins combined with our strong and consistent share repurchase program resulted in mid-teens cash flow per share growth from 2021 to 2023.

With the closing of the Aera merger, we again are targeting to grow cash flow per share in 2024. Importantly, we achieved this full-year growth without sacrificing our balance sheet strength. As we integrate with Aera, we will deliver our synergy targets in the next 15 months as we head to an improved permitting backdrop by the second half of next year. Recent economic developments have provided a riskier outlook for the domestic and global economy, placing greater importance on sustainability of earnings. Our low-decline assets, strong hedge book and cash flow capability supported by a strong balance sheet provide us with a significant fortress in any volatile environment. The Aera transaction adds improved cash flow capacity and scale, and so let me take a few minutes to discuss the merits of the Aera deal.

We expanded our conventional energy business, improving the reliability of cash flows and enhanced our growing carbon management business to decarbonize California. We created operational scale and strengthen the durability of our business. Our daily production volumes doubled, California needs oil and we will be here to provide it. The Aera transaction also increased our average NRIs. And today our fields deliver 90% average net revenue interest. When you compare this to the Permian where average NRIs are less than 80% this is an advantage it boosts our profitability. We’re also capturing meaningful cost savings and see more synergies than originally forecasted. We now expect $235 million in total synergies, which reflects $60 million of savings achieved with the refinancing of various debt and $25 million of additional operational synergies.

We expect to capture these run rate savings over the next 15 months to improve our bottom line. Our cash flow forecast is expected to more than double from where it would have been on a stand-alone basis and has led us to increase our dividend per share today by 25% as we continued to consistently return more cash to shareholders. Lastly, CRC’s sustainability leader in California and we operate our business, the right way. Today, we have more direct control of in-field emissions and more capacity to accelerate the decarbonization of our portfolio in California’s emissions due to the advantage an unequal location of our assets. Over the last five weeks, since the closing of the merger, we have already made great strides. We are executing on our opportunities that will optimize our field operations, combining infrastructure and leveraging our combined scale to develop more cost-efficient supply chains.

As an example, our teams already connected our two largest fields in the San Joaquin Basin to improve and expand natural gas deliverability. The Interconnect allow CRC to take natural gas from our Elk Hills field to Belridge for use in Steam Flood operations. This connection will provide an additional outlet for Elk Hills’ gas during maintenance activities at our midstream infrastructure in Elk Hills and will benefit Belridge by lowering fuel cost for steam generation for EOR. Another early, win is the streamlining of well monitoring activity to the nearby Belridge control facility. There are made dedicated investments in this area and applied AI technology to improve well performance and uptime with fewer staff. We are adopting their best practices and optimizing nearby satellite fields to benefit from more efficient, well surveillance efforts across a broader base.

Similarly across the well service value chain, we are seeing early gains from vertical integration of services resulting in lower cost of our well maintenance and P&A activities. These examples highlight the strong industrial logic behind the merger. The proximity of our neighboring fields, position us to find the most synergies out of this powerful combination. And we’re just only getting started. On the carbon management front, we submitted another Vault for permitting to the EPA. For 102 million metric ton CO2 reservoir in Central California, this will be CTV IV. As a reminder, we now have over 300 million tonnes under permit review. Like the other reservoir, CTV VI is centrally located near major emission regions in California. In terms of execution, we’re targeting the receipt of California First Class VI EPA permit and the FID of our cryogenic Gas Plant CCS project by year end.

Our goal is to inject CO2 into CTV I before the end of 2025. From a Greenfield emissions perspective, CTV expanded our storage only CDMA with NLC Energy to 430,000 metric tons per annum of CO2 emissions. This project is slated for early 2028. We now have nearly three million metric tons per annum of CO2 projects under consideration throughout the state. You can find all the details in our CTV update release issued today. Now, I would like to move to another important opportunity for us. And that is to support the growth of data centers, to service California customers, while aligning with California net-zero ambitions in what we refer to, as the Carbon Valley Where Silicon Valley and the Central Valley Meet. CVS’ assets are uniquely positioned in the heart of a state that is home to of the top 10 data center markets in the U.S. Silicon Valley and Los Angeles.

We offer viable solutions for the demands of the tech industry today, and a solid runway to meet the needs of tomorrow. First we can provide data centers with the key ingredients they need to operate large plots of land, access to fiber networks, water, power infrastructure, natural gas and related interconnections. Our Elk Hills complex for example is in the sweet spot and can meet the data center needs and provide accelerated time to market benefits that other potential competitors simply cannot match. Our second advantage is that we can utilize our resources and energy expertise to support the development of carbon-free baseload power before the end of the decade. California has few instead dispatchable sources and we believe retrofitting combined-cycle natural gas with CCS is a solution that delivers both the market needs of low-emission and reliable power.

Alternatively, our 320 million metric tons of pore space throughout the state to support the decarbonization of over 2 gigawatts of new for alternative power to service co-locaters and big tech alike CTVs offerings align with the state’s ambitious carbon neutrality goals without exacerbating power shortages or pressuring power prices in California, which are already among the highest in the nation. With that I’ll hand it over to Nelly.

Nelly Molina: Thanks, Francisco. Our second quarter financial results were solid, extending our strong track record of performance. Free cash flow in the quarter reflected a strong oil sales, which were higher than we anticipated. Our earnings were in line with expectations and we continued to strengthen our capital structure, adding deeper liquidity with an expanded credit facility. All of this was done in combination with higher cash returns to shareholders. Let me summarize our results for the second quarter. Our business generated 139 million in adjusted $EBITDAX and deliver $63 million in free cash flow. Results were driven by consistent base production from our low decline assets with total volumes in line and oil production at the high end of expectations.

Second quarter production averaged 76,000 barrels of oil equivalent per day and oil averaged 47,000 barrels per day, above the midpoint of our quarterly oil guide. Our realized oil price in the quarter was $81.29 per barrel after hedges or 96% of Brent. We ran a one-rig program throughout the quarter. Costs and expenses were on average in line and reflect our recent efforts to enhance margin. One of the largest validation of synergies was demonstrated when we refinance all of their outstanding long-term debt at better rates. We issued $600 million of new unsecured notes with a coupon 625 basis points below Aera’s legacy second lien loan. These reduce the annual interest expense by about $60 million. During the quarter, we returned $57 million to shareholders including $35 million in share buybacks and $22 million in dividends or 90% of our quarterly free cash flow.

Year-to-date, we have returned $136 million to shareholders. As part of the merger, we also improved our liquidity position by increasing our borrowing base to $1.5 billion and elective commitments to $1.1 billion. At merger close, we use the available cash on hand to repay $990 million of Aera’s outstanding debt, transaction costs and financing fees, leaving CRC with roughly $1 billion of liquidity. Turning now to our guidance for the second half of 2024 and building on the $60 million of interest expense savings mentioned earlier. We now expect $235 million in total synergies. We anticipate approximately $30 million will be reflected in the second half of 2024 results and the rest in 2025 and beyond. As Francisco mentioned, Aera’s and CRC’s assets are interconnected and we believe there will be additional synergies that can be actioned in the near future.

Looking to the second half of 2024, we expect our cash flow and free cash flow to more than double, due to the increased scale, strength of our business and our ability to enhance margins through synergies and operational efficiencies. We also expect our 2024 adjusted EBITDAX to be around $1 billion as the business builds momentum into 2025. We will continue to have merger related costs which include transaction, integration and cost to achieve synergies but will be reflected in other operating expenses and which are non-recurrent in nature. I would like to remind you about our hedge book, no matter what prices may move for the balance of the year and through 2025, we have managed our hedge book to provide the revenues necessary to one, invest in both the core and CTD businesses, two, service our debt and three prioritize shareholder returns including dividends and share buybacks.

In terms of 2026, we have significant hedges in place for that year, which depending upon the size of our drilling program leave us in the same spot. The capital needs for our drilling program will ultimately be heavily influenced by some of other factors prevailing market price. We are committed to preserving a solid balance sheet and believe we have the financial flexibility to deliver on our strategic objectives. With that I’ll turn it back to Francisco.

Francisco Leon: We’re excited to execute our strategy across a platform that is now bigger and better. Our hedge book, durable cash flows and balance sheet flexibility provides business stability through market volatility. Moving forward, we will have three primary areas of focus. First, we will drive our business decisions to deliver cash flow per share growth and strong returns to shareholders while preserving a strong balance sheet. Second, we will continue to drive operational efficiencies and execute on $235 million of operational and financial synergies that will improve the business’ cost structure and finally, we will continue to expand our California leading carbon management platform through new CDMAs and permit applications to offer sustainable energy solutions to existing and developing industries to support California net-zero goals.

We truly are a different kind of energy company and look forward to unlocking the value of our expanded enterprise for the benefit of our shareholders and our fellow Californians. And with that we can now open the line for questions. Operator?

Q&A Session

Operator: Thank you. [Operator Instructions] Our first question today will come from Scott Hanold, RBC. Please go ahead.

Scott Hanold: Yeah. Thanks. Good morning. It looks like the CTB assets are squarely positioned for this carbon free data center AI demand opportunity. I know it’s early, but when you look at the economics of this how does that compare with some of the other prior on CTB. projects you’re evaluating? And also as you think about the different power solutions to utilize for these data centers? I know you talked about the combined-cycle kind of facilities but are there other options and does that impact the economics.

Francisco Leon: Hey, Scott. Yes. Thanks for the question. So yes, this is side. If you go to our slide deck today, we highlight the location of our reservoirs that we’ve been permitting now for over two years in the northern part of California. So this has been a long time build in execution from our team to get us to the right areas around the state where we can service all these potential emitters. So we’re excited about that. The location of these Northern reservoirs you can see it on the map. There’s been a lot of questions as we have got built our CTV strategy around where the emissions are going to come from. Anything that should clear that would part of getting the Bay Area San Francisco Sacramento where a lot of the existing hard to abate sectors of emissions are their show.

So we like we like the positioning there. We also are looking at these data center growth with a lot of interest. As these older power plants that have been in service for a long time are going to be critical to attracting and retaining data centers in California. Data centers need 24/7 baseload power. It’s a race to get to market first time to market is critical. So having existing infrastructure is absolutely going to be key. The nice thing is with CTV, we offer not only the time to market opportunity, but we have an ability to bring a decarbonized power generation into the fold that also meets the other criteria. As we move up north, and really the strength of our business there is in the pore space availability to sequester emissions, we will look for partnerships around these existing power plants.

There will be an opportunity to develop other technologies like fuel cells. Geothermal will also come into play. And those would be important depending on what data centers ultimately want to power their AI. I don’t foresee any changes to the tide curve. I would say very confident that we have the right pricing for storage-only projects. And what you’re seeing here is more the market development on both the emission side and also on the who’s going to consume that power for future growth. So no changes that I would say coming in our type card feel very good about our positioning and how we’re aligned to accommodate this incremental power that will come from data centers.

Scott Hanold : I appreciate that color. And then my next question is going to be on the oil and gas business. And as you kind of think forward into 2025 as the — you now have a combined asset base with Aera. Can you talk a little bit about — how do you see activity on the combined basis? Like where is it going to be focused on? And where are we at with getting oil and gas permits? I know you’re all running a dual path, but can you remind us and refresh us on where we’re at that gives you confidence in getting to more of a maintenance mode in 2H 2025?

Francisco Leon : Yes, for sure. So we’re confident in our one-rig inventory that we talked about before in terms of new wells. But these assets, really, it’s about workovers and sidetracks. That’s the bread and butter of our assets and Aera assets as well. And so we’re able to, with one-rig program running between the two assets, workovers on sidetracks, we should be able to deliver that mid single-digit decline even with no incremental permit. So, we feel good about the quality of the assets, the low decline, and the ability to work over all their wellbores and go to different zones for incremental production. So that’s the way ultimately this business runs. And now to get to a steady state of a stay flat, which is ultimately our objective, is to keep production flat and keep that stability in the cash flows.

We haven’t really changed the timeline. We still see the second half of 2025 as the point in time where we have that line of sight, a path to getting permits back again in California. So that hasn’t changed. We still are working towards that timeline, working multiple alternatives, as we talked about before, multiple alternatives, as we talked about before. But again, this company runs very well, as you saw with our results year-to-date, with only a 2% decline during the period. These assets run really well with just the blocking and tackling and doing surveillance and just focusing on the base production, right? That’s the great thing about the assets that we own.

Scott Hanold : Thank you.

Operator: And our next question will come from Kalei Akamine with Bank of America. Please go ahead.

Kalei Akamine : Hey, good morning, guys, Francisco, CRC team. I’ve got a follow-up there on the big thematic on data centers. I think there’s no question that there’s a bigger data center thematic out there, and guys on my side are obviously trying to figure out what that means for businesses like yours. Maybe at a base level, we can agree that it’s positive for the gas price. I guess where I’m a little bit less clear is what it means for volumes. So as you think about the potential outcomes of what data centers mean for your business, is there sort of a scenario that clearly drives volume growth in your business as a response to price?

Francisco Leon : So yes, as a reminder, we — CRC has about 80% of the natural gas production in state and the rest of it we import from other states. So are there scenarios of growth? Absolutely. You have to think if you look at the growth profile of data centers and then you go to — okay, well, these data centers are not going to rely on renewables and intermittent power. You need to come back to baseload. California doesn’t really have a lot of options. We’re down to one nuclear plant and hydro tends to be variable depending on the rain. So you look at this infrastructure that’s already in place with all these independent power producers which are natural gas power generation, which are in some cases not fully utilized today is the plan should be in California to maximize that utilization.

And if you can put the decarbonization plan that we have in place then you can really solve for multiple variables and that’s what has us really excited, right? The decarbonization which we’re very committed to do. But we also bring the reliability with this infrastructure and affordability by having local production. As we’ve highlighted before, we don’t feel like all barrels or all Mcf are created equal. Local production or you can certified through third parties, you had that your low methane emissions like we did with MIQ or that it’s responsively sourced across the board should matter to the consumer where their energy comes from. So if you start thinking about data center consumption needs, if you start looking at a path towards having preference to local production then you start really getting excited about our natural gas position and the ability to service a lot of these power plants.

So yes, I mean there’s definitely scenarios out. There are things that have to come and we’re a little bit in front of the market. But I like our assets and where we’re positioned we are from just a production standpoint and an infrastructure point as well.

Kalei Akamine: I guess when you think about it you see a lot of behind-the-meter sort of opportunities for your natural gas in your power?

Francisco Leon: Yes. Absolutely. I mean I think that’s something that we’re really focused on. There’s that we have this power plant at Elk Hills 550 megawatt and we added more power with the Aera transaction. So we’re above 800 megawatts combined. And right now if you look at the trading multiples of CRC, we trade at a discount to PDP and we have a critical asset that has a lot of value. We participate in a very attractive capacity program right now, but there’s no value recognition for this asset. So we’re going to work towards whether it’s data centers or other potential partners. We’re going to look to unlock that value of the power plant and you can do that through contract price and duration and we’re focused on that. And that’s where the data center opportunity kind of brings a growing and exciting industry into kind of the forefront of what we’re thinking.

So, there could be ways to unlock that value in their power plants. As you know, we use about one-third of the power for self-consumption that goes to the rest of it gets sold into the grid. So those behind-the-meter opportunities will be important to unlock over time.

Kalei Akamine: Got it. There’s a lot changing in the long-term for sure, very interesting setup. I guess my follow-up is on the near-term outlook for California gas. I think some of us were surprised to see. So Cal under Hub in the second quarter for that Permian seems to have returned. As we sort of head into 2025 that Permian looks a little bit more durable as you have Mexican LNG and perhaps siphoning some away some of that California imports away. But there is a lot of things happening in California renewables are growing. So as you sort of run your scenarios for 2025, how do you see the balances playing out?

Francisco Leon: Sounds great Kalei. So it’s a great question on gas. So I’ll turn it over to Jay here in a minute to cover the near-term impact. But yes, a reminder just more macro and longer term first, California short gas, we import a lot of the gas that we consume in state. As L&G projects get sanctioned in advanced, the gas will flow to great places where it can find better pricing. So that’s why it’s important to develop that local industry so that we can really provide that gas when the market needs it. But the dynamics in terms of the short-term, I’ll let Jay speak to that.

Jay Bys: Sorry about that with a little IT mishap here. Yeah, your notations correct Q2 both the border and the Citygate traded below or near the screen which is pretty unusual for the last couple of three years. The fact is gas is going to go where it’s most valuable, and gas was making its way to California and particularly from the Permian, where it’s alternative market price would have been something close to zero or negative. So like water, it’s going to flow to the most attractive points. Going forward, I think you’re already seeing what’s going to happen. You’re seeing a lot of this Permian gas gets stuck in the Rockies, for example, and unable to make it over to California today. So you’re seeing differentials in — differentials in price between California and, for example, the Rockies.

I think you’re going to see more and more of that next year. We — again, we produce roughly 15% of the natural gas we consume in the state over time. That’s not a good position to be in right now, it’s great to have low-cost gas coming from somewhere else. But over time, we need to dictate our own fate.

Kalei Akamine: Helpful. Thanks, guys.

Operator: And our next question will come from Betty Jiang with Barclays. Please go ahead.

Betty Jiang: Good morning. Thanks for taking my question. This is probably a data center question, but also related to CTV. So I want to ask about CalCapture project. It is a very meaningful project and it’s in-house. These post combustion projects are more capital intensive. So would love to understand the decision drivers around whether or not you will plan to move forward with that project? And how much of that is tied to signing a power purchase agreement with a buyer that are willing to pay up for low carbon power?

Francisco Leon: Hey, Betty, yeah, so CalCapture, which you see putting a capture system on our Elk Hills power plant. So we really like the ability to control our own destiny and emissions behind the meter. We were looking for to provide a solution for the state that’s going to require pipelines and that’s going to ultimately bring the scalability to CTV. But in the meantime and until we get more better framework to retrofit pipelines, having those emissions behind the meter and whether our power plant or steam generations is the way to bring forward the industry. So we feel good about the control points that we have. As you mentioned, this is a natural gas combined cycle plant, low concentration of CO2. So if you look at the cost curve, it’s going to be on the higher end on the sources that you can capture.

So value drivers that you need is ultimately, good definition around the cost of the capture, and we’ve done multiple FEED studies now. So we have a good handle of how that — how much is that going to cost. So you need to bring in the revenue drivers around incentives, and that’s a combination of federal and state incentives and also PPA from data centers or ultimately it doesn’t have to be data centers, right? At the end of the day, what we’re looking for is the right price point where the consumer of that power not only recognizes the advantage of the power already being there, but also the ability to unlock carbon-free power before the end of the decade. So I would say we’re kind of in that price discovery mode. We’re trying to understand the value that, that can bring in terms of all the different elements to our strategy.

And if we get — we solve for all the right variables, I think this project will be a great one to bring forward. So we’re not ready yet, but it’s something that we’re actively looking at, and we’re kind of growing in excitement around being able to do something at the Elk Hills power plant.

Betty Jiang: Got it. Very interesting look forward to that. And then my follow-up, more on the free uses of free cash flow. We are seeing quite a bit of free cash flow generation in 2020 this year and next year. And — wondering what are the call on your cash maybe for the next several years. The only thing we see is there is that potential, the 2026 maturity is that something that you want to preserve cash to pay off? Or as you start generating that meaningful free cash flow, that’s more likely to come down to cash return can be a buyback?

Francisco Leon: So, yes, Betty. So we I guess do we have to look backwards to our track record as a company since 2021. And we’ve returned $894 million of cash to shareholders through a combination of dividends and buybacks. And we also were able to accumulate a significant amount of cash. So that’s the business model. That’s what CRC offers. The ability to generate a lot of cash in then aggressively returning it back to shareholders. We are very comfortable with a fixed dividend model. We want to continue to offer that to our shareholders. And we like to have that as a growing fixed dividend model. This is the fourth consecutive year where we’ve grown that dividend. So, that’s a key part of our strategy. The share buybacks are important as well in particular at levels where we’re trading today.

And as we wait for all these catalysts to unfold, it makes a lot of sense to us to buy back our shares on what we think is a meaningful discount and that’s where the discretionary piece ultimately comes from. So I guess the other point to raise on the buybacks, we no longer have effectively any restricted payment capacity on the buyback. So your question is, is Supervalu. It’s about the — what do we do with the cash. And you know you talked about the debt. The 2026 is what we said is we want to be at a 0.5 turn net leverage and we’re slightly above that. But we want to get to that target — third target point quickly. And so we’ll look to preserve some cash to get there or always look to be in the market if there’s an opportunity to buy those bonds.

As a reminder, the 2026 is callable or a little bit over one or one and then they step down to par next year. So it gives us some prepay ability option. So we have the option to refinance prepay. But ultimately, we talk with our Board every quarter and we decide, what’s the best use of that cash and that’s been buybacks by a long shot in the last few quarters. So, we’ll continue to preserve that optionality. It’s a good place to be when you have cash. I would lock in the fixed dividend and then look for ways to buy more shares. And as we said, we were going to continue with our balancing strength too. So we’re watching the maturities and looking at that as well. So the nice thing is as we wait for permits next year, we have that excess cash flow that we have multiple ways to put it to work in a very attractive way.

Operator: And our next question will come from Scott Gruber with Citigroup. Please go ahead.

Scott Gruber: Yes, good morning. Francisco, turning back to the Cal capture project. What is the latest cost estimate for that project? And how do you think about funding it and yes, how long would it take to add capture the plant we have both in terms of permitting and construction.

Francisco Leon: The full picture comes certainly on the cost and permitting side, but also on the revenue line. Once you have all those components, we can address your question. And then we can also look at different financing opportunities. We see a lot of appetite from private equity in growing support from traditional lending to deploy capital in projects like how captured that are decarbonizing existing infrastructure. So we feel good about where the direction of that business model is going. But we know it as I said earlier we need to understand both the incentive packages in the long term PPA around carbon free power in order to make that decision. And we’re still not there yet. We’re still looking at that doing the price discovery on that — and not on that part of it.

So and what I would look for is an update that has a more comprehensive view of what we’re going to do with time line with cost estimates and ultimately, how do we get — can generate an attractive return on the projects.

Scott Gruber: That’s fair. We’ll wait for the details. And I was curious you had some more color on CTV6. It’s going to be your largest site once approved. Is that tied to a specific project that has been announced or maybe one that hasn’t been announced? And I was looking at the anticipated time of CPA approval in 2027. Is that a bit longer given the size maybe just building in some conservatism there, so just some more color CTV6? Thank you.

Francisco Leon: Het Scott. Yes absolutely. So let me start by saying I’m very pleased with the pipeline inventory and the CTV. team has been building. As we talked when we started the strategy in 2021, we talked about having one billion metric tons of potential. So, to having 300 million tons already in the queue for permitting in different areas different type of reservoirs in some assets that we own some assets that we picked up over time. It’s really truly a testament on how good this team really is in achieving our strategy. It’s you can see it. It’s all there in the EPA information but I see very few companies are able to us to show as much progress as we have. And so and we have more to go right. And we continue to refine the permitting get better at it and at land that has that core space prospectivity as we go after the premium pore space in California as it relates to class to the CTV. six reservoir. I’ll turn it to Chris to provide any additional details.

Unidentified Company Representative: Yes. So CTV. six and if you look at the map you can you can see that we essentially have some bookends if you will with our storage projects in the San Joaquin Basin in the South and then the Sacramento Basin in the north. And we used the description of Central California to describe CTV 6. So, it’s just that it’s in the middle or more in the middle of the state and essentially filling in across the Central Valley where we can find the best intersection of high quality meaning high injection rates combined with attractive acquisition cost and ease of execution going forward. This is the next step in that process. We like the area and it is I would anticipate that it will follow the same sort of time lines as you’re seeing in the EPA tracker for CTV.

one through five. I don’t think there’s anything different about it that would cause it to go faster or slower other than the fact that now that we’ve been through this and have this many permits through we hope that overall the time lines continue to compress at EPA. But there’s nothing the size of the asset itself should not require a longer timeframe to evaluate by EPA in terms of if it’s associated with a particular project a part of the consideration for where we acquire pore space just that what are the addressable emissions in the in the local vicinity. And I would just say that without specifics this this asset has ample opportunities for both brownfields and greenfield emission sources.

Operator: And our next question will comes from Kevin MacCurdy Pickering Energy Partners. Please go ahead,.

Kevin MacCurdy: Hey good morning. We appreciate all the details and the shareholder return. You mentioned that over the last several quarters, the Board found the buyback to be the most attractive use of free cash flow. My question is what indicators are you looking at to make that decision isn’t an internal NAV or recent share price dislocation? And do you have any flexibility to temporarily go above free cash flow if you saw a large dislocation?

Francisco Leon: Yes. So, the way we look at it it’s really a view on the intrinsic value of the business. And if you do you can look at it from multiple EBITDA. But we like to like to look at the sum of the parts and you have an integrated business that s you look at all the value drivers from our very stable very valuable PDP oil and gas wedge. And then you add on top of that the power generation cash flow that we’re bringing in today the prospects for the power generation in the future you have the very high in our eyes on our reservoirs and then just looking at the CPV optionality of bringing this model forward and add on that prospectivity around data centers and the ability to monetize the Huntington Beach asset over time you get to a value of the business that’s meaningfully higher than where we are today.

And that’s what gives us confidence as we as we’re trading today below 4 times EBITDA. This company just given its solid foundation today cash generation ability, but ultimately, the catalysts are coming within the next five years. This is the right place to put our capital to work in terms of returns. As it relates to would go over cash flow we have we’ve done it in prior quarters where we’ve actually distributed more than 100% of cash flow if we had some asset sales or are some timing opportunities to be more aggressive. So we’ve done it before and the plan is to return as much cash as we can to shareholders. So if the opportunity is there we are not afraid to lean in.

Kevin MacCurdy: Great. Thanks for all that detail. And as a follow-up we noticed that you increased your oil mix for the second half of the year on basically 79% which is effectively increasing your oil guide. What’s driving that? Is that something you’re seeing in the new era assets? Or is that something in your legacy assets?

Francisco Leon: Yes absolutely. That’s the answer that we feel can contrast the asset bases. It’s almost entirely oil and the gas and NGLs will come from the CRC portfolio. The oil is areas show yes, you should expect a higher oil weighting and you should expect higher net revenue interest as I already mentioned and a nice portfolio of assets throughout the state that allows you to blend the crude to get creative around how do we move things around. So but, yes, ultimately that’s you have the higher oil weighting given the air portfolio is almost exclusively.

Operator: And the next question will come from David Deckelbaum with TD Cowen. Please go ahead.

David Deckelbaum: Thanks for taking my questions guys. I’m curious just a follow-up on some of the other questions around the return on capital. How did you arrive at the specific fixed dividend? And should we think of it as it grows over time? Our ratio relative to free cash are that given long-term oil price.

Francisco Leon: So we look at the fixed dividend in terms of how it compares to other E&P companies to indices obviously where we were fighting for capital from investors and want to make sure we have a competitive yield on our dividend. These assets given how low capital intensity the intensive they are really are really great for that fixed dividend growth over time. So we wanted to provide a cadence that attractive and the growths are significant and that’s we are leaning in and looking at synergies we feel like the step-up is require a higher incremental change than we had in prior sessions where we were closer to a 10%. But we want to provide a consistent fixed dividend in. We have the runway to be able to do that over time again given the quality of the assets and our focus on synergies to continue to find more and more cash to return to shareholders.

David Deckelbaum: Appreciate the color. It certainly looks like there’s plenty of runway left there. Now I wanted to ask more on the AI data center thematic but I think for the sake of that topic being covered, I’m curious just on what you’re observing around the Kern — excuse me permitting environment pro forma now with Arrow having closed where are most of your efforts and sort of focused around those initiatives? Maybe you could update us on the balance of looking at state-level permits versus what you’re seeing happening at the local Kern County level?

Francisco Leon: Yes. So I mentioned before the we see multiple alternatives to get the permits back on track. Working with different agencies in Kern County you have the county themselves at initial permits. The rest of the state is pretty much CalGEM used to be called Doggr that ultimately issues that permits. In CalGEM has been going through a significant realignment of the organization in that primary reason we see for are some delays there. But a deep we’re having really good discussions around our permitting process in ultimately how we see this playing forward is much more field specific permitting so not what we have today or had a few years ago which is countywide permitting it didn’t go into more field specific and which is much easier to define from a permitting standpoint in fields where our 100% owned by the company will be where I see the and then the path to getting the permits reinstated.

So as an example we have a massive inventory in Elk Hills and Belridge. These are our two core fields. As I mentioned before, a lot of the work that we can do is to do workovers and that’s not just repair workovers. We can recomplete uphole, down-hole. We can sidetrack wells and we see a lot of opportunity to do that. And that’s basically what we do today. But we also have a lot of new production that can come online with new wells in those as well. And those are fields that are entirely owned by CRC. Elk Hills has fee-simple, Belridge is pretty much fee-simple mindset a couple of percent points. So we have the ability to permit on lands that we own. There’s no overlap with farmers and certainly no communities nearby. And we see those as the core of the activity on a go-forward basis.

So we’re working through the changes at the agencies and we’re working through to provide more much more of a stable regulatory pathway in that. We feel we have a lot of good data in really good practices to be able to get back on track.

Operator: And our next question will come from Leo Mariani with ROTH. Please go ahead.

Leo Mariani: Hi, guys. I was hoping to dive a little bit more into some of the regulatory progress/initiatives in the state. Can you talk about what the current status of some of the new potential 3,200 foot setbacks that have been proposed? And then additionally is there been any real movement or update on the states push to come up with some rules and regulations for new CO2 pipeline infrastructure?

Francisco Leon: Hey, Leo. So yeah regarding the setbacks, these are now a law to have 30 to 400 feet setbacks in the state. We’ve been working towards documenting the impact for two years. And this really — we were already at a place where we felt comfortable with the law going into effect. So no impact or very insignificant impact that we see on the CRC portfolio. There’s also no impact to the Aera assets. Everything is really in Kern County in rural areas away from communities. So we just don’t see any impact on setbacks on a go-forward basis. So we’ll comply with the laws and have a lot of incremental inventory to drill within those limits, so no impact there. In terms of the pipeline regulation that Senate Bill 905 that had a temporary moratorium on pipeline regulation for CO2.

We see a lot of support if you can have the state of California reach targets, decarbonization targets without a pipeline solution. It’s just not going to get there. So as we build our CTV business and we put the permits in place were for space that pipeline will ultimately drive a lot of the growth in the business for us. And so where we feel very good about launch CTV and getting to first injection of CO2 by next year at Elk Hills with a biogenic gas project, ultimately the scalability of the business will depend on pipeline regulations coming to fruition. So what we see like I said, I think the — all the decision makers at the state level are aware that they need us. We need more support as industry to launch these projects and we’re standing by to be able to put more capital to work and make these projects a reality.

So the session in California it just got started after the summer break. We still have a few weeks left, optimistic that we can we can get some resolution there, but again we’re trying to highlight the art of the possible here to the state in terms of getting to their objectives if we can unlock the value there on the pipe regulation

Leo Mariani: Okay. Appreciate that. And just wanted to jump over to the electric generation business. So my understanding was that you guys were getting roughly a $150 million payment from the state to serve as a backup electric gen provider in case, you folks are needed. When I look at your guidance for full year 2024 you guys are estimating around $100 million in EBIT. So just trying to reconcile those numbers there, are you expecting kind of a loss from the business kind of regular way and then you get this $150 million kind of on top, which gets you to the $100 million EBIT guide. Can you just kind of help me out with the concept here on some of the numbers?

Francisco Leon: Yes. So I think, the short answer is, don’t forget we had a major turnaround, the plant major turnaround early in the year. So the plant was offline for a period of time. And when you look at power generation cost of the plants start running than major purchasing power from the grid. So there’s an offset, but I’ll turn it to Jay to see if he wants to add more color.

Jay Bys: Two pieces of the revenue stream Leo there’s the energy — energy sale stream and the RA capacity stream, which you kind of just touched upon. For 2024, that RA as we call it, a resource adequacy revenue stream, is approximately $104 million across the year. It will be closer that one $150 million figure a little over that for calendar 2025. So just to make sure we’re comparing apples to apples. The energy contribution this year, given the prevailing pressure provided by intermittent resources. The energy piece is not as robust as it was last year. If we get a warm summer, if we get a cold winter, we expect that to change. But for the time being, right now, the capacity piece is the larger piece of the revenue stream on the power business.

Operator: And the next question will come from Noel Parks with Tuohy Brothers Investment Research. Please go ahead.

Q – Noel Parks: Hi. I just had a couple of questions. I want just to just to clarify. I apologize if you talked and sort of touched on this already. So on the Aera properties, just wondering are there any of the sort of lingering land or lease issues on the Aera side where sequestration target areas are. I’m just wondering, is there anything you need to clean up that’s not long — you’re no longer held by production anymore for instance, or more may not be — but that is valuable from sequestration.

Francisco Leon: Yes, one of the exciting things about the Aera transaction is that it allows us to expand our premium pore space near Bakersfield, with two additions to the portfolio. One is the project that we called CarbonFrontier. That’s in the EPA tracker that now we have inherited. And then there’s another property called Post Levy [ph] which is adjacent to Elk Hills that we look to permit in the future. These are again one of the big advantages to California is in California operators in general but CRC is the best example is, our land position is really strong. We own a lot of the assets and if it’s simple that means we own surface in all depths, all rights on those reservoirs. And so the nice thing is Aera has the same feature in their asset.

So, there’s always going to be small cleanup items here and there, but nothing of significance. We feel those projects are in really good shape, with a strong permit submitted and we look forward to taking it over and accelerating some of the emission capture in the Central Valley.

Q – Noel Parks: Great. Thanks. And another one on Aera. Did Aera have any partnerships in place similar to for example, CTV and Brookfield that — that will persist now that the combination is closed. And I was wondering, if there are any contractual issues right of first refusal or anything out there hanging with other parties that you might not be immediately apparent?

Francisco Leon: No nothing — no partnerships, no CDMA on their acreage or capital commitments of any kind. So this would be assets that we would anticipate contributing to the partnership and working alongside with Brookfield to bring them forward. So, we called it at the right time, in my view right? They were — Aera was fast following CRC in terms of permitting and we were faster on commercial and financing. So this is — a really good opportunity to bring projects forward, but leading the CRC team the CTV team shape, how those reservoirs get filled.

Operator: And this will conclude our question-and-answer session. I’d like to turn the conference back over to Francisco Leon for any closing remarks.

Francisco Leon: Thank you for joining us today. We will be presenting at investor conferences in September. Lots to talk about, we’re looking forward to seeing you. Thanks.

Operator: The conference has now concluded. Thank you for attending today’s presentation and you may now disconnect your lines, at this time.