Welcome to the California Resources Corporation Second Quarter 2023 Conference Call. Participating on today's call are Francisco Leon, President and Chief Executive Officer; Nelly Molina, Executive Vice President and Chief Financial Officer; as well as CRC's entire executive team. I'd like to highlight that we have provided slides in the Investor Relations section of our website crc.com. These slides provide additional information on our operations and our second 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 press 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. And we ask that participants limit their questions to a primary and one follow-up. With that, I will now turn the call over to Francisco.

Thank you, Joanna. At CRC, our strengths are clear; cash flow, carbon and California. First, our cash flow strength comes from our high-quality low-decline assets. These assets provide a large production base with predictable cash flows from our long-lived reserves. Further, we produce some of the lowest carbon intensity oil and natural gas in the US, which we sell into markets that have access to premium pricing and advantaged realizations as compared to the rest of the US. Our second strength is our carbon storage platform, Carbon TerraVault, which benefits from an early mover advantage for CCS. CRC's large mineral and surface acreage position, the quality of our geological reservoirs, our extensive surface knowledge, and the joint venture with Brookfield continue to provide us with a competitive advantage. Carbon TerraVault leads the nation in permit applications submitted to the EPA. Additionally, our CCS storage potential continues to attract significant interest from current and future emitters. To date, we have executed five carbon dioxide management agreements, or CDMAs, for a combined injection rate of 815,000 metric tons per year, which represents reservations of 16% of our port space and good progress towards our target of 5 million tons per year of injection by year-end 2027. Our third strength is California. California's energy industry offers an attractive market with high barriers to entry. The state is the fifth largest economy in the world, with energy needs that far surpass local production. At CRC, we proudly operate under the highest environmental standards in the world, and our long track record of safe operation demonstrates our ability to navigate California's regulatory landscape. California also has ambitious decarbonization goals and the right incentives to drive emission reductions throughout the state. CRC is well positioned to help advance the state's energy transition and be a solutions provider. From an operational perspective, we continue to make great progress on our business transformation efforts and are now targeting $50 million or more in annualized run rate savings. The goal of our transformation is to recalibrate our approach to reflect our current and future needs and improve our cost structure. Therefore, we're evaluating all aspects of the business, looking for operational optimizations, organizational improvements, and new technologies to drive cost out of the system. Initial actions have focused on our key business processes around well services, chemical programs, and our warehousing model. We also see opportunities for improvement in how we utilize our contractors and rental equipment in the field locations. By aligning our practices and operations to the current business environment and our long-term strategy, we can execute on our strategy to maximize cash flows and further enhance shareholder returns. Note that savings from these initiatives are not included in the '23 guidance we provided today, but are targeted to be in place before year-end and reflected in '24 results. In the second quarter of '23, we produced 86,000 BOE per day, operating one rig in Long Beach and 35 workover rigs. A combination of strong demand and favorable pricing underpinned $69 million of free cash flow generated in the quarter and brings our year-to-date total free cash flow to $332 million. During the quarter, we repurchased $64 million of our common shares and paid $20 million to our shareholders in dividends. This represents 122% of our free cash flow return to shareholders in the second quarter. Since May 2021, CRC has returned nearly $700 million to our shareholders, or nearly 20% of our current market cap. Our reservoirs continue to perform in line with expectations. Our stable performance is best observed from our gross production results, which excludes variations from our production sharing contracts in Long Beach and NGL storage levels. Our flat quarter-over-quarter gross production demonstrates the productivity of our stacked pay and efficacy of our downhole maintenance program. As a reminder, we continue to see delays in new drill permit approvals, but continue to receive permits from Calgon for workovers, deepening, and sidetracks. Despite a lack of new drilling permits, we remain on track to deliver a 5% to 7% entry to exit production decline. Our 2023 development plan is focused on permits in hand, and our high-return recompletion and workover activity highlights CRC's ability to manage reservoirs and maintain capital efficiency even at lower activity levels. On a net production basis, oil came at the midpoint of our guidance range, while total production ended up on the lower end due to the storing of NGLs. We typically store NGL volumes produced during the second quarter to sell in higher demand periods, maximizing our cash flows. On the power side, our 550-megawatt power plant provides us with the ability to manage field-level power costs at Elk Hills and surrounding fields, as well as to optimize between taking incremental volumes of natural gas to market. We're converting the natural gas to power for delivery into the wholesale power market. Our natural gas and marketing activities once again had a very strong quarter, as Citygate gas prices held up much better than field-level prices. The team was able to double quarterly margin results versus guidance expectations by taking advantage of the transportation and delivery resources we maintain. Looking ahead, our natural gas marketing margins should moderate in the second half of 2023 as California natural gas inventories return to more seasonal levels, and the abundance of hydro-generation capacity competes with natural gas-fired generation this summer and fall. Moving to carbon management. During the quarter, we executed our fifth CDMA with Burdick Clean Fuels for our renewable gasoline project. This project further confirms our economic type curve of 50 to 75 of EBITDA per metric ton for storage-only projects. We also expanded our capacity reserve for Lone Cypress for the previously announced blue hydrogen projects. Anticipated CO2 injection has now more than doubled from 100,000 to 205,000 metric tons per year for the project. These facilities, in addition to our agreement signed with Intec earlier this year, are planned to be located at our net Hero Industrial Park at Elk Hills, which provides a unique benefit of offering surface acres for build-out midstream and co-location with permanent CO2 storage. Post-quarter end, we submitted another Class VI permit application for CTV 5, continuing our position for storage permit submissions in the queue with the EPA. The permit application has a capacity of 70 million metric tons of CO2 storage, bringing CTV's cumulative potential storage capacity on their permit applications to 191 million metric tons. We continue to target a draft Class VI permit from the EPA by year-end. The recent EPA draft permit approval for our project in Indiana is encouraging for the CCS industry and provides yet another data point of EPA support for the technology and progress. We remain optimistic and continue to see positive traction from our conversations with potential emission sources as well as various other stakeholders. Lastly, we continue to evaluate the separation of our carbon management business. Carbon TerraVault continues to make strong progress each quarter. However, we're still in the early stages. We continue to look for certain important milestones such as permit approval, project FID, and line of sight to first CO2 injection and cash flows before considering a potential separation. And now, I'll pass it over to Nelly to provide an update on CRC's financial position and outlook.

Thank you, Francisco, and welcome again, everyone. Our balance sheet remains in solid condition. During the quarter, we expanded our net RBL commitment by $25 million, bringing our total commitments to $627 million. We ended the quarter with $927 million of liquidity, which includes $448 million in cash. Our net leverage position reflects a very modest 0.2 times of leverage, while our fixed charge coverage exceeds 17 times. Given the cyclical nature of the commodity prices, keeping our financial strength is a key pillar of our strategy. Looking forward, we are maintaining our full-year production guidance. As Francisco mentioned before, our reservoirs are performing in line with our expectations, which are informed by decades of operating history. We anticipate modest declines in the second half of the year, in line with our previously disclosed range of 5% to 7% annual decline. Regarding our capital program, we take a dynamic approach in response to commodity price volatility and focus our activity on maintaining oil production and maximizing our free cash flow. We reaffirm our 2023 capital program to range between $200 million and $245 million under current conditions, with a heavier weighting in the second half of the year due to timing of projects and higher expected workover activity. Oil and natural gas development will continue to be focused mainly on executing projects using existing permits. While commodity prices remain at healthy levels, the forward strip softened during the second quarter. Our updated guidance reflects our strong natural gas marketing activities to date as well as our outlook for commodity price differentials. The NGL markets reflect seasonal quarterly pricing trends in the global oversupply market environment. On the natural gas side, our guidance reflects the unprecedented price hikes registered in the first quarter on the full-year average, but that also the return to normalized levels in the second half of 2023. As a result, we are lowering the top end of the range of our 2023 operating cost guidance by $15 million due to lower energy-related operating expenses expected in the second half of the year. Additionally, we are narrowing the range of our free cash flow guidance for the year to $380 million to $460 million. Let me remind you that our 2023 guidance is based on an estimated Brent price of $77.54 per barrel and $2.97 per mcf NYMEX price. Our key financial priorities in the second half of the year are the execution of our business transformation initiatives to reduce our respective 2024 cost run rate by $50 million or more, and being responsible stewards of the best use of our balance. With that, I will turn it back to Francisco.

Thank you, Nelly. CRC's unique value proposition is founded on our disciplined capital allocation, solid balance sheet, and free cash flow generation capability. CRC's continued progress at Carbon TerraVault provides shareholders a way to participate in CCS and California's path towards a decarbonized future. To summarize, CRC's strengths are Cash Flow, Carbon, and California. Thank you for joining us on the call today. We'll now open the line for questions, Operator?

We will now begin the question-and-answer session. The first question comes from Scott Hanold with RBC Capital Markets. Please go ahead.

Hey. Thanks. For my first question, I was wondering if you can provide an update on the Class VI Permit process with respect to the Indiana Permit that you had indicated. So, if you could compare and contrast any kind of differences or the timeframe that they had to go through in Indiana to get theirs versus what you all are doing there? Just trying to get a sense of your confidence in that year-end target for receiving the draft permit.

Hey Scott, it’s Francisco Leon. So yeah, we're still targeting the draft permit for CTV before year-end 2023, a big catalyst for CTV and big catalyst for California in general. We're engaging with the EPA regularly and hope we are the first in California. We are dealing with a different part of the EPA. We're dealing with Region nine, so we talk to both Region nine and headquarters. However, we don’t have a lot of visibility into the permit in Indiana. Best we can tell is that they filed before we did, so there's a little bit longer timeline for them, but hard to say really from where we stand how good the permit application was and ultimately the steps that they took to get there. So I won’t comment on that permit. I just feel like we made a lot of good progress on the technical discussions with the EPA and still feel very much on target to get the draft permit this year.

Got it. And when we refer to the technical progress, you're just talking about like the suitability of the reservoir and everything like that. Is that fair?

That's fair. I mean, there's financial assurances, community support; there's a number of things that the EPA is going through as they make a decision on permits. I feel that Chris Gould and the team have done an exceptional job getting us prepared. Ultimately, we're waiting for that final sign-off that we have the draft permit. I think not only CRC but the rest of the CCS space is eagerly waiting for the EPA to move on more permits.

Okay. And for my next question, I'm going to sort of keep on the same kind of line of questioning. But the community support aspect, obviously, I think is going to be a big kind of lifting effort, especially being in California. But can you give us a sense of what you at CRC are doing specifically to get the community support and help get that through? I do think there's that comment period after you received the draft, correct?

Yes, that's correct. After the draft permit gets granted, there's a period of time for public comments and then a final permit gets granted after those are incorporated. Our team is working diligently in parallel to get the public comment discussion underway and getting the support from the communities. The first project is critical for all stakeholders. In Kern County, we're also at Elk Hills, a field that we own 100% fee simple and remote from any neighborhood in the areas of concern from the public. This is the right place to have our first project in California. We see as we spend time with community leaders and we do community plans, we feel that support is there. It’s not a sequential process; we started already and feel the support is going to be there. We're also working with Kern County and the Kern County Planning Commission to look at the permits that are required at a local level, so we're good to go once the EPA gives us a sign-off. A lot of things are in motion, but we are progressing in every respect and look forward to getting started.

Appreciate it. Thank you.

The next question comes from Kalei Akamine with Bank of America. Please go ahead.

Hey, good morning guys. Thanks for taking my question. My first question, I just want to hit on production. So coming into this year, I think we were expecting to see high single-digit declines by year-end because of the constraints that you're seeing on the current county permitting process. So I'm hoping that you can help us understand what the drivers are to the better production performance that you're seeing. Is it better new well performance? Is it some kind of tailwind from prior years, or is it the underlying base? Really, the nub of my question is trying to understand what the unmitigated decline of the portfolio is?

Hey, Kalei, good talking to you. I think you summarized in your question that the answer really well. So quarter-over-quarter, if you could look at gross production, that’s the best way to judge the performance of the reservoir. We have some NGL storage noise in the quarter and you always have the production sharing contract, but the way you look at the reservoir is to go to gross production, and we were flat quarter-over-quarter. We had three rigs when we started the year, so there’s some benefit from performance of those wells. Our current development plan, which is focused on the Wilmington Field in Long Beach, is performing extremely well, kind of with wells having a positive type curve. At the end of the day, it's the quality of the underlying asset. The PDP of our base has a naturally very shallow decline. As we’re able to move OpEx dollars through downhole maintenance and as we’re able to do capital workovers, we're able to mitigate that base decline over time. It’s a low decline to start with, and all the activities have the effect that we would want. We still think what starts fading out is some of the support from the initial activity in the year, so we do see a 5% to 7% entry to exit decline. I feel pretty good about that number; if you look from January to December, but we’re happy with the results in the performance of the base and the way production has responded year-to-date.

Awesome. I appreciate that color, Francisco. My second question goes to the carbon management business. Now I understand that there’s some legislation in the works that’s going to help define the state regulations on the CO2 pipelines, and I think that's now expected in 2024. So I'm trying to understand what the impact that may have on perhaps the third parties that are situated around you that are considering capture projects. Because at the moment, most of your offtake is with new build plants to be located on your own property where those regulations may not be as meaningful?

Yeah. There’s a lot of work happening in California to get some pipeline regulation and the framework in place. We see significant support among legislators for CCS, and there’s a lot of discussion happening on effectively what's a trailer bill to Senate Bill 905 to get that framework put in place. This session is still open, so I wouldn't say that it’s happening next year versus this year. We do see progress; we do see conversations happening. I wouldn't put a timeline to it until we have and ability to see how the session finishes. That is an important piece of legislation that needs to come out. If you think about why we are at five Greenfields and not any legacy Brownfield projects, it’s really two things: one is the price discovery negotiations on the split of the economics, which is a normal commercial discussion between parties. Ultimately, we have an existing emission source and you have a permitted sink, which we’re going to have in multiple places throughout the state. That connectivity between the two points is critical. Without having a good way to understand how the CO2 pipeline is going to be regulated, I think that's an important gap we're overcoming on both sides of the fence with CCS. We’re working alongside all the decision-makers and stakeholders to provide our input, and that’s hopefully going to get us there in the end. The way we're thinking through this is going on Greenfield projects; it’s a tremendous way to accelerate CCS. We can’t wait always for the regulation to be in place on the more challenging aspects. We do have a project that can be co-located; we have three projects now, right? Blue hydrogen, renewable gasoline, and DME. That’s a way to bring the energy transition into the near term, which is something that California really wants to see. So, it brings alignment; we provide this one-stop shop. It’s a good way to showcase progress as we wait for all their regulations to come into play. You’re right; that’s going to be an important aspect to see that trailer bill to 905, and we are very much looking to see that, and that’s going to help literally connect the points between emission sources and the storage space.

I appreciate it. I’ll leave it there. Thanks.

Thanks, Kalei.

The next question comes from Nate Pendleton with Stifel. Please go ahead.

Good morning. My first question starting at a high level: can you comment on how, or if recent M&A in the CCS space has impacted your view on separating Carbon TerraVault?

Yeah. I think it’s important to see the M&A space moving on CCS. It's a good validation certainly of where the industry is heading, particularly for the Denbury team. It’s hard to predict where we go from here other than there’s a lot of investor interest and investment dollars in this space. Does that lead to combinations? I think it’s clear that we’re heading there. Ultimately, we’re all going to be on different timelines. We’re going to be in different markets to pursue. I see it as a good validation point that CCS is going to be here to stay. In terms of the separation, I would say we are focused on the things that we don’t control and whether we expand or not outside of our current footprint. The focus really needs to be – we need to get permits from the EPA; we need to start construction and get line of sight into that first cash flow. At the end of the day, we’re going to look at – it’s an early-stage industry with a lot of people watching every step of the way, so the best way to do it is just take it step by step and start showing progress. The progress we’ve shown in two years has been tremendous. We look to accelerate that, but ultimately the permit is the catalyst. I don’t see the M&A as a catalyst; I think the permit situation with the EPA is what’s going to get things moving, not only for ourselves but a lot of others in this space.

Thanks. And looking at Slide 17 with your Carbon TerraVault projects to date and the significant addressable market you mentioned on Slide 16, do you have a target cadence for adding new sequestration sites beyond CTV V, or could you provide any color as far as your outlook for additional sites?

So we're targeting 200 million tons of pore space to be permitted. We're at 191 million, so we're pretty much there in terms of the permit submission aspect of this. What we've seen is, as we saw with 26R, part of CTV1, once you're in discussions with the EPA, once you collect more data, and once you have a better sense of the land position, you're able to expand the projects, and that's what we did with 26R. There's always going to be room to expand beyond what we're submitting, but I think for what is critical is – we’ve now secured the pore space that we want to pursue. We started the permitting process. It's about bringing the CO2 into those fields. That’s the next catalyst and that’s what we’re focused on. There’s over 20 million tons per year of emissions; if you add every single counterparty we’re talking to at the moment, it adds up to about 20 million tons of emissions. We think our pore space is ultimately able to get us to about 5 million tons of emissions per year. We’re about four times in terms of the coverage of CO2; in terms of the counterparties that we're talking to, we're 4x our capacity. It’s important that we start getting reservations and finalize deals with other parties. At some point, the pore space is going to run out, right? And then you have to restart again. There’s going to be a lot more to do. We think it’s five times our pore space that we ultimately can do, but our near-term target is 200 million tons. So really focused on connecting the dots with the emitters because everything else is in pretty good shape.

Got it. Thanks for taking my questions.

Thanks, Nate.

The next question comes from Nitin Kumar with Mizuho. Please go ahead.

Hi and good afternoon, guys. I'm going to start with the oil and gas side of things. Francisco, you mentioned the $50 million target on OpEx. As I look at the numbers you're really not guiding to that and you said that. But could we get a sense of the progress you have made to date? I know you aren’t expecting an impact this year, but where are you on that project to reduce cost by $50 million?

Hey Nitin. So, I'm really excited about this initiative. I feel like we have a tremendous team, a tremendous organization, but I challenged the team to see if we could do better. That was the question; can we do better than we have in the past? Are there opportunities? Omar, who is here with me, and others on the team really have stepped up to the challenge and said yes, we can do better and we're getting after it. We gave some examples of the things we're looking at from the way we contract; there's an opportunity to bring some contracting work in-house. There’s other places where you may outsource, kind of challenging the model that we've had for close to a decade now as an independent company. It was a good time to test things that we could improve. We're looking at the warehousing model. We're looking at relationships with key vendors. We're looking at organizational design. I think the commitment that I have from the team is this is not going to be a one-and-done process. We’re always looking for ways to improve the cost structure. Where we might reach a finality here in this quarter in terms of this first stage to get to $50 million, we can start incorporating that into the 2024 guidance, and we'll continue working through ways to improve the business. We think we can get to that $50 million; we have a line of sight. It's a commitment from the team to continue to look at operations and try to bring down the cost structure and ultimately drive to higher cash flows.

Got it. Thank you for the answer. On the carbon management business side, you talked about the type curve of 50 million to 135 million per MMbtu. You're close to that first million or so 815,000 CDMA signed. This might be a long shot, but any sense of which part of the type curve you are tracking to in the first 800?

Yes. All five of our projects so far make up the entirety of that amount; they are all greenfield storage-only projects. That points towards the lower end of the type curve; so 50 to 75 is where we bracket the storage-only EBITDA. The way to think about that is it’s a lower capital requirement for those storage projects. All five of the projects we are working toward will have a capture component built into the facility. So you don't have to attach the capture technology into an existing plant, so it’s already embedded. You also have a much higher concentration of CO2 as you bring these projects to life. With these projects, because they are lower capital-intensive, you’re able to make really attractive returns even with the lower EBITDA. The opposite end of the model is where we have a full CCS service where we go to an emitter and do all the way from capture equipment installation to transportation to storage, and that’s the part of the type curve that points to the higher levels. That also has higher capital commitments, and you need a higher contribution from incentives to make a return. So right now, we’re focusing on the lower end, but lower end in this case means really good returns and low capital, so we're happy with those projects. We do want to pursue many Brownfield projects as we can. Ultimately, this business is going to be successful if we can decarbonize existing industry as much as we can. That’s what we need in state and we think we're well positioned to achieve both ends of the spectrum.

Got it. Great. If I can sneak one last one. Just any update on the current County permitting? I know you had said that you expect permitting to restart in the second half of next year. But any updates there?

That’s still the timeline we’re at. We anticipate a hearing in the appeal process to be scheduled sometime in Q4 of this year. That pushes a final decision to the beginning of next year. So we’re looking to be back to normal activity in the second half of '24. No real changes; we think the hearing is going to get scheduled here very soon. As a reminder, we're working on alternative plans to field level. What's being challenged in the quarter is the current county environmental impact report. We're doing field-level sequels and EIRs for three of our core fields in the San Joaquin Basin that collectively have about 90% of our proved undeveloped, but we're also looking for inventory and ability to drill wells outside of current County. It’s an all-of-the-above strategy to get us back on track by the second half of next year.

Thanks so much.

The next question comes from Leo Mariani with Roth MKM. Please go ahead.

Hi. Can you guys talk about just the production guide in the third quarter? So second quarter you did 86,000 barrels a day net. You guys talked about seeing some declines in the second half, but your third quarter guide is 86 to 88, which implies sort of a modest increase. Can you just kind of help us connect the dots there?

Hey Leo, yes, we are recovering some of the NGLs that we were unable to sell. So, on a sales basis, that shift happens. Without any significant price movements affecting your PSC barrels, we see that as the appropriate range for the third quarter. However, this suggests some decline in the fourth quarter.

Okay. That’s helpful. And then just in the second quarter, I mean it looks like you guys paid out more than 100% of your free cash flow to shareholders in the form of dividends and buybacks. Is that sort of an anomaly, or are you guys comfortable potentially doing that just depending on, say, where the stock is and the macro situation based on the strength of the balance sheet here?

Yes. Last year, we paid over 100% of free cash flow, if you look at 2022. Year-to-date, we’re closer to 50. We had a very high cash flow order in Q1, and so if you average Q1 and Q2, even though Q2 is higher than 100%, we’re at about 50%. We’re comfortable with our capital allocation strategy, but we evaluate the best method to provide returns and value to shareholders every quarter. We have a fixed dividend, but it’s about $1.13 per share. That gives the market more of a fixed component. The rest is discretionary based on how the business is looking and where we see the most value. We haven’t been prescriptive on shareholder buybacks, but we assess every quarter where we are. In the past, we have been over 100%, but right now, we're closer to 50% for the year.

Okay. That’s helpful. And then also, could you just comment on sort of existing competition for CCS deals out there in California? As far as I know, you guys are the only ones that have kind of put some deals on the board here with five deals. But certainly correct me if I'm wrong, any information you can provide about the competitive landscape would be helpful. And then also, is there any update on the sale of the parcel that you’re working on in Huntington Beach area?

Yes, I’ll go with the Apache, which is our one-acre parcel in Huntington Beach first, and then I’ll come back to the CCS question. So we are making progress. There are many components to converting an oilfield to a real estate project. We’re going through abandonment, looking at regulatory requirements, and market conditions. We think this gives us a good look at what the ultimate decision will be for the bigger property, which is 90 acres down the street. It’s a good way to test the waters to ensure we understand all the requirements from the law and ultimately get this acre sold to the highest and best bidder. We are working through that. We said before we think this will be something we would do by year-end. This is not because we just want to provide a lot of cushion; there are a lot of things to do, and we’re working through it. In terms of CCS and competition, if you look at the EPA website, you’ll see that on the permit submission front, we are not the only ones. There are a number of other projects out there. They tend to be more for self-solutions, meaning there are parties that want to reduce their own emissions and have identified a nearby site. We haven’t seen the Carbon TerraVault competitor come out that has a view to look at all of the state emissions quite yet, but we do see competition; we think this is going to be a successful business undertaking, and we see others beginning to acquire land or start to see some permits in the EPA for parties that may not register as potential counterparties in the state. We feel good about what we’ve established to date, which is the core position that we wanted to have and what ultimately ties to our commitments. Don’t be surprised if you start hearing about others coming into California within the next six months.

Thank you so much.

The next question comes from Noel Parks with Tuohy Brothers Investment Research. Please go ahead.

Hi. Good afternoon.

Hi, Noel. How are you?

Good, thanks. Just a couple of things. I was thinking that of course that a company has the long roots in oil and gas production, and you observed that CCS is a very young industry. For the five deals you've done so far, is there a sense that the train is just starting to chug along, and maybe you can leave the station for CCF? I was wondering if you could walk through the deals to date and describe what types of things you were negotiating on each of these transactions to get you or to get the customer to pull the trigger? What are the issues that are in the mix when you're with these past deals?

Yes. We're kickstarting the energy transition in California, and there's a lot of interest to develop markets like hydrogen or renewable gasoline, the project we announced with Verde today. In many cases, you don’t have the product, nor do you have the market and the offtake. We are committed to the energy transition, but we need to drive towards that with a lot of investment, and that's where we work with agencies to get the permits underway. Otherwise, the transition is going to take much longer. What we're trying to do with the conditions precedent that are established in the CDMA is basically related to offtake agreements. In some cases, we have an existing offtake agreement with counterparties; in others, we are working through that. Who's going to buy the blue hydrogen from Lone Cypress is critical for us to understand. We have preserved the option to invest in the projects on all five of them at this point. A lot of groups with very deep pockets want to develop that hydrogen network for heavy trucks in California, but that doesn't mean we have something like seven stations in the entire state, so that’s a circular chicken and egg problem. We have offtakers that want the product, their building plans are ready to go, but you don’t have the hydrogen in a form that’s readily available and cost-efficient for them to sell. We’re trying to bring all of that together on these projects. But we want to be the tip of the spear and the leader in this space. We want to create these markets, but it will take some time. If you think about Brownfield and Greenfield, it might sound early-stage and like it’s not going to get there; it will get there. Because we’re focusing on areas where we already own the land, and we’re going to be co-located with the reservoirs, that brings us much closer to a final investment decision than others. If you had a Brownfield project, you still have to install a capture facility on an existing plant and ensure you have the right build-out on the pipeline. Thus, many of these projects will not happen next year. We’re looking at securing permits from the EPA, starting construction, and getting products to market. This is a long-term project, and we know we have the capital with Brookfield.

Great. Thanks a lot. This is just what I was looking for. You also talked a bit about technology development. You’re talking largely about in-house applications for cost savings, but just zooming out a little bit to a devil's advocate question. Post-injection of CO2, I was wondering if you have done any work or can talk about what sort of modeling technology post-injection you're going to need. Is that something that’s costly, are the methods or the vendors for doing that standardized? Just thinking if you have worries about not meeting the opposition to injection of CO2 and that sort of forestalling any concerns that might be there around if things are sequestered, et cetera?

No, that’s a great question. I’ll pass it over to Chris Gould to provide the answer.

Yes. Hey there. The first and most important thing to understand when it comes to monitoring is that that’s part of the EPA Class 6 permit. All the requirements are spelled out as to what needs to be done and for how long by what sensitivities those need to be dialed into, if you will. So, there’s really not a lot of guesswork there; we know what we have to do and we’ll get the permit based on complying with that. When it comes to fulfilling those requirements, there are many applications or opportunities to do it through collaborations with existing monitoring, as well as new technologies that we’ve been heavily engaged with the DOE and various universities that conduct this monitoring and have done so for many years, particularly in a state like California. We feel very well prepared for complying with the permit requirements with an abundance of different emerging or existing technologies. Thank you.

Great. Thanks a lot.

And we have a follow-up from Scott Hanold from RBC Capital Markets. Please go ahead.

Yes. Hey thanks. Francisco, real quick. You mentioned, obviously, on the shareholder return that you all are going to look at what creates the most value for the shareholders. And just some context, obviously you’ve got the base dividend in there. But as you kind of step in and look at the buybacks, obviously, when you’re doing it before for the last year or so, doing it under $40 was sort of a layup decision, right? Now, you’re $10 to $15 per share higher. Like can you walk us through that thought process of the allocation of the shareholder returns? Where does the stock price play into that? How do you think about where it is today versus where it had been over the last year?

Hey Scott, welcome back. So, what’s your price target? Like $60? We have the option to increase the dividend, and we also can look at the debt. All options are on the table. We like to be opportunistic because, just like we did last quarter, we were able to buy shares at $39. If you look at the history over the last four or five months, we picked a really good time to deploy the cash to buy at the lowest average price for the shares. The discretion that ability to make a decision really comes from a returns-oriented analysis. We look at the opportunities in front of us and make a decision. Even though there's discretion in how we return cash to shareholders, we’re very committed to the program and to returning the highest amount of cash to shareholders over the long run. Although there may be some variability in the amounts in the quarter, we do look at it actively and ultimately, we are very committed. I want to remind you; we didn’t talk about it today, but we have the high-yield indenture that governs our ability to distribute cash via either dividends or buybacks. It’s the last 12 months, 50% of net income calculation, and that’s an oil price or commodity price component. If you're bringing in lower commodity prices from the last 12 months, that acts as a capping mechanism. It’s difficult to specify what our actions will be, but we are committed to maximizing shareholder returns.

No that's helpful. Just one last quick question regarding the greenfield projects for which you have CDMAs. Considering your work towards obtaining the Class VI Permit, are there any other permits or approvals we should be aware of for getting something like a blue hydrogen, blue ammonia, or renewable gasoline facility approved at either the state level or the current County Planning Commission? Are there specific approvals or legislation that govern that process?

Yes. You need a conditional use permit. That’s a critical, local California permit; that’s in conjunction and working very closely with the Kern County Planning Commission. Those conversations are ongoing for the projects at Elk Hills. As I said before, we are working on all those in parallel. It's nice to have the Kern County Planning Commission there because they oversee all aspects of the energy spectrum; they do the conditional use permits for oil and gas, but also for solar and wind projects. So it’s a natural extension of what they do to look at the greenfield projects and be the group that oversees these permits. That’s one to look for. Like I said, we’re working through it. They’re aware of our plans and we are working lockstep with them with a lot of the same information that you send to the EPA. We’ll share more of the progress in the inner workings through the California approval; that’s the one I would highlight. Certainly, we’re looking for the pipeline regulation to also be put into place in the near term, as that is going to be critical as we move away from co-location. Okay. We think that's a wrap. Thank you so much for spending time with us, and look forward to seeing you on the road. We're going to be going through a number of investor conferences in the coming weeks and look forward to seeing everybody in person. Thanks so much.

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