Good day, and welcome to the California Resources Corporation Third Quarter Earnings Conference Call. Please note, this event is being recorded. I would now like to turn the conference over to Joanna Park, VP of Investor Relations and Treasurer. Please go ahead.

Thanks. Welcome to California Resources Corporation third quarter 2022 conference call. Participating on today's call are Mac McFarland, President and Chief Executive Officer; Francisco Leon, Executive Vice President and Chief Financial Officer; as well as the entire Executive Committee. 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 third quarter results. 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 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 Mac.

Great. And thank you, Joanna. At CRC, we are a different kind of energy company. We are focused on delivering consistent and predictable free cash flow. We are focused on disciplined capital allocation and shareholder returns from the free cash that we generate, and we are focused on advancing and accelerating our carbon management business, a simple but focused strategy. So let's discuss each of these in greater detail. First, consistent and predictable cash flow. During the third quarter, we continued to deliver strong results by producing 92,000 barrels of oil equivalent per day and $128 million of after-tax free cash flow. We did this despite externalities, including the continued litigation of the current County EIR, which has been recently resolved in the courts as well as ongoing inflationary pressures. We were able to accomplish these results because we have a robust portfolio of assets that allows us to adapt to the ever-changing landscape. Our portfolio allowed us to ramp up the five D&C rigs during the year and increase our downhole maintenance activity to deliver on our production goals. For the full year 2022, we are projecting approximately $235 million of D&C capital expenditures while maintaining oil production essentially flat entry to exit. And that's after adding back the impact from the current County EIR litigation delay, and taking into account A&D transactions from earlier this year. And while inflation has impacted our non-energy OpEx and CapEx costs and as a result, slightly squeezed our margins, we are still delivering on full year 2022 expectations on the current price deck. Francisco will describe this in greater detail. But as we have said, we anticipate long-term average D&C capital of approximately $300 million per year to keep oil production flat after adjusting for the inflationary pressures that we are seeing. We have a resilient portfolio that delivers consistent and predictable cash flow. Second, disciplined capital allocation. Until recently, we had a stated long-term capital allocation framework of recycling approximately 50% or less of our operating free cash flow to maintain our oil production, and then we would split the remaining free cash flow 50-50 between shareholder returns and investment in our carbon management business. Now that has significantly changed with our Carbon TerraVault JV with Brookfield. Because the JV is expected to fund the carbon management business by our farm-down of Carbon TerraVault into the JV and the 10-ton buy-in to these vaults by Brookfield, our carbon management business is essentially self-funding through the end of the decade if the JV is successful in its objectives. That means we can now focus our free cash flow after CapEx for shareholder returns, and after making limited investments in early-stage CTV storage vaults, as we've said previously, and that is our new disciplined capital allocation framework. In fact, through the third quarter, we have returned 105% of free cash flow through our share repurchase program and our dividend. And because we are further committing to shareholder returns, we are increasing our dividend by 66% to $0.2825 per share and increasing our share repurchase program by an additional $200 million for a total program of $850 million, and we are also extending the program through the end of 2023. In fact, if we complete our entire share repurchase program by year-end 2023 and include our fixed quarterly dividend, CRC is on pace for nearly $1 billion of total shareholder returns on a cumulative basis. Finally, we continue to advance and accelerate our carbon management business. Last quarter, we closed the CTV Brookfield JV, and we are now focused on execution and continue to see a tremendous opportunity. With the passing of the Inflation Reduction Act and the increase in 45Q incentives, we see a growing and expanding target market opportunity. For permanent sequestration, we see a growing set of new opportunities for Carbon TerraVault in the new energy economy, new counterparties in hydrogen and ammonia, renewable diesel. These are greenfield opportunities that we believe can fit within our economic type curve for CMB, our carbon management business, because they have lower cost of capture and can be constructed in close proximity to our storage vaults, which limits transportation requirements. While this target market opportunity is not yet defined as our existing sources in the state, many of the counterparties we have recently engaged with are part of this newly emerging economy and something we find very exciting. We continue to make progress and are advancing multiple CDMAs or carbon dioxide management agreements with our counterparties. These CMAs are detailed frameworks that address the key project terms, including floor space, volume commitments, economics, development milestones, facilities, and the like. The CDMAs are also subject to conditions and provide a useful roadmap to reach agreement on final investment decisions on an expedited basis. We remain confident in our goal of signing a CDMA by the year-end, putting us on track for the first injection by the end of 2025. On the permitting front, we expect to end the year with approximately 140 million tonnes of file permits. And while our previous stated goal was 200 million tonnes of permit on file by the year-end, we remain confident in our backlog of permits. The fact is, as we advance permits for permanent storage in constructive dialogue with the EPA, we are continuing to refine and define best-in-class permit applications, and the standards for best-in-class continue to increase in the level of detail and rigor, something we are keenly positioned to meet. That being said, we have a significant backlog of permit applications, but we are ensuring that we file permits at the highest quality while maintaining our credibility as a leader in carbon management. Our carbon management business was also bolstered by Senate Bill 905, which was focused on advancing and streamlining the process for permitting CCS in California. While the law itself can be improved with further details and clarifications, the author of the bill has acknowledged the willingness to work to improve the law further, and we look forward to engaging on these fronts. Given CO2 EOR was banned from Senate Bill 905, and the increase in 45Q tax credits, we are shifting our CalCapture project to permanent storage and continuing to advance the FEED study. We remain excited about the prospects of this project. So in summary, consistent cash flows, disciplined capital allocation with focus on shareholder returns and growing a carbon management business, that is how we are building a different kind of energy company. I'll now turn it over to Francisco for further details on our results, including how we continue to refine our portfolio.

Thank you, Mac. Our assets continue to perform well, delivering consistent and predictable results. Third quarter production averaged 92,000 barrels of oil equivalent per day, up 1% from the second quarter. Changes in our development plan and well mix in response to the current County EIR litigation and the heat-related electricity outages throughout the state impacted our quarterly production volumes. Yesterday afternoon, the court issued a favorable ruling lifting the stay in the current county EIR litigation. We expect the county to promptly begin processing permits in accordance with that ruling. From a commodity realization standpoint, CRC continued to benefit from strong realized prices across all three hydrocarbon partners. Our average realized price for oil in the third quarter after settlement payments on our derivative contracts registered at $62.45 per barrel. Third quarter NGL realizations declined from the second quarter, which were in line with seasonal pricing and expectations at $57.68 per barrel. California natural gas prices remained strong, registering five consecutive quarters of increases. CRC realized 109% of NYMEX after hedges at $8.58 per mcf. As we turn to the cost side of the business, we saw total quarterly non-energy operating costs rise by $0.77 per BOE quarter-over-quarter, mainly as a result of increased downhole maintenance activity. In addition, increases to natural gas prices drove energy-related operating cost of $1.63 per BOE, or 17% from the previous quarter. As California's largest natural gas producer, we are net long the commodity, which means that what we produce and sell is greater than the natural gas purchased for our operations. During the third quarter, CRC generated $234 million of adjusted EBITDAX and quarterly operating cash flow of $235 million, demonstrating CRC's significant cash generation capability. We remain disciplined and invested $107 million in CapEx, which is $9 million above the second quarter, mainly due to the addition of a fifth rig in the LA Basin. In the fourth quarter, we were temporarily shifting a rig from the San Joaquin Basin to our Huntington Beach field to conduct a six to eight-well program and to prioritize available permits on hand. CRC entered the fourth quarter with four drilling rigs, and we expect to exit the year with 94,000 BOEs per day in total production and 55,000 barrels per day of oil production. For the year, we are maintaining net oil production relatively flat entry to exit after adjusting for A&D activity, with approximately $235 million in D&C capital, below our stated maintenance CapEx levels. After funding our capital program, we generated $128 million of free cash flow for the quarter. Through the third quarter, we have generated $272 million of free cash flow. This provides another example of the financial results our business model delivers. And as Mac mentioned earlier, it provides ample opportunity to accelerate CRC's shareholder return strategy. This quarter, we are increasing both the fixed dividend and the share repurchase program. We believe this allows us to provide competitive returns, which put us in the top quartile of small and mid-cap peers from a fixed dividend standpoint. Further, we continue to execute on our stock repurchase program and have used $424 million of cash to date to repurchase nearly 13% of our shares outstanding. With the expanded and extended SRP program, we have a lot of dry powder left. We also continued to build our cash balance to nearly $360 million at the end of the third quarter, up from $305 million at the end of 2021, and we have a net leverage ratio of approximately 0.3x. Active portfolio management is a key pillar of CRC's strategy, just as we have focused on our core operations to optimize cash flow and leverage our asset position to develop Carbon TerraVault. CRC continuously optimizes and evaluates its assets as part of the value proposition. Many of our assets hold appreciable value beyond the use of oil and gas-producing assets, either through CCS or real estate developments. As such, we are evaluating a potential sale of a small parcel of land near our Huntington Beach field to test the real estate market and to optimize future plans for the larger strip. Looking forward to next year, we see a handful of items to keep in mind. First, consistent with our strategy, CRC will continue to advance operations for Carbon TerraVault. This may require some additional facility spend to prepare certain reservoirs to receive CO2 injection. As a reminder, we expect that the majority of these costs will be recouped through the $10 per metric ton buy-in through our partnership. Second, we will begin to see more commodity exposure in our results as our legacy hedges begin to roll off. This should exceed and offset inflation that we're seeing across several categories in our business. Third, as we have demonstrated this year, we believe that on average, over the next five years, drilling and completion capital requirements to hold oil flat require approximately $300 million per year. Our portfolio of assets allows us to deliver predictable results, which support our consistent free cash flow. Given our continued strong financial results and our limited NOL position, we expect to be a cash income taxpayer in the range of 15% to 20% of taxable income in 2023. CRC's outstanding total return profile, combined with a leading carbon management business, further reinforces the exceptional investment opportunity CRC offers as we create a different kind of energy company. Now I'll turn the call back over to Mac.

Thanks, Francisco. Before we conclude, I'd like to thank the employees of CRC. I'm sorry about that, I had the microphone muted. Before we conclude, and thanks, Francisco, I'd like to thank the employees of CRC for their tireless dedication as well as their safety and environmental stewardship. Nothing is possible in the results that we achieved without their work. Thank you for your interest in CRC, and thank you for joining us on today's call. We'll now open the line for questions, and I'll turn it back to the operator.

Our first question will come from Davis Patris with RBC Capital Markets.

It's Scott Hanold here with RBC. Just kind of curious now that the current county oil and gas permitting is kind of greenlit. Can you talk about how many, I guess, permits you have in there and we'll call it backlog? And how long do you think it's going to take you to get some of those? So ultimately, when do you think you can get kind of back on pace to what you view as the most optimized drilling program in 2023?

Scott, it's Mac. I want to flip this over to Shawn Kerns, our Chief Operating Officer. But look, it's late-breaking news, okay? And it's good news, and we're optimistic about what this brings to us. But I'll let Shawn tell you about some of the process that we're looking at from here.

Yes. Scott, yes, late breaking news, we're very encouraged by what we heard through the court's decision. As you're aware, we're having conversations with the permitting agencies about how they're going to restart in an orderly manner. So we've been engaged in conversations throughout the year, anticipating that this may happen. And so I think it will take a little bit of time to unpack the permitting backlog, but we're very, very excited about what this can mean for 2023.

Do you have a sense? I was kind of curious about your backlog.

Go ahead, Shawn, sorry.

Yes. We have a number of permits that are kind of in place and under hold. And so there's some conversations going of how do we get those restarted. And then we have a number that are just waiting on the permit system to reopen.

Scott, the way I’d say it is that there's a number of permits. It's not just us. It has created a backlog, and that has to be worked through, both through certifying under this EIR as well as going through the CalGEM process. But we remain cautiously optimistic that it will return to normalized activity in 2023.

That's good to hear. And as my follow-up, it was good to hear you kind of reaffirm your view that you hope to have an emitter signed up by the end of the year. A couple of things with that. First of all, are there certain things that we should look for as sort of steps that need to occur? I know there's an EIR in current county for 26R that I think we should be getting some kind of flow on soon. And then also, to the point of the slide that you all have on your presentation on Page 19, where you define those existing sources that can be greenfield projects, currently, I think a lot of those may not be in the LCFS-compliant molecules, but are you seeing any progress to kind of get that put into an LCF compliance bucket to even make them more enhanced opportunities?

Yes, there's a lot to discuss. As for the overall process, you mentioned 26R, and we have just completed a year in the permitting process. We've always stated that we anticipate receiving that permit by the end of next year, aligning with our two-year timeline. We're optimistic about this, and both the 26R permit and the A1A2 permit are progressing, along with our other permits. According to our timeline, we are aiming for an emitter contract, which we are currently referring to as a CDMA. If we achieve our goal by the end of this year, it positions us well for a final investment decision close to when we receive the permit. We are confident we can accomplish this. I believe what's exciting about the information you referenced on Pages 19 and 18 is the expanded market opportunity. With the emergence of the new energy economy, including hydrogen, ammonia, and ethanol, there's a lot gaining attention. This shift has been driven by changes in the Inflation Reduction Act, particularly the $85 for permanent storage, which has brought economically viable options that previously had limited capture capital into the conversation. Additionally, these projects can be co-located next to our sites, offering advantages in transportation and related costs. Would you like to add anything, Francisco?

Just to kind of build on that point, Mac. We have 47,000 surface acres in Elk Hills. We were one of the largest surface owners in the state. So it's a really good way to think about how to leverage our land position.

And Scott, regarding LCFS and the potential pathways, there isn't a recognized pathway for ammonia and hydrogen that I know of, although there is one for hydrogen related to fueling stations. However, if they are utilized for transportation fuels, it's possible to apply for a pathway, which would enable the stacking option as well. Additionally, I find it quite exciting that there are ongoing discussions about direct air capture in California.

Our next question will come from Doug Leggate with Bank of America.

This is Kalei on for Doug. My first question is a follow-up on the current EIR. My understanding is that when the ruling occurred in May, some of your permits were frozen. Can you discuss whether those permits are now viable again and what would happen to them if the opposition files an appeal?

Yes, Kalei, this is Shawn. Yes, those permits that were frozen in May are still viable. So they were just really pending the outcome of an EIR kind of CEQA notification. So you have some in the queue, some that are yet to be filed. But as a team, we've been thinking through different scenarios and planning for this event. So there'll be more conversations in the near future of how to get this restarted in an orderly fashion.

Got it. What happens in an appeal, Shawn?

The stay has been lifted, allowing the permitting process to commence immediately. However, the litigation is not fully resolved, and the original petitioners may choose to seek an appeal regarding the new M2 stay process. It's not certain that they will succeed in obtaining a further stay. From our perspective as litigation observers, both the county and the judge have carefully addressed all the issues raised in the first appeal. While we cannot guarantee future outcomes in the litigation, we remain optimistic.

Got it. So maybe if I could summarize, it sounds like you're not totally out of the woods yet, but it feels like the worst of the possible outcomes is now behind us or past that point. Is that fair?

Yes. Kalei, I would say, the indications we get right now is it's resuming. So the teams are meeting on how to restart permitting, and that's what we're going to be focused on.

Okay. My next question is on the step-back rule as it relates to the L.A. basin. As you assess that impact, can you talk about how you're thinking about the production cadence and the inventory depth of those assets? Maybe to add on, we came across the comments in an old slide deck presentation that stated that workovers in the L.A. Basin provided about 3,500 BOE per year in terms of production. So it seems like the impact, if it does affect the workovers, could be quite meaningful. How do you guys view the cadence?

Yes. On the 1137 again, it still has to go through a rule-making process there to fully kind of understand the impact. We've put out what we think preliminary the impact would be on certain portions of our assets. There's other areas of the field, it's a very large field, where you can continue developing or drilling from different locations. So it's kind of yet to be seen what the impact is.

And as you saw, Kalei, this is Francisco, we've changed our drilling rigs to come into this year to drill some wells in the L.A. Basin that we had this location identified as prime candidates for the beginning of next year. We're moving them into this year. As a result of that, they might be potentially impacted by setbacks in the future. So we're accelerating activity in that basin because of that reason.

Great. Francisco, maybe just to put a finer point on it, what do you see the inventory depth in the L.A. Basin? How long can you hold current production flat?

Yes, we are still assessing the impact. However, as Shawn mentioned, these are substantial fields with room for growth, and the setback does not affect the entire field. We are still analyzing the numbers and will need to wait for the final rules. We do have remaining inventory, and we will provide updates at a later date once we have more information about the inventory status.

Our next question will come from Leo Mariani with MKM Partners.

I wanted to follow up a little bit on the Brookfield deal here. So I think I saw in the release that you made some comments that you put a handful of maybe new projects in front of Brookfield. Can you provide any more color around that? And is there some kind of timeframe they have to kind of look at these projects and decide to move forward on them? How does the mechanics sort of work there?

We submitted a couple of projects, the A1A2, CTD2, and CTD3, to the joint venture as part of the structure. There are commercial terms that we haven’t fully disclosed, but there is a specific timeframe for them to respond. If they choose not to incorporate these projects into the joint venture or decide to defer from our perspective, there’s a mechanism in place that allows for some carry. Ultimately, they have the right of first offer to evaluate the projects until we reach final investment decision, after which a final decision will need to be made. At this point, we are in the waiting period and expect to hear soon whether those projects will be incorporated immediately or deferred.

Okay. And then also in your prepared comments, I think you said that it sounds like you're going to get Class 6 permits around 120 tonnes this year, and I think your goal was 200. It sounds like you come up a little bit short there, if I heard that right? Just any color around that? Are we just looking at maybe some minor delays? What are you seeing happening there on those permits?

I'm going to let Chris Gould jump in and explain because he's handling that process. But I would say in a simple fashion is that the stakes are being taken off at the EPA, and we've been building credibility all along the way with the quality of our permits. And so we want to make sure that we have the highest quality of permits. And so we're just not going to rush anything. But Chris, do you want to provide additional color?

Yes. I think that's right. We've always been committed to setting the highest standards. And given the previously limited amount of Class 6 applications before CCS has really come onto the scene here, it's not unexpected that the EPA is going to learn and adjust. And frankly, we appreciate the need to have the highest standards on projects of this importance. So we are well-positioned to keep our standards high, meet their standards. And we're talking about things related to data requests and additional requirements around the edges. But nonetheless, things that we want to be very deliberate, very thoughtful, and very careful about how we deliver these permits at the highest standards. So we remain on track for our eye set for 200 million tonnes of permits and to hit our 5 million tonnes per annum goal in 2027.

I wanted to follow up on the oil production. If I understood correctly from the previous comments, you expect an exit rate of about 50,000 to 55,000 barrels a day, which seems to be about the same as in the third quarter. I noticed in the press release you mentioned potentially losing another 1,000 barrels a day due to a reshuffling of permits and relocating rigs. Did I get those figures right? It sounds like you might be a bit behind on oil production because of these adjustments. Is that still a challenge? I would assume that if the ERR is not appealed and is fully resolved, this issue would be mostly resolved by 2023?

Yes. That's right. Leo, this is Francisco. The 1,000-barrel impact shown on Slide 10, it's a full-year impact. As we look at, okay, look back at the current county EIR delays and we'd want to measure, okay, how much we could have done if it wasn't for that litigation, it's about 1,000 barrels for the full year. Our accelerated numbers already take this into account. There's no other true-up changes. We just wanted to say, okay, this is the impact based on the litigation and expect to be back in full on a normalized basis in 2023.

Our next question will come from Nate Pendleton with Stifel.

For my first question, your Carbon TerraVault business, can you speak to the potential logistics your team is working through to move the captured CO2 to the planned sequestration sites and how transportation impacts your assessment of potential sources of CO2?

Nate, it's Mac. Yes, obviously, one of the things that we're talking about with this new energy economy is the ability to not have to move it very far. With respect to existing sources and being able to move, we've looked at things that are within close proximity, being, call it, a 30-mile radius. And those are longer term because you'd have to basically create a point-to-point pipe, if you will, because there's no trunk line here of CO2 movement. So it goes into our calculation as to what are the best opportunities, okay, from an economic standpoint because obviously, there's an economic cost of having a pipeline to connect source to sink. However, as we mentioned in these greenfield opportunities, you can site it right at Elk Hills, as Francisco mentioned earlier, you don't have a lot of piping to do. It's all in-field for all practical purposes.

Got it. And then as my follow-up, given your subsurface understanding and progress in the Class 6 process, can you help us understand how your position is differentiated for sequestration from a geologic perspective in the state, especially the reservoirs presented to the JV? And how widespread that opportunity is for high-quality sequestration across your acreage?

Yes. So we're positioned well, I believe we've talked about many times here, our subsurface expertise in the reservoirs that we brought forth thus far. It comes down to, we are one of the largest holders, if not the largest, of seismic data, 3D seismic in the state of California. So obviously, when you're characterizing these reservoirs, you have to know how they will act with CO2, and you need the data, subsurface data to be able to do that, which we have, we're the largest holder. That then translates into us being the largest, one of the largest depending on mineral and surface owners in the state. You put that together, and you combine that with the skills and expertise of a company that's been focused on California for decades, and that is where our competitive advantage comes into play.

Our next question will come from Eric Seeve with GoldenTree.

Congratulations on the favorable ruling in the current county EIR litigation. I understand you are still working through the permitting process with the regulators and your 2023 budget. My question is more qualitative since I know these matters are still in progress. If you can maintain flat oil production with $300 million of D&C CapEx, it seems to indicate a remarkable return on capital for the drilling program. What is your intent and capability regarding the drilling program in 2023? If you can achieve such an excellent return on capital, do you plan to expand? And do you have clarity yet on the permitting constraints? Could those be a barrier to growth?

Eric, it's Francisco. Yes, we're still working through it. We had multiple different variations of the business plan for next year, anticipating a favorable resolution, but also thinking about what happens if it doesn't come through, right? So we're looking at all the options. We're going to deliver an optimized plan next year. And we haven't come to a decision as to how many rigs and what the pacing of that is going to be, right? We're focused on finishing the year strong, focusing on accelerating some of these wells that we thought could be impacted down the road. So I think it's just a matter of we saw the ruling yesterday after the market closed, and we're working hard to provide more clarity.

Okay. Great. My other question is on the Huntington Beach asset. You guys mentioned you're going to do sort of an exploratory process with a small part of the real estate there. Just trying to get a rough sense of how big is that piece? And is it contiguous with the rest of it? I'm just curious how you sized it and how big it is and how you're thinking about that?

Yes, Eric. We have several properties that are promising for future real estate developments. This particular one isn't directly connected to our larger Huntington Beach area, but it's nearby, just a few blocks away, and is also beachfront property. We believe this makes it a very marketable asset. Currently, it is an oil field, but we will take the necessary steps to enhance its value as real estate. We'll proceed with that work. Like I mentioned, it is beachfront property, and I will send you some pictures for you to review. It's located right next to the oil field. It's 1 acre approximately.

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

Well, great. Thanks, everyone, for joining us, and we look forward to your continued support at CRC. Have a good day.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.