California Resources Corporation (NYSE:CRC) Q3 2023 Earnings Call Transcript

California Resources Corporation (NYSE:CRC) Q3 2023 Earnings Call Transcript November 4, 2023

Operator: Good day, and welcome to the California Resources Corporation Third Quarter Earnings Conference Call. [Operator Instructions] Please note today’s event is being recorded. I would now like to turn the conference over to Joanna Park, Vice President, Investor Relations and Treasurer. Please go ahead.

Joanna Park: Welcome to California Resources Corporation’s Third 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 about 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 may differ due to factors described in our earnings press 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.

Francisco Leon: Thank you, Joanna. CRC continues to demonstrate what it means to be a different kind of Energy Company. We’re executing on our low decline and high cash flow generating oil and natural gas business, increasing shareholder returns and advancing our leading carbon management business. We are doing this all while working to provide innovative energy solutions to help California meet its 2045 decarbonization goals. Cash flow, carbon and California are our core strengths, and our quarterly results demonstrate substantial progress on all these fronts. Starting with cash flow. During the third quarter, we continued to deliver strong results, producing 85,000 barrels of oil equivalent per day and generating $71 million of free cash flow.

We remain on track with our 5% to 7% entry to exit production decline expectation for the year and have progressed our business transformation efforts, targeting $55 million of annual run rate cost savings that are expected to lower our E&P business cost structure by approximately $2 per barrel. Nelly will expand on the cost reductions achieved to-date, our shareholder return progress and cover the key business drivers for 2024. Moving on to carbon. We continue to expand our reach and strengthen our role as the market leader for CCS in California. Our first-mover advantage is demonstrated through our multiple Class VI permit applications with the EPA. A recently published tracker by the EPA shows our leadership in Region nine with over 50% of all permits submitted to-date and show CTV I on track to receive the first draft classics permit in California by year-end.

Additional progress can be seen in our growing project queue as we develop pore space in other parts of the state. We are pleased to announce our own capture and storage project at CRC’s cryogenic gas processing plant at Elk Hills. This project will install new equipment to capture 100,000 metric tons of CO2 per year from some of our natural gas production through a pre-combustion separation process and permanently sequester the CO2 in our CTV I reservoir. We are targeting FID of this project during the first half of 2024 and first injection by the end of 2025. This project is co-located at Elk Hills with our CTV I CO2 storage reservoir and is our fastest track to CCS adoption and the first CCS cash flow in California. CRC expects to earn 45Q credits and other incentives and anticipates paying CTV JV an injection fee for CO2 sequestration services.

CTV JV’s economics are expected to be in line with previously announced storage-only deals with an EBITDA in the $50 to $75 per ton range. Further, this project will increase the operational efficiency of our cryogenic gas processing plant, which will benefit from improved propane recovery, higher production and reduce the carbon intensity of the electricity generated from the Elk Hills power plant, which, as a result, will potentially lower the carbon tax for the plant. Today, we have also announced a new Carbon Dioxide Management Agreement or CDMA with NLC Energy, an innovative renewable energy partner. CTV will sequester 150,000 metric tons of CO2 per year from a new renewable natural gas facility that will be constructed at our proposed CTV Clean Energy Park at Elk Hills.

Once online, CRC will have the option of utilizing this product to supply facilities at our energy park with decarbonized energy, or we can sell the RNG to the market. With this new CDMA, combined with our Elk Hills gas plan capture project, we now have reserved 57% of the pore space in our CTV I storage reservoir. The CTV Clean Energy Park at Elk Hills will provide unique advantages and benefits to industrial partners. The park provides greenfield projects with access to land and proximity to a favorable end-user market where we can reduce the all-in cost of production and effectively transport decarbonized products by conventional means, effectively creating a virtual CO2 pipeline designed to decarbonize Brownfield emissions by capturing the market for their products versus the CO2 at their facilities.

The proximity of CTV storage reservoirs to major demand centers in the Bay Area, Los Angeles and the broader Central Valley helped make greenfield projects competitive with great products that are transported to California from thousands of miles away. Furthermore, CRC and CTV get an added benefit of access to renewable fuels for use in our own processes to help further lower our carbon intensity while also providing development and employment opportunities to our local communities. And finally, our California positioning is a key advantage that enables us to develop energy solutions for the state’s future energy landscape. CRC has the leading permit application position, land and mineral ownership, strong partnerships and California expertise.

We control several key aspects and variables that allow CRC to derisk the new energy projects and enable commercial-scale CCS quicker than many others in the state or even the U.S. We are also well positioned as the largest natural gas producer in California. We believe low carbon intensity natural gas will play an important role in the energy transition. We want to grow our contribution of local supply by developing our inventory. As such, we have identified incremental resource of 1 TcF of natural gas in our existing fields in Sacramento and Western San Joaquin. We’re in the process of high-grading the inventory and finalizing plans to develop this resource. Further and to validate our low methane intensity positioning, we are pursuing third-party responsibly sourced gas designation for our current and future production, which we expect to have in 2024.

Over the past several years, CRC has primarily focused on developing our oil inventory. However, California’s gas market continues to experience significant volatility due to the reliance on imported gas from other states and aging infrastructure. This, coupled with strong expected demand through 2045, will likely lead to continued premium pricing relative to the rest of the country. Our teams are working on development plans to unlock CRC’s untapped natural gas potential to meet this need with local and responsibly sourced supply. At CRC, we’re determined to lead the energy transition. We are committed to improving our products and providing carbon management solutions that help enable renewable and replacement fuels. And now I’ll pass it over to Nelly to provide an update on CRC’s financial position and several important points on our preliminary 2024 financial and operational outlook.

Nelly?

Manuela Molina: Thank you, Francisco, and welcome again, everyone. Shifting to the quarterly financial results, we executed on our plan and delivered another strong quarter of free cash flow. Results were largely in line with guidance and we have modestly narrowed our full year 2023 guidance to reflect our operational results year-to-date. The increase in oil prices during the quarter meant production sharing contracts had a greater impact on CRC’s net oil production. Brent averaged $85.95 for the quarter compared to the price of $75.28 per barrel used to set guidance. The nearly $11 difference in price assumption contributed to a $7 million increase in cash flow, but also impacted oil production by 1,200 barrels down due to PSE effect.

We have auctioned nearly all of our business transformation initiatives and expect to see at least $55 million of run rate level savings beginning in 2024. Our work continues and we believe we can further identify opportunities over time. We expect to exit the year with a solid balance sheet and ample liquidity. To demonstrate our confidence in future performance and our commitment to shareholder returns, the Board has authorized a dividend increase for the third consecutive year. And as a result, we are increasing our fixed dividend by 10%, bringing our quarterly dividend to $0.31 per share. This reflects an annual dividend of $1.24 per share with an approximately 2.4% yield at the end of the third quarter stock price. Since year-end 2020, we have returned $736 million through dividends and stock buybacks while increasing our cash position by over $450 million.

Our share repurchases amount to 18% of the company’s shares outstanding at the end of the calendar year 2020. CRC has $1.1 billion share repurchase program in place with $497 million of capacity remaining through June 2024. In addition to our stock buybacks, we have delevered our balance sheet by repurchasing at a slight premium $35 million of our notes, reducing the principal amount of our outstanding debt to $565 million. Looking ahead to 2024, we anticipate an increasing level of drilling activity in the second half of next year. We have various paths to achieve this beyond the resolution of Kern County EIR. The first is by utilizing updated field-level EIR. The second is by pursuing natural gas projects within the Sacramento Basin. And finally, through developing a more robust inventory of sidetracks to access bypass hydrocarbons and new reserves.

CRC has considerable expertise in drilling sidetracks from existing wellbores. We have executed over 1,000 sidetracks from our THUMS islands, which target reserves from one of the largest oil fields in the U.S., our Wilmington field. CRC is committed to increasing its level of activity and the optionality we have for 2024 reflects the benefit of our diverse portfolio and extensive operating expertise. In addition to our increased activity set on the operations front, we have scheduled a four year major maintenance at Elk Hills power plant and one of our gas processing facilities at the beginning of next year, which will require a combined capital investment of approximately $34 million. This downtime is expected to reduce gas volumes by approximately 20 million cubic feet per day for the first quarter of 2024.

The Elk Hills power plant is a very important asset for us and for the CAISO Grid. CRC has consistently supplied both energy and generating capacity to the CAISO marketplace. In 2024, we have contracted an increase of approximately $45 million in capacity revenue, which will flow through our electricity revenue line. Increased capacity revenue is expected to offset both of these major maintenance activities. We continue advancing our strategy on both our conventional and energy transition business to be the energy solutions provider for California. Francisco, back to you.

Francisco Leon: Thank you, Nelly. As we look to 2024, we see a number of exciting catalysts for CRC as we remain disciplined and focused on building a different kind of energy company. Cash flow, carbon and California remain our core strengths. We continue to deliver meaningful value to our shareholders. We are producing some of the lowest carbon intensity oil and gas energy for the state and are helping California reach its climate goals through industry-leading carbon management solutions. Thank you for joining us on the call today. We’ll now open the line for questions. Operator?

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Q&A Session

Operator: [Operator Instructions] Today’s first question comes from Kalei Akamine with Bank of America. Please go ahead.

Kalei Akamine: Hey good morning guys. I’ve got a couple. So I apologize in advance. The first one is more of a housekeeping one in nature, though. I want to understand why there was a CapEx provision in the quarter. Presumably, your permitting constraints were already anticipated, but the market seems to be interpreting that maybe there’s a new message that the constraints have maybe gotten worse. So wondering if you can first clear that up and maybe while we’re at it, some early thoughts on 2024 could be helpful.

Francisco Leon: Yes. So the CapEx, there’s just — there were some delays in third quarter facility spend that we expect to finish here before the end of the year. So it’s really nothing more than timing on some of the facilities projects that we laid out. So I wouldn’t read too much into that. And in 2024, we’ve laid out some of the big catalysts that we see. We have — we’re still not ready to put out guidance for 2024, but there’s some important aspects to take into account as you model next year. First one is the business transformation work, cost reduction efforts, $55 million annualized run rate savings. The team did a phenomenal job bringing those in. And we effectively executed on most of that. And we’re not stopping there.

We’re going to keep looking at new ways of working together and reducing some of that cost structure, which we brought down by about $2 a barrel. We also have a resource adequacy contract around our power plant where we see an incremental $45 million of capacity associated with that plant. As a reminder, we — that plan makes on research adequacy about $50 million per year in 2023. So this is almost a doubling of that payment to be on standby for the grid. So we have some really exciting catalysts coming up next year. We also have a maintenance of the plant, which we want to make sure it’s running in tip-top shape. So we disclosed that as well. So we still don’t have any new information around permits. We still have a view that first half of the year, next year, you should assume a one rig program in the second half of the year is what we expect that to go back to three or four rigs, a little bit more normalized run rate in terms of drilling activity.

Kalei Akamine: Got it. That’s very clear, thanks. My second question is on natural gas. And I want to spend a little bit of time framing this out. So I apologize for the multiple parts. So I guess, first, the dynamics in California are obviously very tight. Just kind of looking at the chart, it implies that something has changed post-COVID. I guess, first off, can you help us understand what that change is? And then next, all activity has a value skill, right? So when you think about gas, at what price does it compete with oil and you can pick your oil price, maybe call it $80. And then when you think about this opportunity longer term and I think your slide on the balances actually frames this very well, California gas has a direct link with the Permian Basin, albeit that build-out is still taking place and there’s a couple of years before it really gets in the way.

But I’m wondering what you could do now today to sort of get ready for that opportunity? How much low friction growth do you have in the bag? And how do you think about the infrastructure constraints?

Francisco Leon: Yes, Kalei, I think you got it right on the framing. Just to underscore the California market dynamics, California needs more natural gas today. We import as a state over 92% of the gas consumed. We’re the fifth largest economy, a lot of industrial and commercial needs for the gas beyond residential and the gas is brought from other states. It’s not under long-term contracts. So the reason it comes to the West Coast is to find better pricing. And that better pricing might — now we’ll be competing with LNG export facilities built in other parts of the U.S. So there’s a big problem that California has and introduces big risks to baseload power. And our commitment in a number of ways is to find solutions from an energy perspective to the state.

And we have a lot of gas. We haven’t highlighted in the past couple of years, our gas resource, but we went out earlier this year, started looking at, okay, can we high-grade a number of locations that are within existing fields, that are near facilities, near customers and that’s the — today, we’re announcing the results of that effort. Also by making — pursuing RSE designation, we really want to highlight and contrast the gas that we’re importing. Not all gas is the same, gas comes from other basins that is fracked. And there’s more fugitive emissions in other states. You want it to be California-produced and we want it to be CRC produced. So we’re excited about the prospects of being there in the very, very near term. We’re not ready to talk about economics.

But as we’ve laid out, the structurally — there’s a structural premium to natural gas in California, which we expect to persist for years to come. And having that local resource that can contribute to the needs of the state is going to be critical. So our positioning is very strong and our ability to make good returns for the shareholders is going to be right on par with oil. This doesn’t mean that we’re not looking to drill more oil wells. We’re convinced that low carbon intensity oil and gas will be here to stay for the long run in multiple decades. The state needs the oil and the gas and we can provide both. We’re just providing the — we’re bringing forward the gas side of the equation that we really haven’t talked about before, but I feel really good about the potential of our assets.

Kalei Akamine: So I guess just to clarify, the change in California is just greater power demand. And then could you address the infrastructure constraints piece? How much can you grow without spending additional material capital dollars on infrastructure today? And how much do you think you could spend over the next few years?

Francisco Leon: Yes. It’s too early to put it into numbers. But just to highlight the resource base a little bit more, when we talk about Western San Joaquin, that tends to be wet gas, primarily at Elk Hills and Buena Vista. So fields that already have a lot of the facilities infrastructure in place, it’s about drilling for those wells. A little bit deeper formations, but known to us being very productive for a long time. So it’s refocusing on those gas wells. We have the added benefit of generating NGLs from that production. As you move north to Sacramento, that’s dry gas. So very limited gas processing requirements, already a lot of infrastructure in place. Markets, proven markets out there. So it’s also more about getting the permits and going after drilling.

We still need to decide what pace we want to develop this. We’re still moving towards putting economics into the projects and that we can disclose, but we feel, again, very excited about the positioning. What’s changed in California, a state of short gas, but consumes it in big quantities, I think the — what you saw change is started — I mean, we talked about it earlier this year, $47 per Mcf of natural gas pricing here in the state whereas the rest of the country was around $4. So more than a 10x premium in a state that decides to import gas. 92% is imported. You better have a gas storage solution in state. Otherwise, you’re going to be very susceptible to market shocks and volatility and aging infrastructure. So, I think that was a wakeup call that we need more local production, that we need more storage.

The storage fields in California just got expanded in terms of capacity that you can store. That should help moderate at least this winter, some of the prices. But we’ll see. At the end of the day, the demand is still very strong. And I think, again, it’s a realization that being isolated and dependent on imports, not having that energy security is a risk and a problem for the state.

Operator: Thank you. And our next question today comes from Scott Hanold with RBC Capital Markets. Please go ahead.

Scott Hanold: Yes, hey thanks. When you were in your prepared comments talking about the Kern County EIR and looking at the second half 2024 and doing some more drilling, you kind of mentioned, obviously, you’re potentially more drilling in the Sacramento Basin for gas sidetracks and then obviously exploring the field-level EIRs. With respect to like sidetracks and I mean, do you need to get permits for that? Or is the permitting process a little bit different?