Hello, and welcome to the California Resources Corporation first quarter earnings call. All participants will be in listen only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star then one on your touchtone phone. To withdraw your question, please press star then two. Please note, today's event is being recorded. I will now turn the conference over to your host today, Joanna Park, Vice President of Investor Relations and Treasurer. Please go ahead, ma'am.
Thanks. Welcome to California Resources Corporation's first quarter 2023 conference call. Participating on today's call are Francisco Leon, President and Chief Executive Officer, as well as the entire executive 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 first quarter results. We've also provided information reconciling non-GAAP financial measures discussed to the most directly comparable GAAP financial measures on our website, as well as in our earnings release. Today, we are making some forward-looking statements based on current expectations. Actual results could differ due to factors described in our earnings release and in our periodic SEC filings. As a reminder, we have allotted additional time for Q&A at the end of our prepared remarks. We ask that participants limit their questions to a primary and one follow-up.
With that, I'll now turn the call over to Francisco.
Thank you, Joanna. Good morning, everyone, and thank you for joining us. I am very pleased to be here talking to you today as CEO of CRC as we continue to build a different kind of energy company focused on generating the highest cash flow from our low carbon intensity assets and advancing our carbon management business. My remarks today will focus on three key areas. First, our record financial performance in the quarter, which was driven by a strong operational execution and leading natural gas position. Second, the progress we made advancing our plans to reposition the business to unlock shareholder value. Finally, the growing strength of our carbon management business as we continue to take steps to enable California's clean energy goals. Turning to our quarterly results, we're off to a great start for the year.
Record financial results showcased the quality of our low decline assets and the benefit of a diverse hydrocarbon E&P portfolio. We successfully maintained flat oil production quarter- over- quarter on $31 million of drilling and completions in workover capital. We drilled 9 wells in 2 sidetracks and ended the quarter with 1 drilling rig at Wilmington and 39 maintenance rigs. Our reservoirs offer stack pays, which means we can recomplete and sidetrack existing wells to add pay at attractive returns. This type of activity is highly economic and allows us to bring on production at a fraction of the cost of a new well. For the balance of the year, we intend to increase our workover activity and execute a 1-rig drilling program. We have secured all the necessary drilling permits for our 2023 capital program and are working to build incremental permit inventory for next year.
Another highlight for the first quarter was the California commodity markets. The state operates as an energy island, California realizations reflect the demand for energy and tend to be higher than national benchmarks. Both NGLs and natural gas realizations were above expectations, and crude realizations were within guidance. To be more specific, NGL and natural gas realizations benefited from colder than normal weather and the lack of in-state production. In the case of natural gas, our realizations for Q1 were approximately 630% of NYMEX. As a reminder, California imports approximately 90% of the natural gas consumed in the state. When demand exceeds local production plus incoming supply, the market relies upon natural gas and storage to make up the difference.
In the case of January, and to some degree, February, California found itself with limited natural gas inventories and storage and limited local supply of production. As the state's largest natural gas producer, our roughly 12 Bcf of production was available to meet the needs of the state. These factors helped drive record results and facilitated another quarter of shareholder returns. The company generated pre-tax free cash flow of $263 million, of which approximately $79 million was returned to shareholders. This consisted of $20 million in dividends and $59 million in share repurchases. Since implementation of our share repurchase program in May of 2021, we have bought back approximately 15% of the company's outstanding shares.
Combined with our fixed dividend of $1.13 per share, we have returned back to shareholders approximately 22% of our current market cap in less than two years. We intend to continue with our active shareholder program and have $567 million remaining under the total board-approved $1.1 million authorization. We also ended the quarter with robust liquidity of $931 million, including $477 million of cash on hand. CRC is committed to maintaining a very strong financial foundation, and we will continue our focus on achieving greater financial flexibility and commitment to shareholder returns.
As we look to the balance of the year, we have increased our 2023 after-tax free cash flow guidance by 8% to $415 million at the midpoint of our range to reflect our strong first quarter 2023 performance. This is partially offset by lower commodity pricing assumptions for the rest of the year, timing of capital, changes to working capital, and higher cash taxes. We have provided detailed analysis about our quarterly financial and operational results on our 2023 guidance in the attachments to our earnings release and in our slide deck. Turning to our continued strategic realignment of the company's operations and structure, we announced yesterday the appointment of Nelly Molina as CRC's new CFO effective May eighth. I could not be more excited to welcome Nelly to CRC.
She is a seasoned energy executive with more than 25 years of corporate finance, capital markets, and project financing experience, and brings an extensive background in the development of energy infrastructure projects in the natural gas and power sectors. Nelly joins us from Sempra Energy, where she most recently served as Vice President of Audit Services and Vice President of Investor Relations. I look forward to introducing her to you in the weeks and months ahead, and I know we will benefit greatly from her expertise in navigating today's evolving energy industry. In addition to the changes in leadership, we're also focused on pursuing operational excellence. As mentioned last quarter, we launched a cost reduction and business transformation initiative to align with our activity levels and build a more efficient organization.
We are targeting annualized run rate cost reduction goal of $25 million-$50 million to be implemented by the end of this year. We have identified $20 million of reductions to date and are working to expand the scope and scale of cost reductions efforts during Q2. Another key element of our plan is to achieve increased financial flexibility. This quarter, we have successfully reaffirmed our $1.2 billion borrowing base and amended our RBL facility to increase the duration and improve the terms. These changes will enable us to make additional investments in our carbon management business and further support our shareholder return program, as well as help pave the way for a potential separation of the carbon management business. We will continue to evaluate ways to increase our financial flexibility as the year progresses.
As we discussed last quarter, we're evaluating the separation of our carbon management business, Carbon TerraVault, as part of our ongoing efforts to optimize the value of our portfolio. Outgoing CRC CEO Mac McFarland is serving as the chair of the board of Carbon TerraVault, and we have been working closely together to determine the best path forward. The carbon management business is still in the early stages, and there are important milestones that we're working to reach before initiating a potential separation, such as an EPA Class VI permit approval, project FID, line of sight to first CO2 injection, and first cash flow, among others. We're continuing to build out the leading carbon storage business in California.
In the first quarter, we have made further progress by signing 2 new greenfield storage-only CDMAs, a green hydrogen project in the Sacramento Basin, and a renewable DME project at our Elk Hills Net Zero Industrial Park. These projects target 140,000 metric tons of CO2 injection per annum on a combined basis. We now have 4 CDMAs in place for a combined injection rate of 610,000 metric tons per year, representing reservations of about 12% of our pore space. We submitted Class VI permit application for a new development area, which we call CTV IV, for an additional 34 million metric tons, bringing CTV's total potential permitted storage to 174 million metric tons, or over 85% of our stated 2027 target of 200 million metric tons.
The CTV team continues to file permits for additional vaults across California to expand our leading position in the state. We are targeting receiving our 1st Class VI draft permit from the EPA for CTV I by the end of the year. In summary, we're excited about our continued progress in executing our strategic repositioning. In the first quarter of 2023, we had record financial performance, which allowed us to increase our full year guidance. We also advanced our cost-cutting initiatives and continued to reposition our business to unlock additional shareholder value. Finally, we further expanded our California leading carbon management strategy to support California's clean energy goals. Thank you for joining us on the call today. We'll now open the line for questions. Operator?
Yes. Thank you. At this time, we will begin the question- and- answer session. To ask a question, you may press star then one on your touchtone phone. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star then two. At this time, we will pause momentarily to assemble the roster. The first question comes from Scott Hanold with RBC Capital Markets.
Thanks. Good morning or good afternoon all. you know, my first question, it may feel like a little bit of a multifaceted one, but let me try here. You know, you've made progress on obviously, you know, starting the, you know, signing up the new CDMAs. How do you. More of those, I guess, recently were some of the lower capital intensity agreements. How do you think about these, excuse me, the mix of these projects going forward? Do you want to see some more of the kind of the front-end projects to increase the scale of EBITDA?
Do you feel, you know, confident that I know you said you're only about 12%, you know, on total reservations right now, but do you feel confident in the larger quantum of getting that storage permitted, so that scarcity factor isn't really as much of a concern? I know it's kind of a bit of a multifaceted question, but, you know, ultimately, I'm just trying to think about, you know, the high relative EBITDA opportunity and if a potential offset would be exercising some of the equity stake options.
Hey, Scott. Yeah, we're focused on both. Greenfield for CDMAs on greenfield is really good progress. No question about that. You have the tailwinds from the IRA, increase in the incentives. Definitely that's helped put projects together. It also helps that we can co-locate these greenfield projects at Elk Hills and in the Sacramento area. It's an easier process to get to a CDMA. Existing point sources, we talked about it before, you're still going to price discovery, right? How are the credits shared across the value chain? You also have to solve for transportation. How do you move the CO2 across the state?
We know there's a lot of interest in Sacramento to ensuring that CCS is successful. Everyone understands that transportation is part of the equation. We're hoping there's some uncertainty right now. We're hoping that uncertainty is clarified in the near term. I am confident we're gonna be delivering both projects. Certainly the going to point source, the ability to deploy more capital, but also increase the EBITDA is something that we're focused on with our partners in Brookfield. We'll do a little bit of both. I think if you looked at the types of projects that we see in the queue or the types of projects that we're reviewing, you see a pretty good mix between them.
It just so happens as we're kind of building kind of this new business live in front of everybody, that the first four projects are greenfield, that's not. This business is not gonna be exclusively for greenfield. We'll bring some point source projects into the fold, hopefully in the near term.
Yeah. How about the exercising of the equity options on those?
You know, we reserve the option to invest into the equity of all four projects and started with Grannus and Lone Cypress that have been in the works for longer. We're reviewing not only the cost profile of those businesses, but the market in a lot of cases. Like hydrogen, there's not a very well-developed market quite yet, but there's a lot of interest. That also requires understanding the offtake contracts and the depth of the market and where to best place the hydrogen and the ammonia. Ammonia is already tied to a co-op in Sacramento. We're evaluating both. We like to have a decision this year on Lone Cypress in particular. That's gonna be the first project we're reviewing the equity.
There's a lot to do, but we're excited. We think these markets will develop nicely in California. There's a lot of support, again, by IRA. Hydrogen has 45 E that supports it, but we're seeing a lot of potential demand for the product. Both Brookfield and CRC have retained that ability to invest in the equity, and it's something that gets us very excited about participating in these new energy verticals.
No, I appreciate that. This sounds like you're putting a lot of depth into thought of around this. My follow-up question is on those cost savings you talked about. Can you give us a little bit of color on, you know, I think you said $20 million. There's kind of a line of sight on it right now, but what kind of specific cost savings are you really seeing, and what are you targeting? I'm kind of curious with using, I guess that A&M service. You know, what specifically, you know, was the reason of going, like, outside to have somebody come in and do that versus, you know, what, you know, doing stuff like CRC.
What, you know, what can't you do on your own that they can come in and help you with?
Scott, we were looking for ways to change how we work. CRC does a lot of things really well. It's a company that has been operated in under the strictest regulations, pretty much in the U.S. There's a lot of, the team works well. We are all have very high operating standards. We need to change how we work. We need to bring cost in line with activity levels. That requires a kind of a business transformation, not just a cost-cutting exercise. We need to question everything. We need to question how we're organized, we need to question what we prioritize and ultimately look for to make decisions to take some cost out of the system.
You know, the team got to work right away, after we came last quarter and described this initiative, in $20 million in a couple months. It's a pretty good win. We're trying not to... this is not a deferral, this is not Removing one time cost. These are run rate savings. These are permanent savings that we wanna take out of the system. We're evaluating contractors, we're evaluating contracts, chemical contracts, for example. How do we use different, how do we ultimately make decisions across the board? We're questioning everything, right? It's a good opportunity for a refresh. It's a good opportunity to say, okay, can do we do better and drive that culture going forward. We brought A&M, they're a very good team.
Two, we wanna get that external perspective. California tends to be isolated from what's happening in the rest of the U.S. We wanna bring best practices, and we want their help assessing and ultimately accelerating some of these cost saving efforts. We've taken a lot of cost out of the system historically at CRC. The next phase is really one that requires kind of a transformation of how we work, and we felt it was best done with some outside help. I'm, you know, very focused on these cost reduction exercises and we're getting a lot of great organic support from the team presenting new ideas on how we make this company better.
Got it. Appreciate it. Thank you.
Thank you.
Oh, thank you. The next question comes from Doug Leggate with Bank of America.
Hey, good morning. This is actually Kalei on for, well, for myself. Francisco, following your announcement last quarter regarding a potential separation of CCUS from E&P, we received a lot of inbounds on the power plant. What's the valuation? What's the G&A burden? What does the power market look like? Could you comment on whether it's core to your oil and gas business or whether it's a better fit for a standalone CCUS business, noting that there are potential synergies with CalCapture? Maybe to add on here, I remember a few years ago you guys did that deal with Ares. Therefore, if you did something with the power plant here, it wouldn't be the first time. Even in that deal, there was an option to buy it back after a period of time.
That suggests to me that there is maybe some constraints in how you think about structuring it.
Hey, Kalei. Yeah, I mean, I think we have a big advantage in the state by owning a power plant at Elk Hills. It's been truly a great asset for us, and it really helps us stay away from the grid, at least for part of our fields, which helps us bring down cost alongside with it. The plant delivers about 1/3 of the power goes to the oil field, and 2/3 gets sold to CAISO and utilities. It's been, it's been a good, profitable asset for us historically.
We have the opportunity to make it better, to be able, with a capture system, be able to deliver net zero power in a state that's really hungry for these types of offerings. We're evaluating where this asset fits best on a go-forward basis. I mean, I think the prospect of having net zero is appealing to everybody, but you also have to be able to undertake CalCapture, which as we talked about in the past, it's a capture system on a low concentration stream of CO2, which is going to be on the higher end of the cost spectrum, right? How do we make that investment? How do we finance that type of capital call? Ultimately, where does the asset belong?
Is it more on CRC or is it more on Carbon TerraVault? Those are the sort of things we're working through. We did release the collateral from the banks through the RBL, and we're looking to have the flexibility so that we can put that asset to work in the best way possible. Right now, the way I see the power plant, even though it's a great unique asset in the state of California for E&P companies, we see that asset trading at, you know, as an E&P multiple, right? Having a ability to see the financials, right?
The things, some of the things you're asking, having the visibility to fully showcase how good this plant is and how it can get better by making it a net zero power plant, I think it's gonna be a great value add and a way to unlock value. We're working through it. Nothing definitive. Hopefully, at least I gave you some of the groundwork here as to as we're working through these types of assets and where do they best fit if in case we do separate the businesses going forward.
The quick follow-up there. I hope you don't count this as my second question. There was a FEED study that was performed about 2 years ago. For whatever reason, you guys are performing a second FEED study. Can you give us an update on where that, what the status is on that FEED study that you're currently performing?
We'll see if it's your second question or not, depending on what the next one looks like. No, I'd say it's a great question, Kalei. We did a FEED study with Fluor a few years ago, and now we're doing a second FEED study with NextDecade. You have to understand the reason we have two FEED studies, and we're gonna continue looking at the cost, is that there hasn't been a capture system put into a natural gas power plant facility of this scale anywhere in the U.S. before. We wanna make sure that we have the costs right. I mean, the technology is really not, it's not a new technology. It's not something that concerns maybe the scale to us. What it's really trying to drive that cost down.
We, you know, we've had a lot of inflationary pressures over the last two years. We wanna make sure it's a project that not only delivers that ability to reduce that CO2 emission footprint, but it's also a profitable project. What you're gonna continue seeing from us is really working through that cost profile. How do we best set up, how do we finance these power plants so that we can make CalCapture happen. We're targeting FID next year, right? We're working through it. We're soliciting input. There's a lot of companies that are bringing new ideas, bringing new technology and looking at the supply chain differently.
We're gonna look to award the project to whoever can deliver the best price and ultimately get us a project that we feel comfortable that can be executed on. We're working through it.
I appreciate that. My real second question is on natural gas. Obviously really big numbers this quarter, hoping that you can help us understand how to model your exposure. Is it bid week or is it spot? Is it Citygate or is it SoCal border? I think any help here would be appreciated because given the tightness in California, it seems like this could be reoccurring.
Yeah. I'll start and then I'll turn it over to Jay to give a more in-depth answer. We do feel this is a California through the regulation and through the penetration of renewables that gas is gonna be absolutely needed, not in the near term, but as we go forward as base load. We're well positioned as the largest natural gas producer in the state, and now we see these spikes happening more and more. Definitely, you know, it's something that the state as an energy island has kinda decided that's w hat we're gonna be. These, these natural gas assets that we own through both power and owning, the Sacramento Basin and the.
Buena Vista areas all have gas in the right places, gives us a lot of flexibility when we see this, these market shocks to be able to reposition our assets and go out and try to deliver that gas for the state. Maybe, Jay, if you can cover a little bit of the pricing around that.
Yeah. Let me kind of touch on the basic precept here. You know, more times than not, we're gonna find ourselves looking to be close to, if not at, the first-of-the-month index. We'd prefer not to carry a lot of gas into the daily market during any particular month. In advance of that bid week cycle or during the bid week cycle, we may take some limited fixed price positions that just simply seem frankly attractive given the circumstances that are taking place. I mean, our gas for the most part, is produced relative to a SoCal border index. As you may or may not be aware, we maintain long-haul transportation from the field on Kern River. We've got a fairly significant position on the SoCalGas system in terms of BTS.
You know, this is kind of where the semantics get a little bit goofy, I'm afraid. Some people call this trading, we call it marketing and asset management. The fact is we keep a set of tools around that work very well together. We've got gas production in some of the most liquid points in the state. We maintain that transportation, as I mentioned. We've got some of the most dependable generating capacity in the state, and we've got really the right folks around to make those decisions. When the market needs power, we move more gas to the power plant. When the market needs gas, we're able to bring more gas to market.
In general, I think you should probably look at any particular monthly cycle, look for the first-of-the-month index reflective of kind of a 80-20 SoCal Border and PG&E Citygate index.
I appreciate the thorough response.
Thanks, Kalei.
Thank you. The next question comes from Leo Mariani with ROTH MKM.
Wanted to, just delve in a little bit more, to a few of the numbers, you know, sort of around the quarter. You know, looking at CapEx, you know, is quite a bit, you know, sort of below guidance. Just to follow up on the gas price question. I guess when I looked at sort of, you know, SoCal border, Citygate, didn't really matter. I had a hard time getting to the $21.50 that you guys put up, you know, in the quarter. Maybe there's kind of some other semantics around the pricing or some other local markets that are kind of less visible, you know, outside of these indices that get reported by you know data agencies like Bloomberg or sort of whatnot that drove that.
Any more color on how do you get to the $2,150? Then again, just, you know, CapEx nicely below the guide here. Any thoughts on that?
Hey, Leo, that sounds good. Let me answer the CapEx question. You know, we went through 4 months, and I know it's hard to believe, of really bad weather in California. A lot of wind, a lot of rain, snow, that affected our operations. The team did a phenomenal job executing through that. You don't see a lot of impact in production. In fact, we outperformed on production expectations. It did delay some of the capital activity that we had planned. We do, you know, as we step down, we're now running 1 rig in the Wilmington field. We'll continue that throughout the year. What you should see is a step-up in capital workover activity for the rest of the year and as operations get normalized.
In terms of the gas pricing question, again, I'll turn it over to Jay for an answer.
Sure. As I mentioned kind of a couple moments ago, we did execute a few opportunistic, fixed price trades during the, during the bid week cycle. One thing that kind of gets lost, and I'm trying not to get a whole bunch into the weeds, when it comes to natural gas pricing, is when you see an index posted, natural gas doesn't necessarily trade on the physical market at that price. There are times of the year when it trades at a discount, and there are times of the year when it will trade at a physical premium. For example, to get physical gas at SoCal border, you may end up paying more than the border price. You'll buy physical gas in Index Plus number.
We had a fair number of Index Plus numbers transacted in our book for the months of January and frankly, February. Both were very strong. A lot of different points in the Western gas market, physical gas was trading at significant premiums to the individual posted financial indexes. Combine the opportunistic trades, the limited number we had, and that small variation, and I think you get there pretty quickly. Again, I'm not sure Q1 of 2023 will be representative of what we see for the balance of the year. I think you're gonna find that our gas prices are probably in large measure, excluding the fact that we've got a shortage of gas in inventory right now, I think you're gonna find them more reflective of the national gas price.
If I can add one thing. You know, we have a fantastic marketing and trading team, and then we have a very diversified revenue stream. Last year, we highlighted the NGLs. The NGL barrels were trading higher at some point in the year than our after-hedge oil barrels. This year's natural gas, there'll be times where it's electricity. Really feel good about that diversification that we built for CRC, and then giving the team an opportunity to manage that to make our most highest return decisions. I think we're set up for success here in the long run.
Okay. That's very helpful. Makes a lot of sense. Just kind of sticking with some of the numbers on the quarter here. Looking at your San Joaquin Basin gas production, it was down around 10 million a day this quarter versus last. Historically, that gas production's been pretty steady, doesn't really move around much, you know, sort of by quarter. Was there any, like, maintenance or downtime, or was this more of you guys maybe directing more of that gas to the power market and kind of less to the volumes, you know, sort of sold market here in the quarter? Just looking for any color on that.
No, the gas, Leo, really was impacted by weather. You know, you had facilities down because of the high winds and that affected our gas production in particular. That's really what happened in the quarter. We do have some maintenance projects throughout the year, but I think Q1, you can attribute most of that change to weather.
Okay. No, that's helpful. Just on the regulatory front here, you know, kind of any update on just the general permitting situation for oil and gas drilling permits in California. I know the Kern County EIR is still a way away in the decision, but, you know, apart from that, can you maybe just talk to whether or not permits are kind of coming outside of those Kern County areas?
Yeah, no update on the appeal around Kern County EIR. That's still ongoing. As we said before, we expect that to take some time. We are getting work over permits in Kern County and throughout the state, so those are flowing. We also filed a CEQA for 3 of our largest fields in Kern County to be able to do field level EIR. That gives us an alternative to be permitting back in the San Joaquin Basin in Kern County. We're building inventory outside of Kern, looking at our gas wells in the Sacramento Basin, and continue to get, you know, looking at the South and LA Basin as well.
As we said before, we have all the permits in the drilling campaign that we need for 2023. Really all we're doing right now is creating as many options as possible for 2024. Working through those, but again, no permits in Kern County yet other than work over permits, which are flowing.
Okay. It sounds like, generally speaking, you guys are able to probably get permits outside of the Kern County EIR. That's something you can still obtain here?
Yeah. I mean, Like I said, we have all the permits that we need in Wilmington, so that's in good shape. We do expect to get permits outside of Kern County.
Okay. Thank you.
Thank you. The next question comes from Nate Pendleton with Stifel.
Good morning. Congrats on a strong quarter. Regarding trucking CO2 at your Carbon TerraVault site that you alluded to earlier; can you provide any details around whether you're exploring the use of low emissions trucking at other sites? Are there any noteworthy cost or throughput implications that we should be thinking about?
First of all, on the greenfield developments that we co-locate at oil fields, we'll use our internal gathering lines to be able to move CO2. That's the first option, and that's what we're focused on. To the extent that we're now going into areas that require trucking, yes, we're looking at low emission vehicles, whether it's hydrogen and fuel cells or other options. That's very much part of the part of the plan, right? Ultimately, these projects need to provide across the board low emission solution in order for them to work and to get the full benefit of the credit. Definitely thinking through that as we move CO2 across the state, and as we wait for the uncertainty on pipelines to be resolved.
The first order of business and how we're gonna get CO2 injection much quicker is to be able to co-locate the plant on top of our reservoir and just deal with behind the fence gathering systems.
Great. Thanks. Stepping back out a bit, over the past few months, we've been tracking an increasing number of Class VI permits, both in California and across the country. At a high level, can you speak to how Carbon TerraVault is differentiated in this growing industry and how you plan to capitalize on your first mover advantage going forward?
Absolutely. We filed our first permit in August of 2021, second permit in November of 2021. When we talked to the EPA at the time of filing, they said it's gonna take them 18-24 months. Really, you know, this new era of Class VI permits was just starting a lot of uncertainty in the process. We learned a lot throughout. I think the EPA has as well. What we know is there's a high rigor on all fronts. Technically, commercially, that's expected from anybody that submits an application. We've seen some permissions, some permits being withdrawn. You know, I think we have everything that it takes to have our permit come in this year. We've done a lot of work technically.
We have seismic. We have a good understanding of the reservoir at Elk Hills. Our team has worked diligently to position the permit in the best way possible for the EPA. We're working with having support from local communities in Kern County to bring these projects forward and have really good dialogue with the EPA. You know what? I think we're in the running to be one of the first permits by the EPA. I think we're right there. Again, given the dialogue, given the progress that we made, I feel very good that we're gonna have the permit this year. You know, the key is that first permit is a big catalyst.
Catalyst to more projects, more emission sources coming together, to really giving the market transparency as to what happens, what happens next. I think what we heard through multiple channels is that Carbon TerraVault is putting some of the best, you know, best positioned permits out there. Again, we're working well with the EPA to try to get that to the finish line.
Got it. Thanks for taking my questions.
Thanks, Nate.
Thank you. Once again, please press Star then 1 if you would like to ask a question. The next question comes from Noel Parks with Tuohy Brothers Investment Research.
Hi. Good morning.
Hi.
Just a couple of things. They're sort of high-level questions, but I'm just thinking about, I guess, overall, looking at some of your... or hoping to get some thoughts on where you might see, in the carbon business a greater degree of vertical integration over time. Of course you announced today a couple new storage-only deals. Clearly you like the margins from that business line. You've given us some guidance on what those economics might look like. Where would you... I mean, do you see any low-hanging fruit as far as over time bringing more project development or even, you know, construction activities in-house over time?
The way the early projects are unfolding, is that pretty much the sort of ideal, you know, I guess, burden of risk reward that you'd be looking to achieve?
Yeah. A lot in that question. Let me try to address it. On these greenfield projects, as a reminder, we see pore space as being the scarce resource in the state. You know, contrary to many other parts of-
Right
W here, what we've said is our type curve is gonna deliver between $50 and $75 per ton for storage-only deals. All 4 CDMAs that we signed today fit within that type curve. Not only are we validating the pore space scarcity point, but you have third parties that ultimately work the economics through and value that storage and pore space. It's difficult to say where we're gonna have the most vertical integration, but as we take, you have the option to invest equity into these projects, we're learning a lot, right? We're not a hydrogen company, we're not green or blue, we're not ammonia companies.
We're trying to understand the business model and if there's a way to add value and there's a way to make good returns, it's something that we'd like to do. We do see integration happening not only with ourselves, you know, as you bring power, you can sell power, sell natural gas into these projects and provide land. We're seeing integration even amongst the partners that we're bringing together as we develop these big industrial centers, net zero industrial centers like we have at Elk Hills. It's hard to say if we need to bring these projects in-house.
Right now we're looking to partner with really smart people that have done this before, and they're just looking to develop a market in California, which seems to be the most attractive to get these green projects underway. I don't know yet about in-house projects. We'll see more squarely at that. It's a difficult question to answer, but I do know that we're seeing the California energy sector in a very different light as we get exposed to all these projects coming through the door.
Great. Thanks. Maybe sort of continuing along similar lines of discussion, the net zero industrial park, could you maybe talk about the business development process for that? We get some sense of some of the building blocks from, you know, the announced projects. I'm just curious about, you know, criteria of, you know, what sort of projects maybe you are eager to get more of or would rule in as opposed to maybe types of projects you would be more inclined to rule out for, you know, for the industrial park setting.
Yeah, no, I mean, I think we have a lot of conversations were ongoing. I think you're only able to see the 4 that we brought forward in terms of CDMA, where we're evaluating multiples. Of what we brought in as we talked about before, we feel we're oversubscribed. That means we're talking to many more parties than we have capacity for. There is a selection process, right?
You know, obviously, when we're dealing with people that have the credibility, and that can bring these projects forward, where we can get permits, locally as well, and that these projects are ultimately gonna have strong long-term offtakes to be able to lock in returns and ultimately do incremental financing. There is a selection process, right? That's why, you know, we moved. We're not doing MOUs just for the sake of announcing that we're making progress. We're really focused on conditions precedent.
We're finalizing contracts that have much more meat to them, because we wanna make sure we are building this, all these projects that need to be able all to come together so that we can get to our injection targets by 2025 and then 2027, 2028 for the 5 million tons. We are selecting, right? You have this funnel, and we are kinda high grading the projects that we think can get to the finish line and provide good returns for us and Brookfield, our partner. It's hard to say what we are not considering without being specific, but I would say what you see is a high-graded list of projects that we feel very strongly that we can execute on.
Great. Thanks a lot.
Thanks, Noel.
Thank you. The next question comes from Eric Seeve with GoldenTree .
Hey, guys. Thank you for the call. Another follow-on question regarding the CO2 business. In terms of the projects in the queue I know that you're still talking to, you gave us some color earlier that it's a mix of greenfield and brownfield that was interesting. I'm curious in terms of the potential size of those projects. Is it in line with the size of the projects you've already announced? When I talk about size, I'm talking about million tons of CO2 sequestered each year. Are the remaining projects you anticipate signing, are they similar size, or are there some bigger, chunkier ones out there? Any color on that would be appreciated.
Hey, Eric. I mean, remember, we're dealing with a total addressable market of 400 million tons of emissions in California, right? There's definitely, as you said, chunky emission sources out there. In, and you're naturally, if you're having to put investment on capture, if you're having to connect point source to sync and put pipelines in place, you're gonna have to have a scale naturally to those point source projects. Having said that, we look at all of these projects. We look at proximity to our tanks, we look at counterparty, and we look at the commercial aspects of the injection payment, right? In order if we do a full CCS as a service, what that means.
It's hard to answer that question, but we are looking at multiple size projects throughout the state. There are some big emitters that need solutions, right? There are emitters out there that right now they're paying, you know, $30 per ton on carbon tax, and that's increasing every year. They're also probably going through, you know, trying to replicate what we're doing and finding out that subsurface and permitting is probably not a core competency. We're having those dialogues, we're educating, we're trying to land the right deal and the right partner and, you know, expect some point source legacy emissions, you know, hopefully in the near term. We're working through it and again, the size of the price is big.
It's just a matter of figuring out, okay, what's the best place to store their CO2 and agreeing to terms.
Great. Thank you. One follow-up. I mean, it seems like Elk Hills is really, really well suited to, you know, get a lot of attractive projects here. It sounds like you're gonna be well oversubscribed. Is there more potential storage space in that field that you guys are evaluating?
Yeah, for sure. I mean, Elk Hills, you know, 47,000 acres, fee simple, property with a power plant, with natural gas, with a lot of elements to bring new technology into the field. We're looking for ways to add incremental pore space. I mean, we've already expanded one of our permits in 26 R. Yes, ultimately yes, as we draw more oil and gas, we're creating pore space, right? At some point that pore space and the injection of CO2 may be more valuable than what we're extracting. That's not the case today, but it could be. The key is having those tanks that we know and understand really well.
As the, as the market comes together and as we see the value of in storing CO2, we will be looking for ways to create more pore space at Elk Hills or in the near proximity down there. We do see a lot of running room in the Sacramento area. There's a lot of near emissions near there, and we're building a very, very nice portfolio of assets. Creating these two options, I think gives us the most access to the market that we, that we can see.
Terrific. Thank you. Second question is, as we model out the production, oil and gas production throughout the remainder of the year, just trying to understand, is there any, you know, other than potential impacts from adverse weather, are there any scheduled maintenance downs that would impact the quarterly production cadence, or should we just, can we sort of, you know, annualize the sort of rate we see progressing from Q1 to Q2?
We provided Q2 guidance. There is one of our plants in Elk Hills was down for maintenance a couple weeks ago. That's reflected in the guidance for Q2. What we said is, because we're only gonna do drilling activity with permits on hand, effectively, that's one rig for the rest of the year. We see production declining between 5%-7% for the year, entry to exit. That number still looks good to us as we go here. You know, more, you know, production held up very nicely in Q1. We do start seeing a little bit of a decline in Q2 and that will be the case for the rest of the year.
It's not gonna be copy-paste Q1. You should look at the guidance and the trend. We do see 5%-7% decline for the year.
Thank you. This concludes both the question- and- answer session as well as the conference itself. Thank you for attending today's presentation. You may now disconnect your phones.