Q1 2023 California Resources Corp Earnings Call
Participants
Francisco J. Leon; Executive VP & CFO; California Resources Corporation
Jay A. Bys; Executive VP & Chief Commercial Officer; California Resources Corporation
Joanna Park; VP of IR; California Resources Corporation
Eric Seeve; Research Analyst & Portfolio Manager; GoldenTree Asset Management LP
Kaleinoheaokealaula Scott Akamine; VP in US Oil Equity Research; BofA Securities, Research Division
Leo Paul Mariani; MD; ROTH MKM Partners, LLC, Research Division
Nathaniel David Pendleton; Associate Analyst of E&P; Stifel, Nicolaus & Company, Incorporated, Research Division
Noel Augustus Parks; MD of CleanTech and E&P; Tuohy Brothers Investment Research, Inc.
Scott Michael Hanold; MD of Energy Research & Analyst; RBC Capital Markets, Research Division
Presentation
Operator
Hello, and welcome to the California Resources Corporation first quarter earnings call. (Operator Instructions) Please note today's event is being recorded.
I would now like to turn the conference over to your host today, Joanna Park, Vice President of Investor Relations and Treasurer. Please go ahead, ma'am.
Joanna Park
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 risk factors described in our earnings release and in our periodic SEC filings. (Operator Instructions)
With that, I will now turn the call over to Francisco.
Francisco J. Leon
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 continued 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 3 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. And 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 and workover capital.
We drilled 9 wells in 2 sidetracks and ended the quarter with 1 drilling rig at Wilmington and 39 maintenance rigs. Our resource offers stack pace, 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 of the first quarter was the California commodity markets, because the state operates as an energy island, California realizations reflect the demand for energy and tends 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 in storage to make up the difference. In the case of January and to some degree, February, California found itself with limited natural gas inventories in 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 pretax 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 2 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 '23 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 and 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 8. 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 some 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 are 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 to $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 reduction 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 sacramentation and a renewable DME project at our Elk Hills net 0 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 port space. Further, 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 first 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. And 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?
Question and Answer Session
Operator
(Operator Instructions) And the first question comes from Scott Hanold with RBC Capital Markets.
Scott Michael Hanold
And my first question, it may feel like a little bit of a multifaceted one, but let me try here. You've made progress on, obviously, starting to, signing up the new CDMAs. And how do you -- and more of those, I guess, recently were some of the lower capital intensity agreements?
And how do you think about the mix of these projects going forward. Do you want to see some more of the kind of the front-to-end projects to increase the scale of EBITDA? Or do you feel confident and I know you said you're only about 12% 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. So I know it's kind of a bit of a multifaceted question. But ultimately, I'm just trying to think about the higher relative EBITDA opportunity. And if a potential offset would be exercising some of the equity stake options.
Jay A. Bys
Scott, yes, we're focused on both. So Greenfield 4 CDMAs on Greenfield is really good progress. No question about that. And you have the tailwinds from the IRA increase in the incentives.
So definitely, that's helped put projects together. It also helps that we can co-locate these Greenfield projects at Elk Hills in the Sacramento area. So it's just -- it's an easier process to get to a CDMA.
Existing point sources we talked about it before, but they're still going to price discovery, right? How are, the credit share across the value chain. And you also have to solve forward transportation, how do you move this year to across the state.
We know there's a lot of interest in Sacramento to ensuring that CCS is successful. Everyone understands the transportation is part of the equation. And we're hoping there's some uncertainty right now. We're hoping that uncertainty is clarified in the near term.
But I'm confident we're going to 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 on Brookfield. So we'll do a little bit of both.
I think if you look at the types of projects that we see in the Q with 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 4 projects are the greenfield, but that's not -- it's this business is not going to be exclusively for greenfield. We will bring some point source projects into hopefully in the near term.
Scott Michael Hanold
Yes. And how about the exercising the equity options on those?
Francisco J. Leon
Yes. So we reserve the option to invest into the equity of all 4 projects and started with Granites and on 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.
And that also requires, understanding the offtake contracts and the depth of the market and work to best place the hydrogen and the ammonia. Ammonia is already tied to a co-op in Sacramento. So we're evaluating both. We like to have a decision this year on s Lone Cypress, in particular. That's going to 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 that support it. But we're seeing a lot of potential demand for the product. So 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.
Scott Michael Hanold
No, I appreciate that. And it sounds like you're putting a lot of depth and a thought of around this. My follow-up question is on those cost savings you talked about. And could you give us a little bit of color on 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? And I'm kind of curious with using, I guess, that A&M service. What specifically was the reason of going like outside to have somebody come in and do that versus doing stuff like CRC? What can't you do on your own that they can come in and help you it?
Francisco J. Leon
Yes, Scott. So 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 -- on the strictest regulations pretty much in the U.S. So there's a lot of -- there's -- the team works well. We are -- have very high operating standards.
But we need to change how we work. We need to bring costs in line with activity levels. So that requires kind of a business transformation, not just a cost-cutting exercise. So we need to question everything. We need to question how we're organized. We need to question where we prioritize and ultimately look for to make decisions to take some cost out of the system.
The team got to work right away until we came last quarter and described this initiative in $20 million in a couple of months, it's a pretty good win. And again, we're trying not to -- this is not a deferral, this is not removing onetime cost. These are run rate savings. These are permanent savings that we want to pick out of the system.
So 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. And we're questioning everything, right?
It's a good opportunity for the refresh. It's a good opportunity to say, okay, do we do better and drive that culture going forward. We brought A&M. They're, one, they're a very good team. Two, we want to get that external perspective. California tends to be isolated from what's happening in the rest of the U.S.
We want to 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. So the next phase is really one that requires kind of a transformation of how we work. And we felt it was best done with -- help.
So I'm very focused on this cost reduction exercises. And we're getting a lot of great organic support from the team presenting new ideas on how do we make this company better.
Operator
And the next question comes from Doug Leggate with Bank of America.
Kaleinoheaokealaula Scott Akamine
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 imbalance on the power plant. What's the valuation, what's the G&A burden, what does the power market look like? So could you comment on whether it's core to your oil and gas business or whether it's a better fit for a stand-alone CCUS business, noting that there are potential synergies with for CalCapture?
And 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. But even in that deal, there was an option to buy it back after a period of time. So that suggests to me that there is maybe some constraints in how you think about structuring it?
Francisco J. Leon
Kalei, so, yes, 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.
So the plant delivers about 1/3 of the power goes to the oilfield and 2/3 gets sold to, Kalei -- in utilities. So 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 0 power in a state that's really hungry for these types of offerings.
So we're evaluating where this asset fits best on a go-forward basis. I mean I think the prospect of having net 0 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 stemoCO2, which is going to be on the higher end of the cost spectrum, right?
So how do we make that investment? How do we finance that type of capital call? And ultimately, where does the asset, the long, is it more on CRC or is it more on Carbon TerraVault? Those sorts of things we're working. 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 acid industry to California for E&P companies, we see that acid trading as an E&P multiple, right? So having an ability to see the financials, right? So I think some of the things you're asking having the visibility to really showcase how good this plant is and how it can get better by making it a net 0 power plant.
I think it's going to be a great value add and a way to unlock value. So we're working through it, nothing definitive. Hopefully, at least I gave you some of the down work here as we're working through these types of assets and where do they best fit in case we do separate the businesses going forward.
Kaleinoheaokealaula Scott Akamine
The quick follow-up there. And I hope you don't count this as my second question. But there was a FEED study that was performed about 2 years ago. And 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?
Francisco J. Leon
We'll see if it's your second question or not depending on what the next one looks like. No. So no, I think it's a great question, Kalei. So we did a FEED study with Fluor a few years ago. And now we're doing a second FEED study with Next Decade.
You have to understand, the reason we have 2 FEED studies and we're going to 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.
So we want to make sure that we have the cost right. I mean the technology is really not -- it's not a new technology. It's not something that concerns or maybe the scale us, but is really trying to drive that cost down.
We've had a lot of inflationary pressures over the last 2 years. We want to make sure it's a project that not only delivers that bile to reduce that CO2 emission footprint, but it's also a profitable project. So what you're going to continue seeing from us is really working to that cost profile, how do we invest it on how do we finance this power plant so that we can make to capture happen.
We're targeting FID next year, right? So 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.
And we're going to look to award the project to whoever can deliver the best price and ultimately get us a project that we feel comfortable with that can be executed on. So we're working through it.
Kaleinoheaokealaula Scott Akamine
I appreciate that. My real second question is on natural gas. So obviously, really big numbers this quarter, hoping that you can help us understand how to model your exposure? Is it bit weak? 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.
Francisco J. Leon
Yes. So I'll start, and then I'll turn it over to Jay to give a more in-depth answer. So we do feel this is a California through the regulation and through the penetration of renewables that gas is going to be absolutely needed, not more in the near term, but as we go forward as baseload.
So we're well positioned as the largest natural gas producer in the state. And we see these spikes happening more and more. So definitely, it's something that the state that an Energy Island has kind of decided that's where we're going to be. So these natural gas assets that we own through both power and owning the Sacramento Basin and Elk Hills and Buena Vista all have gas in the right places, gives us a lot of flexibility when we see this market shocks to be able to reposition our assets and go out and try to deliver that gas for the state.
But maybe, Jay, if you can cover a little bit of the pricing around that?
Jay A. Bys
Yes. Let me kind of touch on the basic precept here. More times than not, we're going to find ourselves looking to be close to, if not at the first of the month index. We prefer not to carry a lot of gas into the daily market during any particular month. Now in advance of that a 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.
Minor gas for the most part, is produced relative to a SoCal Border index. But as you may or may not be aware, we maintain long-haul transportation from the field on current -- river. And we've got a fairly significant position on the SoCal gas system in terms of BTS. So 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. And the fact is we keep a set of tools around and work very well together. We've got gas production, some of those 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. So 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. So, in general, I think you should probably look at any particular monthly cycle for the first month index, reflective of kind of an 80-20 SoCal Border/PG&E Citygate index.
Operator
And the next question comes from Leo Mariani with Roth MKM.
Leo Paul Mariani
Why don't you just delve in a little bit more to a few of the numbers sort of around the quarter. Looking at your CapEx, it's quite a bit sort of below guidance? And then just a follow up on the gas price question. I guess when I looked at sort of SoCal Border, Citygate, didn't really matter. I had a hard time getting into the $21.50 that you guys put up in the quarter. So maybe there's kind of some other semantics around the pricing or some other local markets that are kind of less visible outside of these indices that get reported by data agencies like a Bloomberg or sort of whatnot that drove that. But any more color on how you get to the $21.50 and then again, just CapEx nicely below the guide here, so any thoughts on that?
Francisco J. Leon
Leo, that sounds good. Let me answer the CapEx question. So 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 and that affected our operations. The team did a phenomenal job executing through that. And you don't see a lot of impact in production. In fact, we outperformed on production expectations. But it did delay some of the capital activity that we had planned.
We do -- as we step down, we're now running 1 rig in the Wilmington field. We'll continue that throughout the year. But 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.
Jay A. Bys
Sure. As I mentioned kind of a couple of moments ago, we did execute a few opportunistic fixed price trades during the bid week cycle. But one thing that kind of gets lost and then trying 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 in 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. So for example, to get physical gas at SoCal Border, you may end up paying more than the Border price. You'll buy physical gas and index plus number. So we had a fair number of index-plus numbers transacted in our book for the months of January and frankly, February. Both are 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.
So combined, the opportunistic trades, the limited number we had in that small variation and I think you get there pretty quickly. Again, I'm not sure Q1 of '23 will be representative of what we see for the balance of the year. I think you're going to 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 going to find them more reflective of the national gas price.
Francisco J. Leon
And if I can add one thing. So 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 will be times where it's electricity, so 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.
Leo Paul Mariani
Okay. That's very helpful, makes a lot of sense. And then, just kind of sticking with some of the numbers on the quarter here. So looking at your San Joaquin basin gas production, it was down around 10 million a day this quarter versus last. Historically, that gas production has been pretty steady. It doesn't really move around much 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 left to the volumes sort of sold market here in the quarter, just looking for any color on that.
Francisco J. Leon
The gas, Leo, really was impacted by weather. That's -- you had facilities down because of the high winds and that affected our gas production in particular. So that's really what would happen 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.
Leo Paul Mariani
Okay. That's helpful. And then, just on the regulatory front here, kind of any update on just the general permitting situation for oil and gas drilling permits in California. I know the Kern County EIS is still a ways away in the decision. But apart from that, can you maybe just talk to whether or not permits are kind of coming outside of those Kern County areas?
Francisco J. Leon
Yes. So yes, no update on the appeal around Kern County EIR, so that's still ongoing. As we said before, we expect that to take some time. So we are getting workover 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 looking at the South and L.A. Basin as well.
As we said before, we have all the permits in the drilling campaign that we need for '23. So really, all we're doing right now is creating as many options as possible for 2024, so working through those. But again, no permits in Kern County yet other than workover permits, which are flowing.
Leo Paul Mariani
Okay. But it sounds like, generally speaking, you guys are able to probably get permits outside of the Kern County EIS. That's something you can still obtain here?
Francisco J. Leon
Yes. I mean we were -- 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.
Operator
And the next question comes from Nate Pendleton with Stifel.
Nathaniel David Pendleton
Congrats on a strong quarter. Regarding trucking CO2 at your Carbon TerraVault sites that you alluded to earlier, can you provide any details around whether you're exploring the use of low emissions trucking other sites? And are there any noteworthy cost or throughput implications that we should be thinking about?
Francisco J. Leon
Yes. So first of all, on the Greenfield developments that we co-locate at Elk Hills. We'll use our internal gathering lines to be able to move CO2. So 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. So we're looking at low emission vehicles, whether it's hydrogen and fuel cells or other options, so that's very much 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. So -- definitely thinking through that as we move CO2 across the state and as we wait for the uncertainty on pipelines to be resolved. But the first order of business and how we're going to get to CO2 injection much quicker is to be able to co-locate the plant on top of our reservoir and just have deal with behind the fence gathering systems.
Nathaniel David Pendleton
Great. And 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?
Francisco J. Leon
No, absolutely. So we filed our first permit in August of 2021, second permit in November of '21. So when we talk to the EPA at the time of filing, they said it's going to take 18 to 24 months. But really, this new era of Class VI permits was just starting a lot of uncertainty in the process. We learned a lot throughout the thing that 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. And 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 with the EPA. We're working with having support from the local communities in Kern County to bring these projects forward and have really good dialogue with the EPA. So I think we're in the running to be one of the first permits by the EPA. I think we're right there, begin given the dialogue, given the progress that we made. I feel very good that we're going to have the permit this year.
And 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 next. And I think what we heard through multiple channels is that Carbon TerraVault is putting some of the best positioned permits out there. And again, we're working well with the EPA to try to get that to the finish line.
Operator
(Operator Instructions) And the next question comes from Noel Parks with Tuohy Brothers Investment Research.
Noel Augustus Parks
Just a couple of things. There's 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.
And of course, you announced today a couple of new storage only deals. So clearly, you like the margins from that business line. And you've given us some guidance on what those economics might look like. So where would you -- I mean, do you see any low-hanging fruit as far as over time, bringing more project development or even construction activities in-house over time.
Or the way the early processes are unfolding is that pretty much the sort of ideal I guess, burden of risk reward that you'd be looking to achieve?
Francisco J. Leon
Yes, so a lot in that question. Let me try to address it. So on these Greenfield projects, as a reminder, we see port space as being the scarce resource in the state. In contrary, in other parts where -- what we've said is our type curve is going to deliver between $50 and $75 per ton for storage only deals. All 4 CDMAs that we signed today fit within that type curve. So not only are we validating the port space scarcity point. But you have third parties that ultimately work their economics through and value that storage and port space.
It's difficult to say where we're going to 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. But so we're trying to understand the business model. And if there's a way to add value and it'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 as you bring power, you can sell power sell natural gas into these projects and provide land.
But we're seeing integration even amongst the partners that we're bringing together as we developed these big industrial centers, net 0 industrial centers like we have at Elk Hills. It's hard to say if we need to bring this house -- these projects in-house. Right now, we're looking to partner with really smart people that have done this before. And they were just looking to develop a market in California, which seems to be the most attractive to get these green projects underway. So I don't know yet about in-house projects. We'll see. It's too early that it's a difficult question to answer. But we do -- 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.
Noel Augustus Parks
And maybe sort of continuing along similar lines of discussion. The net 0 industrial park, could you maybe talk about the business development process for that? We get some sense of some of the building blocks from the announced projects. I'm just curious about criteria of what sort of projects maybe you are eager to get more of or would rule in and as opposed to maybe types of projects you would be more inclined to rule out for the industrial product setting?
Francisco J. Leon
Yes. No, I mean I think we have a lot of conversations are ongoing. And I think you're only able to see the 4 that we brought forward in terms of CDMA. We're evaluating multiples of what we brought in -- as we talked about before, we feel we're oversubscribed. So that means we're talking to many more parties than we have capacity for. So there is a selection process, right? So obviously, we're dealing with people that have the credibility and they can bring these projects forward where we can get permits locally as well and that are serving a market need and that these projects are ultimately going to have strong long-term off-takes to be able to lock in returns and ultimately do incremental financing.
So there is a selection process, right? That's why 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 need to them because we want to make sure we can -- we are building this -- all these projects that need to be able to come together so that we can get to our injection targets by 2025 and then 2027-2028 for the 5 million tons.
So we are selecting, right? You have this funnel. And we are kind of high grading the projects that we think can, to the finish line and provide good returns for us in Brookfield, our partners. So 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.
Operator
And the next question comes from Eric Seeve with GoldenTree.
Eric Seeve
Another follow-on question regarding the CO2 business. In terms of the projects in the queue and those 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? And when I talk about size, I'm talking about million tons of CO2 sequestered each year.
Are the remaining projects you anticipate on -- are they similar size? Or are there some bigger chunkier ones out there? Any color on that would be appreciated.
Francisco J. Leon
Eric, so I mean -- so remember, we're dealing with a total addressable market of 400 million tons of emissions in California, right? So there's definitely, as you said chunky emission sources out there.
And you're -- naturally, if you're having to put investment on capture, if you're having to connect points force to sync and put pipelines in place, you're going to have to have a scale naturally to those points worse projects.
Now having said that, we look at all of these projects. We look at proximity to our tanks. We looked at counterparty. And we look at the commercial aspects of the injection payment, right? So in order if we do a full CCS as a service, what that means?
So it's hard to answer that question. But we are looking at multiple sized projects throughout the state. But there are some big emitters that need solutions, right? There are emitters out there that right now, they're paying $30 per ton of carbon tax, and that's increasing every year.
They're also probably going through trying to replicate what we're doing and finding out the subsurface and permitting it's probably not a core competency. So we're having those dialogues we're educating. We're trying to land the right deal and the right partner and expect some point source legacy emissions hopefully in the near term, but we're working through it.
And but again, the size of the price is big. It's just a matter of figuring out, okay, what's, the best place to store the CO2 in averaging terms?
Eric Seeve
And one follow-up. I mean it seems like Elk Hills is really, really well suited to get a lot of attractive projects here. But it sounds like you're going to be well oversubscribed. Are there -- is there more potential storage space in that field that you guys are evaluating?
Francisco J. Leon
Yes, for sure. I mean Elk Hills 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 port space.
I mean we've already expanded one of our permits in 26 hours, so yes, ultimately, as we draw more oil and gas, we're creating port space, right? And at some point, that port 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.
So the key is having those tanks that we know I don't understand really well. And as the market comes together and as we see the value of in storing CO2, we will be looking for ways to create more port space. At Elk Hills, we're in the new proximity down there. We do see a lot of running room in the Sacramento area. There's a lot of newer emissions near there and we're building a very, very nice portfolio of assets. So creating these 2 options I think gives us the most access to the market that we can see.
Eric Seeve
Terrific. And second question is with -- as we model out the production, oil and gas production throughout the remainder of the year. Just trying to understand, are there -- is there any -- 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 annualize the sort of rate we see progressing from Q1 to Q2?
Francisco J. Leon
Yes. So we provided Q2 guidance. There is -- one of our plans in Elk Hills was down for maintenance a couple of weeks ago, but that's reflected in the guidance for Q2. What we said is because we're only going to do drilling activity with permits on hand. And so effectively, that's one rig for the rest of the year. We see production declining between, 5% to 7% for the year, entry-to-exit.
So that number still looks good to us as we go here. So more -- we held -- production held up very nicely in Q1. We will start seeing a little bit of a decline in Q2 and that will be the case for the rest of the year. So it's not going to be copy-paste Q1. You should look at the guidance and the trend, we do see 5% to 7% decline for the year.
Operator
And 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 phone lines.
