Q2 2023 California Resources Corp Earnings Call
Participants
Chris D. Gould; Executive VP & Chief Sustainability Officer; California Resources Corporation
Francisco J. Leon; CEO, President & Director; California Resources Corporation
Joanna Park; VP of IR; California Resources Corporation
Manuela Molina; Executive VP & CFO; California Resources Corporation
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
Nitin Kumar; MD & Senior Energy Equity Research Analyst; Mizuho Securities USA LLC, 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
Good day, and welcome to the California Resources Corporation Second Quarter 2023 Earnings Conference Call. (Operator Instructions) Please note, this event is being recorded. I would now like to turn the conference over to Joanna Park, Vice President of Investor Relations and Treasurer. Please go ahead.
Joanna Park
Welcome to the California Resources Corporation Second Quarter 2023 Conference Call. Participating on today's call are Francisco Leon, President and Chief Executive Officer; Manuela Molina, Executive Vice President and Chief Financial Officer; as well as CRC's entire executive team. I'd like to highlight that we have provided slides in the Investor Relations section of our website, crc.com. These slides provide additional information on our operations and our second quarter results.
We've also provided information reconciling non-GAAP financial measures discussed to the most directly comparable GAAP financial measures on our website as well as in our earnings press release. Today, we are making some forward-looking statements based on current expectations. Actual results could differ due to factors described in our earnings release and in our periodic SEC filings. As a reminder, we have allotted additional time for Q&A at the end of our prepared remarks. And we ask that participants limit their questions to a primary and one follow-up. With that, I will now turn the call over to Francisco.
Francisco J. Leon
Thank you, Joanna. At CRC, our strengths are clear; cash flow, carbon and California. First, our cash flows strength comes from our high-quality, low-decline assets. These assets provide a large production base with predictable cash flows from our long-lived reserves. Further, we produce some of the lowest carbon intensity oil and natural gas in the U.S., which we sell into markets that have access to premium pricing and advantaged realizations as compared to the rest of the U.S.
Our second strength is our carbon storage platform, carbon TerraVault, which benefits from an early mover advantage for CCS. CRC's large mineral and surface acreage position was the quality of our geological reservoirs our extensive serve surface knowledge and joint venture with Brookfield continue to provide us with a competitive advantage. Carbon TerraVault leads the nation in permit applications submitted to the EPA. Additionally, our CCS storage potential continues to attract significant interest from current and future emitters. To date, we have executed 5 carbon dioxide management agreements or CDMAs for a combined injection rate of 815,000 metric tons per year, which represents reservations of 16% of our port space and good progress towards our target of 5 million tons per year of injection by year-end 2027.
Our third strength is California. California's energy industry offers attractive market with high barriers to entry. The state is the fifth largest economy in the world with energy needs that far surpass local production. At CRC, we proudly operate under the highest environmental standards in the world, and our long track record of safe operation demonstrates our ability to navigate California's regulatory landscape. California also has ambitious decarbonization goals and the right incentives to drive emission reductions throughout the state. CRC is well-positioned to help advance the state's energy transition and be a solutions provider to the state.
From an operational perspective, we continue to make great progress on our business transformation efforts and are now targeting $50 million or more in annualized run rate savings. The goal of our transformation is to recalibrate our approach to reflect our current and future needs and improve our cost structure. Therefore, we're evaluating all aspects of the business, looking for operational optimizations, organizational improvements and new technologies to drive cost out of the system.
Initial actions have focused on our key business processes around well services, chemical programs and our warehousing model. We also see opportunities for improvement in how we utilize our contractors and rental equipment in the field locations. By aligning our practices and our operations to the current business environment and our long-term strategy, we can execute on our strategy to maximize cash flows and further enhance shareholder returns. Note that savings from these initiatives are not included in the '23 guidance we provided today, but are targeted to be in place before year-end and reflected in '24 results.
In the second quarter of '23, we produced 86,000 BOE per day operating 1 rig in Long Beach and 35 workover rigs. A combination of strong demand and favorable pricing underpinned $69 million of free cash flow generated in the quarter and brings our year-to-date total free cash flow to $332 million. During the quarter, we repurchased $64 million of our common shares and paid $20 million to our shareholders in dividends. This represents our 122% of our free cash flow return to shareholders in the second quarter.
Since May '21, CRC has returned nearly $700 million to our shareholders or nearly 20% of our current market cap. Our reservoirs continue to perform in line with expectations. Our stable performance is best observed from our gross production results, which excludes variations from our production sharing contracts in Long Beach and NGL storage levels. Our flat quarter-over-quarter gross production demonstrates the productivity of our stacked pay and efficacy of our downhole maintenance program.
As a reminder, we continue to see delays in new drill permit approvals but continue to receive permits from (inaudible) for workovers, deepenings and sidetracks. Despite a lack of new drilling permits, we remain on track to deliver 5% to 7% entry to exit production decline. Our 2023 development plan is focused on permits in hand and our high-return recompletion and workover activity highlights CRC's ability to manage reservoirs and maintain capital efficiency even at lower activity levels.
On a net production basis, oil came at the midpoint of our guidance range, while total production ended up on the lower end due to storing of NGLs. We typically store NGL volumes produced during the second quarter to sell in higher demand periods, maximizing our cash flows. On the power side, our 550-megawatt power plant provides us with the ability to manage field level power costs at Elk Hills and surrounding fields as well as to optimize between taking incremental volumes of natural gas to market. We're converting the natural gas to power for delivery into the (inaudible) wholesale power market.
Our natural gas and marketing activities once again had a very strong quarter. As Citygate gas prices held up much better than field-level prices, our natural gas and marketing activities once again had a very strong quarter. The team was able to double quarterly margin results versus guidance expectations by taking advantage of the transportation and delivery resources we maintain. Looking ahead, our natural gas marketing margins should moderate in the second half of '23 as California natural gas inventories returned to more seasonal levels and the abundance of hydro generation capacity competes with natural gas-fired generation this summer and fall.
Moving to carbon management. During the quarter, we executed our fifth CDMA with [Verde] Clean Fuels for our renewable gasoline project. This project further confirms our economic type curve of 50 to 75 of EBITDA per metric ton per storage only project. We also expanded our capacity reserve for Lone Cypress for the previously announced blue hydrogen project. Anticipated CO2 injection has now more than doubled from 100,000 to 205,000 metric tons per year for the project.
These facilities, in addition to our agreement signed within Intec earlier this year are planned to be located at our Net Zero Industrial Park at Elk Hills, which provides a unique benefit of offering surface acreage for build-out, midstream and co-location with permanent CO2 storage. Post quarter end, we submitted another Class VI permit application for CTV 5, continuing our coal position for storage permit submissions in the queue with the EPA. The permit application has a capacity of 70 million metric tons of CO2 storage, bringing CTV's cumulative potential storage capacity on their permit applications to 191 million metric tons.
We continue to target a draft classics permit from the EPA by year-end. The recent EPA draft permit approval for our project in Indiana is encouraging for the CCS industry and provides yet another data point of EPA support for the technology and progress. We remain optimistic and continue to see positive traction from our conversations with potential emission sources as well as various other stakeholders. Lastly, we continue to evaluate the separation of our carbon management business. Carbon TerraVault continues to make strong progress each quarter. However, we're still in the early stages.
We continue to look for certain important milestones such as permit approval, project FID and line of sight to first CO2 injection in cash flows before considering a potential separation. And now I'll pass it over to [Nelly] to provide an update on CRC's financial position and outlook.
Manuela Molina
Thank you, Francisco, and welcome again, everyone. Our balance sheet remains in solid condition. During the quarter, we expanded our net RBL commitment by $25 million bringing our total commitments to $627 million. We ended the quarter with $927 million of liquidity, which includes $448 million in cash. Our net leverage position reflects a very modest 0.2x of leverage while our fixed charge coverage exceeds 17x.
Given the cyclical nature of the commodity prices, keeping our financial strength is a key pillar of our strategy. Looking forward, we are maintaining our full year production guidance. As Francisco mentioned before, our reservoirs are performing in line with our expectations, which are informed by decades of operating history. We anticipate modest declines in the second half of the year in line with our previously disclosed range of 5% to 7% annual decline.
Regarding our capital program, we take a dynamic approach in response to commodity price volatility and focus our activity on maintaining oil production and maximizing our free cash flow. We reaffirm our 2023 capital program to range between $200 million and $245 million under current conditions with a heavier weighting in the second half of the year due to timing of projects and higher expected workover activity. Oil and natural gas development will continue to be focused mainly on executing projects using existing permits. While commodity prices remained at healthy level, the forward street softened during the second quarter. Our updated guidance reflects our strong natural gas marketing activities to date as well as our outlook for commodity price differentials.
The NGL markets reflect seasonal quarterly pricing trends and the global oversupply market environment. On the natural gas side, our guidance reflects the unprecedented price spikes registered in the first quarter on the full year average, but also the return to normalized levels in the second half of '23. As a result, we are lowering the top end of the range of our 2023 operating cost guidance by $15 million due to lower energy-related operating expenses expected in the second half of the year. Additionally, we are narrowing the range of our free cash flow guidance for the year to $380 million to $460 million.
Let me remind you that our 2023 guidance is based on an estimated Brent price of $77.54 per barrel and [$2.87] per Mcf NYMEX price. Our key financial priorities in the second half of the year are the execution of our business transformation initiatives to reduce our respected 2024 cost run rate in $50 million or more (inaudible)AG and being responsible stewardship of the best users of our balance. With that, I will turn it back to Francisco.
Francisco J. Leon
Thank you, Nelly. CRC's unique value proposition is founded on our disciplined capital allocation, solid balance sheet and free cash flow generation capability. CRC's continued progress at carbon TerraVault that provides shareholders a way to participate in CCS and California is a path towards a decarbonized future. To summarize, CRC strengths are cash flow, carbon and California. Thank you for joining us on the call today. We'll now open the line for questions. Operator?
Question and Answer Session
Operator
(Operator Instructions) The first question comes from Scott Hanold with RBC Capital Markets.
Scott Michael Hanold
For my first question, I was wondering if you all can provide an update on the Class 6 permit process with respect to the Indiana permit that you had indicated. So if you could compare and contrast like any kind of differences or the timeframe that they had to go through in Indiana to get theirs and versus what you all are doing there? So if you can just kind of compare and contrast and if there are any differences between those -- just trying to get a sense of your confidence in that year-end target for receiving the draft permit.
Francisco J. Leon
So yes, we're still targeting the draft permit for CTV before year-end '23. A big catalyst for CTV, big catalyst for California in general. We're engaging with the EPA regularly and hope we are the first in California. We are dealing with a different part of the EPA. We're dealing with Region 9 -- so we talked to both Region 9 and headquarters. But we don't have a lot of visibility into the permit in Indiana. Best we can tell is that they filed before we did. So a little bit longer timeline for them, but hard to say really from where we stand as to how good did the permit application was and ultimately, the steps that they took to get there. So I won't comment on that permit. I just feel like we made a lot of good progress on the technical discussions with the EPA and still feel very much in target to get the draft permit this year.
Scott Michael Hanold
Got it. And when we refer to the technical progress, you're just talking about like just suitability of the reservoir and (inaudible). Is that fair?
Francisco J. Leon
That's fair. I mean there's financial assurances, there's community support. There's a number of things that the EPA is going through as they make decision on permits. And I feel that Chris Gold and the team have done an exceptional job getting us prepared. But ultimately, we're waiting for that final sign off that we have the draft permit. And I think the -- not only CRC, but the rest of the CCS space is eagerly waiting for the EPA to move on more permits.
Scott Michael Hanold
Okay. And for my next question, I'm going to sort of keep on the same kind of line of questioning. But the community support aspect, obviously, I think, is going to be a big kind of lifting effort to, especially being in California. But can you give us a sense of like what you at CRC are doing specifically to get the community support and help get that through? Because I do think there's that comment period after you received the draft correct?
Francisco J. Leon
Yes, that's correct. After the draft permit gets granted, there's a period of time for public comments, and then a final permit gets granted after those are incorporated. We're working -- our team is working diligently in parallel to get the public comment discussion underway and getting the support from the communities. Their first project, is critical that the first project is successful for all the stakeholders. And we're in Kern County, we're also at Elk Hills at a field that we own 100% fee simple remote from any neighborhood in the areas of concern from the public. This is the right place to have our first project in California.
So -- and we're the right counterparty to be leading it -- we see, as we spend time with community leaders and we do community plans, we feel that support is there. And so again, to us, it's not a sequential process. We very much got started already and feel the support is going to be there. We're also working with Kern County and the Kern County Planning Commission to look at the permits that are required at a local level so that we're good to go once the EPA gives us a sign off. So a lot of things in motion, but we are progressing in every respect and look forward to getting started.
Operator
The next question comes from Kalei Akamine with Bank of America.
Kaleinoheaokealaula Scott Akamine
And my first question, I just want to hit on production. So coming into this year, I think we were expecting to see high single-digit declines by year-end because of the constraints that you're seeing on the Kern County permitting process. So I'm hoping that you can help us understand what the drivers are to the better production performance that you're seeing. Is it better new well performance? Is it some kind of tailwind from prior years? Or is it the underlying base -- and really, the [nub] of my question is trying to understand what the unmitigated decline of the portfolio is?
Francisco J. Leon
So I think you summarized in your question that the answer really well. So quarter-over-quarter, if you could look at gross production, and that's ultimately the best way to judge the performance of the reservoir. So you don't have -- like we have some NGL storage noise in the quarter and you always have the production sharing contract. But the way you look at the reservoir is to go to gross production and we were flat quarter-over-quarter. So -- and it is a tailwind, we had 3 rigs when we started the year. So there's some benefit from performance of those wells.
Our current development plan, which is focused on the Wilmington Field in Long Beach, it's performing extremely well, kind of with wells have up type curve. So that helps as well. But at the end of the day, it's the quality of the underlying asset, right? The PDP of our base has a naturally very shallow decline. And as we're able to move OpEx dollars through downhole maintenance and as we're able to do capital workovers, we're able to mitigate that base decline over time. So it's a low decline to start with all the activities having the effect that we would want -- we still think at the end of the day, what starts fading out is some of the support from the initial activity in the year. So we do see a 5% to 7% entry to exit decline. I feel pretty good about that number, if you look from January to December. But we're happy with the results in the performance of the base and the way with the production has responded year-to-date.
Kaleinoheaokealaula Scott Akamine
Awesome. I appreciate that color, Francisco. My second question goes to the carbon management business. Now I understand that there's some legislation that's in the works that's going to help define the state regulations on the CO2 pipelines, and I think that's now expected in 2024. So I'm trying to understand what the impact they may have on perhaps the third parties that are situated around you that are considering capture projects. Because at the moment, the majority of your offtake is with new build plants to be located on your own property where those regulations maybe aren't as meaningful?
Francisco J. Leon
Yes. So there is a lot of work happening in California to get the -- to get some pipeline regulation and the framework on their way. We see significant support among legislators for CCS and there's a lot of discussion happening on effectively what's a trailer build to Senate Bill 905 to get that framework put in place. This session is still open. So I wouldn't say that it's happening next year versus this year. We do see progress. We do see conversations happening. So I wouldn't put a timeline to it until we have and ability to see how the session finishes.
So -- but that is an important piece of legislation that needs to come out. And if you think about, okay, why are we at 5 Greenfields and still not any of the legacy brownfield projects it's really 2 things. One is the price discovery negotiations on the split of the economics, which is a normal commercial discussion between parties. But ultimately, we have an existing emission source and you have a permitted [sink], which we're going to have in multiple places throughout the state. That connectivity between the 2 points is critical. And without having a good way to understand how the CO2 pipeline is going to be regulated, I think that's an important gap that we're overcoming on both sides of the fence with CCS.
Now working alongside all the decision makers and stakeholders to providing our input is hopefully going to get us there at the end. But the way we're thinking through this is going on Greenfield projects -- going towards Greenfield projects, it's a tremendous way to accelerate CCS. We can't wait always for the regulation to be put in place on the more challenging aspects, we have a project that can be co-located. We have 3 projects now in fact, right? Blue hydrogen, renewable gasoline and DME. And that's a way to bring the energy transition into the near-term, which is something that California really wants to see.
So it brings alignment -- we provide this one-stop shop. It's a good way to showcase progress as we wait for all their regulations to come into play. But you're right, that's going to be an important aspect to see that trailer built to 905 is something that we're very much looking to see. And that's going to help literally connect the points between emission sources and the storage vaults.
Operator
The next question comes from Nate Pendleton with Stifel.
Nathaniel David Pendleton
My first question, starting at a high level, can you comment on how or if recent M&A in the CCS space has impacted your view on separating Carbon TerraVault?
Francisco J. Leon
Yes. I mean I think it's important to see the M&A space moving on CCS. It's a good validation, certainly of where the industry is heading in particular for the [Denbury] team. It's hard to predict toward where we go from here other than there's a lot of -- we knew there was a lot of investor interest in investment dollars in this space. Does that lead to combinations. I think it's clear that we're heading there. But ultimately, we're going to be all in different timelines. We're going to be in different markets to pursue. And I just see it as a good validation point that CCS is definitely going to be here to stay.
Now in terms of the separation, I would say not focused on the things that we don't control and whether we expand or not outside of our current footprint, I think the focus really needs to be -- we need to get permits from the EPA. We need to be able to start construction and get line of sight into that first cash flow. I think at the end of the day, we're going to be looking at -- it's an early-stage industry with a lot of people that are watching every step of the way. So the best way to do it is just take it step by step and start showing progress. And the progress we've shown in 2 years has been tremendous. We look to accelerate that -- but ultimately, the permit is the catalyst. I don't see the M&A as a catalyst. I think the permit situation with the EPA is going to be what gets things moving not only for ourselves, but a lot of other people that are in this space.
Nathaniel David Pendleton
And looking at Slide 17, with your Carbon TerraVault projects to date and the significant addressable market you mentioned on Slide 16, I believe, -- do you have a target cadence for adding new sequestration sites beyond CTV 5? Or could you provide any color as far as your outlook for additional sites?
Francisco J. Leon
So we're targeting 200 million tons of [port space] to be permitted in -- we're at 191 million -- so we're pretty much there in terms of the permit submission aspect of this. What we've seen is, as we saw with 26R, which is part of CTV 1. Once you're in discussions with the EPA, once you collect more data, once you have a better sense of the land position, you're able to expand the projects, and that's what we did with 26. We added capacity to that. So there's always going to be room to expand beyond what we're submitting. But I think for what else is critical is -- we've now secured the port space that we want to pursue. We started the permitting process. It's about bringing in the CO2 into those fields. That's the next catalyst, and that's what we're focused on.
There's over 20 million tons per year of emissions. If you add every single counterparty that we're talking to at the moment, it adds up to about 20 million tons of emissions. We think our port space is able to ultimately on a combined basis, get us to about $5 million tons of emissions per year. So we're about 4x in terms of the as the coverage of CO2 in terms of counterparties that we're talking to were 4x our capacity. So it's important that we start getting reservations, we start finalizing deals with other parties. At some point, the port space is going to run out, right? And then you have to restart again.
Now there's going to be a lot more to do. We think it's 5x our port space that we ultimately can do, but our near-term target is 200 million tons. So really focused on that ability to connect the dots with the emitters because I think everything else, we feel like we got it in pretty good shape.
Operator
The next question comes from Nitin Kumar with Mizuho.
Nitin Kumar
I'm going to start with the oil and gas side of things. Francisco, you mentioned the $50 million target on OpEx. As I look at the numbers, you're really not guiding to that, and you said that. But could we get a sense of the progress you have made to date? I know you aren't expecting an impact this year. But where are you on that project to reduce cost by $50 million?
Francisco J. Leon
Nitin, so really excited about this initiative. I feel like we have a tremendous team, a tremendous organization, but I challenge the team to see if we could do better. And that was the question, can we do better than we have in the past? Are there opportunities in Omar, who is here with me and others on the team really have stepped up to the challenge. And said, yes, we can do better and we're getting after it. So we gave some examples of the things we're looking at it from the way we contract, there's some opportunity to bring some contracting work in-house. There's other places where you actually may outsource in kind of challenging the model that we've had for close to a decade now as an independent company, it was a good time to kind of test things that we could improve. We're looking at warehousing model. We're looking at relationships with key vendors. We're looking at the organizational design.
But I think the commitment that I have from the team is this is not going to be a won and done process. We're always going to look for ways to improve the cost structure. And so where we might reach a finality here in this quarter in terms of this first stage to get to $50 million, so we can start incorporating that into the 2024 guidance, we're going to continue working through ways to improve the business. And there's things like energy, for example. CTV is doing a lot of interesting things with new technology on that could really work in the future. And then if we can reduce our exposure to the California grid, that's going to be a big benefit to CRC and our cost structure. That's a big cost driver, the energy cost.
We also have a lot of wells, and those wells are great assets for us, right? We were able to do side tracks, we're able to do workovers without having to have a drilling rig on site, I think that answers part of the question as to why we have such low decline. But we're very spread out over a large footprint. So we're looking at things like [Gen AI], drone technology, things that are up and coming, but I think we're going to be particularly well suited for incorporating some of those technologies on a go-forward basis. So anyways, to summarize, $50 million is what we have line of sight. We think we can get to -- that's where we have a plus because we think we can do a lot more. It's a commitment from the team to continue to look at operations and try to bring down the cost structure and ultimately drive to higher cash flows.
Nitin Kumar
Got it. On the CMB side, you talked about the type curve of 50 million per [MMtpa]. You're close to that first million or so, 815,000 CDMA signed. This might be a long shot, but any sense of which part of the type curve you are tracking to in the first 800.
Francisco J. Leon
Yes. I mean, I think all 5 of our projects so far, Nitin, that make the entirety of that amount is all greenfield storage only. So that points towards the lower end of the type curve. So 50 to 75 is where we bracket the storage-only EBITDA. And the way to think about that is -- it's a lower capital requirement for those storage projects. All 5 of the projects that we are working towards will have a capture component built into the facility. So you don't have to attach capture technology into an existing plant, so it's already embedded or that plus you also have a much higher concentration of CO2 as you bring these projects to life. So those projects, because they are going to be less capital intensive, less capital requirement. When you look at returns, you're able to make really attractive returns by -- even with the lower EBITDA.
The opposite end of the model is where we have a full CCS as a service, where we go to an emitter, and we do all the way from capture equipment, installation to transportation to storage and that is the part of the type curve that we point to the higher levels -- that would point to the higher levels of the type curve. That also has higher capital commitments and therefore, you need a higher contribution from the incentives in order to make a return. So right now, we're focusing on the lower end, but lower end in this case means really good returns and low capital. So we're happy with those projects. We do want to pursue a Brownfield project -- as many Brownfield projects as we can.
At the end of the day, this business is going to be successful if we can decarbonize existing industry as much as we can. That's ultimately what gets the support from California, that's what we need in the state and we think we're really well-positioned to achieve both ends of the spectrum.
Nitin Kumar
Got it. Great. If I can sneak 1 last one. Just any update on the Kern County permitting? I know you had said that you expect permitting to restart in the second half of next year. But any updates there?
Francisco J. Leon
That's still the timeline we're at. We anticipate a hearing in the appeal process to be scheduled sometime in Q4 of this year. And that pushes a decision -- a final decision to be the beginning of next year. So we're looking to be back to normal activity in the second half of '24. So no real changes other than we think the hearing is going to get scheduled here very soon. As a reminder, we're working on alternative plans to field level. What's being challenged in the quarter is the Kern County environmental impact report. We're doing field level CEQA and EIRs for 3 of our core fields in the San Joaquin Basin that collectively have about 90% of our proved undeveloped, but we're also looking for inventory and ability to drill wells outside of Kern County. So it's an all-of-the-above strategy to get us back on track by the second half of next year.
Operator
The next question comes from Leo Mariani with Roth MKM.
Leo Paul Mariani
Can you guys talk about just the production guide in the third quarter. So second quarter, you did 86,000 barrels a day net. You guys talked about seeing some declines in the second half, but your third quarter guide is 86 to 88 that implies sort of a modest increase. Can you just kind of help us connect the dots there?
Francisco J. Leon
Leo, yes, the -- so we -- basically are recovering some of the NGLs that we were not able to sell. So on a sales basis, that shift happens. So absent any big movements in price that affects your PSC barrels -- we see that's the right range, 86 to 88 for the third quarter. So that does imply further some decline in the fourth quarter.
Leo Paul Mariani
Okay. That's helpful. And then just in the second quarter, I mean, it looks like you guys paid out more than 100% of your free cash flow to shareholders in the form of dividends as well as buybacks. Is that sort of an anomaly? Or are you guys sort of comfortable potentially doing that, just depending on, say, where the stock is and then the macro situation based on the strength of the balance sheet here.
Francisco J. Leon
Yes. Last year, we paid over 100% of free cash flow if you look at 2022. Year-to-date, we're closer to 50. We had a very high cash flow order in Q1 and -- and so if you average Q1 and Q2, even though Q2 is higher than 100%, we're at about 50%. We're very comfortable with our capital allocation strategy, but we do evaluate the best method to provide returns and value to shareholders every quarter. I mean we do have a fixed dividend, but it's about $1.13 per share. So that's in there that gives the market more of a fixed component. And then the rest of it is discretionary based on how the business is looking and where we see the most value. We do look at where is the best return for the company, and that's what we act on. So we haven't been prescriptive on the shareholder buybacks, but because we like to assess every quarter where we are. But if you look backwards, we have been over 100% in 2022, but right now, we're closer to 50% for the year.
Leo Paul Mariani
Okay. That's helpful. And then also, could you just comment on sort of existing competition for CCS deals out there in California -- as far as I know, you guys are the only ones that have kind of put some deals on the board here with 5 deals. But certainly, correct me if I'm wrong, any information you can kind of provide about the competitive landscape would be helpful. And then also, is there any update on the sale of the parcel that you're working on in Huntington Beach area?
Francisco J. Leon
Yes, I'll go with the [Ford] Apache, which is our 1 acre parcel in Huntington Beach first, and then I'll come back to the CCS question. So we have -- we are making progress. There's many components to converting an oilfield to a real estate project. We're going through abandonment. We're looking at regulatory requirements, but you also look at market conditions. So we're working through all 3. As we said before, we think this gives us a really good look as to what ultimately be the decision that we make for the bigger property, which is 90 acres down the street. So it's a good way to test the waters and make sure we understand all the requirements from the law and ultimately get this acre sold into the highest and best bidder. So we're working through that.
We said, I think we've from the beginning, said that this was going to be something that we would do by year-end, not because we want to just provide a lot of cushion. There's a lot of things to do. And we're working through it. I think I reported last time we -- we started working on abandonment. There's a few wells on site. There's facilities we have to remove. So all of that process has begun and is ongoing. So look back to report to the results of that sale later this year, assuming market conditions hold. So that's kind of the update there. We're working through that.
In terms of CCS in competition. I mean, you can see if you look out to the EPA website, you'll see that on the permit submission front, we are not the only ones. There's a number of other projects out there. They do tend to be more for self-solutions, meaning there's parties that want to reduce their own emissions and they have a site that they identified nearby and that's how they're trying to do. So we haven't seen the Carbon TerraVault competitor come out that has a view to look at all of the state emissions quite yet, at least not based on what you could see publicly. We do see competition. We do see this as being -- not like the Gulf Coast, where it seems like a free for all. But here, you're going to have competition.
We think this is going to be a very successful business undertaking and that we see others that are either trying to acquire land others that are -- you're going to start seeing some permits, we think, in the EPA of parties that maybe they're not there or don't register as potential counterparties in the state. So feel good about what we've established to date, which is the core position that we wanted to have and what we ultimately ties to our commitments. But yes, don't be surprised if within the next 6 months, you start hearing about others coming into California.
Operator
The next question comes from Noel Parks with Tuohy Brothers Investment Research.
Noel Augustus Parks
Just a couple of things. I was thinking that, of course, that a company has the long routes in oil and gas production, and you observed that CCS is a very young industry. So for the 5 deals you've done so far, is kind of a sense that the train is just starting to chug along and maybe you can -- leave the station for CCF. I was wondering, can you sort of walk through the deals to date and describe what types of things you were negotiating on each of these transactions to get you -- or to get the customer to pull the trigger? Sort of like what are the issues that are in the mix when you're -- with these past deals?
Francisco J. Leon
Yes. So we -- we're kickstarting the energy transition in California. And there's a lot of interest to develop markets like hydrogen or renewable gasoline, the project we announced with Verde today. But in a lot of cases, I mean, you don't have -- first of all, you don't have the product, but you also don't have the market and the offtake. So the energy transition, I think we're very committed to it, but we need to drive towards that, and that's a lot of investment that needs to come in and that's where we are working with agencies to get the permits under way. Otherwise, the transition is going to take much longer.
But what we're trying to do with the conditions precedent that are established in the CDMA is basically related to things like offtake agreements. In some cases, we have already an existing offtake agreement with the counterparties, in some others, we're working through that, right? So who's going to buy the blue hydrogen from Lone Cypress, critical that we understand that. And that in terms of our -- we have preserved the option to invest into the projects on all 5 at this point. But we're -- that's a good way to really look into the market and how that evolves.
Now we -- there's a lot of groups in a lot of very -- lot of groups with very deep pockets that want to develop that hydrogen network for heavy trucks in California, but that doesn't mean I think we have something like 7 stations in the entire state. So that's going to require -- it's a little bit of a circular kind of chicken and the egg problem. We have offtakers that want the product that they're building plans are ready to go. And then -- but you don't have the hydrogen in a form that's readily available and cost efficient that ultimately they can sell. So we're trying to bring all of that together on these projects. So -- but again, it's very well aligned with where the state is asking us to be. And so we want to be the tip of the spear. We want to be the leader in the space. We want to create these markets, but it's going to take some time.
Now if you think about Brownfield, Greenfield, right, because this maybe sounds like it's early stage, and it's not going to get there, you will get there. And again, because we're focusing on areas where we already own the land, and we're going to be co-located with the reservoirs, that brings us much closer to a final investment decision than others.
If you had a Brownfield project, you still have to install a capture facility on an existing plant and then make sure you have the right build-out on the pipeline. So this is why these projects are not happening next year, right? That's what we said to get to our critical mass of injection, we're looking at end of the year 2027 because a lot of these projects have to come together. But there's -- so just, again, to recap, it's a lot about the offtake agreements. -- who's going to be buying these products? Is the support going to be there? What's the price. We went through a significant change, positive one with the IRA last year and 45Q, providing a much better support for some of these projects, and that's what we're actively trying to capitalize on these Greenfield projects.
But there's still a lot of work to do. But ultimately, that Class 6 permit for us is the catalyst that gets a lot of things going. We have the capital with Brookfield. We get the permits, and it's a matter of starting the construction and getting these products to market.
Noel Augustus Parks
Great. That's what I was looking for. And you also talked a bit about technology development. You're talking largely about in-house applications for cost savings, but just zooming out a little bit to -- just a little bit of a double advocate question. Post-injection of CO2, I was wondering if you have done any work or can you talk about what sort of modeling technology post-injection you're going to need. And I'm just wondering, is that something that's costly, are the methods or the vendors for doing that standardized? Just thinking that as you have worries about not -- [made] the opposition to injection of CO2, just sort of forestalling any concerns that might be there around if (inaudible) sequestered, et cetera.
Francisco J. Leon
No, that's great question. I'll pass it over to Chris Gould to provide the answer.
Chris D. Gould
Yes. I think the first -- the most important thing to understand when it comes to monitoring is that, that's part of the EPA Class 6 permit. So all the requirements are spelled out as to what needs to be done and how -- for how long, by what sensitivities those need to be dialed into, if you will. So there's really not a lot of guesswork there. We know what we have to do, and we'll get the permit on the basis of complying with that. When it comes to fulfilling those requirements, there's a lot of different applications or opportunities to do it through collaborations with existing monitoring all the way through new technologies that we've been heavily engaged with the DOE, other universities that conduct this sort of monitoring and have done so for many years, particularly in a state like California. So we feel very well prepared for complying with the permit requirements with an abundance of different emerging or existing technologies.
Operator
And we have a follow-up from Scott Hanold from RBC Capital Markets.
Scott Michael Hanold
Francisco real quick. You mentioned, obviously, on the shareholder return that you all are going to look at what creates most value for the shareholders. And just some context, obviously, you've got the base dividend in there. But as you kind of step in and look at the buybacks, obviously, when you're doing it before for the last year or so. I mean doing it under $40, that was sort of a layup decision, right? Now you're $10 to $15 per share higher. Like can you walk us through that thought process of -- from your -- on the allocation of the shareholder returns, like where does the stock price play into that? And how do you think about like where it is today versus obviously where it had been over the last year?
Francisco J. Leon
So what's your price targets like $60 (inaudible) so we have the option to increase the dividend. We have the option to continue with buybacks. We also can look at the debt. All options are on the table. We like to be opportunistic because just like we did last quarter, we were able to buy shares at $39. And if you look at the history over the last 4, 5 months, I think we were able to pick a really good time to deploy the cash to buy the lowest average price for the share. That discretion that ability to make a decision really comes from a returns-oriented analysis, right? So we look at the opportunities in front of us and then we make a decision.
Now what we -- even though there's discretion in how we return cash to shareholders, we're very committed to the program and to return the highest amount of cash to the shareholders over the long run, right? So even though there may be some variability into amounts in the quarter and the like, we do look at it actively, and ultimately, we're very committed. Now we -- as a reminder, right, we didn't talk about it today, but we have the high-yield indenture that ultimately governs our ability to distribute cash via either dividends or buybacks. And it's the last 12 months, 50% of net income calculation.
So there is an oil price or a commodity price component to it. If you're bringing in, you might have a period of very high prices at the moment, but you're bringing in lower commodity prices from the last 12 months and that acts as a capping mechanism, right? So because we're dealing with those caps and you're dealing with discretion, it's very difficult to be more prescriptive, but very committed to returning as much cash to the shareholders as we can.
Scott Michael Hanold
No, that's helpful. And one real quick one for me, just to close it out for me. Just on some of these Greenfield projects that you all have CDMAs for -- when you think about -- obviously, you have your Class 6 permit, which is something you're working towards. But are there any other like permits or approvals that we should be thinking about to get like a blue hydrogen or blue ammonia or renewable gasoline facility approved either at the state or even at the Kern County Planning Commission. Is there any specific approvals or legislation that governs some of that?
Francisco J. Leon
Yes. No. So you need a conditional use permit. That's a critical local California permit and that's going in conjunction and working very closely with the Kern County Planning Commission. So those conversations are ongoing for the projects that are going to be at Elk Hills. Like I said that before, we're working on all those in parallel -- it's nice to have the Kern County Planning Commission there because they see all aspects of the energy spectrum, right? They're the ones that do the conditional use permits for oil and gas, but also for solar and wind projects. So it's a natural extension of what they do to look at the Greenfield projects and be the group that oversees these permits.
So that's one to look for. And but like I said, we're working through it. They're aware of our plans, lockstep working with a lot of the same information that you send to the EPA, you have to provide locally, so that would be one to look for after we get the draft permit this year to -- we'll share more of the progress in the inner workings, so the California approval. So that's the one I would highlight. Certainly, we're looking for the pipeline regulation to also be put into place in the near-term. That's going to be critical as we move away from co-location.
Okay. We think that's a wrap. Thank you so much for spending time with us. And look forward to seeing you on the road. We're going to be going through a number of investor conferences in the coming weeks and look forward to seeing everybody in person. Thanks so much.
Operator
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.
