Hello. I'd like to welcome you to California Resources Corporation's Carbon Storage Update. Here with us today are Mac McFarland, President and Chief Executive Officer, Francisco Leon, Executive Vice President and Chief Financial Officer, and Chris Gould, Executive Vice President and Chief Sustainability Officer. We're excited to share with you the carbon capture and storage opportunities we see, and appreciate you taking time to be with us today. Before we begin, I'd like to highlight that we have provided slides in the investor relations section of our website, www.crc.com. These slides provide additional information on the topics we will cover today, as well as information reconciling non-GAAP financial measures discussed to the most directly comparable GAAP financial measures within the deck or on our website. Today's conference call contains certain projections and other forward-looking statements within the meaning of federal securities laws, including estimates, financial projections, and targets relating to CRC's carbon capture and storage projects that are still in the early stage of development. The structure and ownership of these projects are yet to be finalized. The actual conduct of our activities related to our carbon management projects are subject to risks and uncertainties and could be materially different from what is discussed today. Additional information on factors that could cause our results to differ are available in the company's Form 10-Q and Form 10-K. We ask that you review it and the cautionary statement in our slide presentation. With that, I will now turn it over to Mac. Welcome to CRC's Carbon Storage Update. Fittingly, today is California Clean Air Day. What you're going to hear today are the opportunities we are developing for a lower carbon future. We are still in the early stages, and as Joanna mentioned, what we are sharing with you today are estimates and forecasts that are still being developed. That said, they represent our best estimates at this point in time. Before we begin, let me provide a recap of what we've said to date about our carbon management activities. We've identified up to a billion metric tons of potential CO2 storage. We're focused on the first 200 million of this opportunity. Additionally, we filed a permit and are in process of filing a second to form Carbon TerraVault I, the combination of which will form up to a 40 million metric ton storage tank. That's what you've heard so far, and here's what we'd like to cover today. Why Carbon TerraVault fits with our base business and corporate strategy, why our geologic storage is a scarce natural resource when it comes to carbon capture and sequestration, and how we are well-positioned to execute, as well as high-level economics, including capital assumptions and the business models we see developing for Carbon TerraVault. California is the fifth largest global economy on a standalone basis and the largest contributor to U.S. GDP. California has also been leading the way in climate goals. As you can see on the slide, California has set ambitious reduction goals. They are currently set at 40% reduction by 2030. That is law. We have recently seen bills introduced in the legislature to put into law net zero goals by 2045 and net negative thereafter. In order to meet these goals, many climate projections outline carbon dioxide removal and storage as a necessary technology to reach these objectives. In fact, some studies have estimated up to 15% of emission reductions can be addressed through CCS. As you can see on the lower left of this slide, we believe that there is 60 million-90 million metric tons per year of CO2 that can be addressed by CCS in California. Let me pause here and talk about the momentum California is having with respect to climate goals. Recently, Senate Bill 596, or SB 596, which was passed into law, called for a reduction in emissions from the cement manufacturing industry by 40% by 2035. Lawmakers have instructed CARB to develop a comprehensive plan for net zero by 2045. CARB has held numerous open meetings on its 2022 scoping alternatives, most recently on September 30th. These meetings include four scoping alternatives to achieve net zero. They range from alternative one, which includes no CCS, alternatives two and three, which include CCS policies, and alternative four, which actually increases the reliance on CCS technology. Many of the open comments on alternative one, the alternative without CCS, are that it would not deliver on 2045 net zero objectives. The reason why I bring this to light is because many wonder whether CCS will continue to be part of the future and/or be expanded. We believe CCS will be expanded to meet net zero goals. These efforts by the legislature and CARB highlight that view. Here we see the economic incentives and legislative support that is currently in place. As we just discussed, California is leading the country in terms of policy support to meet its climate goals. One of these policies is the California Low Carbon Fuel Standard, or LCFS. LCFS is designed to reduce the well-to-wheels carbon intensity of transportation fuels consumed in California. In 2018, LCFS was amended to enable CCS projects to become eligible for credit generation under this legislation to the extent it is related to transportation fuels or captured via direct air capture. The LCFS credit potential, which is traded around $150-$200 per metric ton, when combined with the Federal 45Q tax credit of $50 per ton, provides sufficient economic incentives for the development of a variety of commercial scale CCS projects. California offers something no other state does, the ability to deliver economic CCS projects and participate in a low carbon future. How do we plan to address this opportunity? By using our unique asset base. Earlier this year, CRC took some time to evaluate our asset position and enhance our ESG strategy. We've made tremendous strides in water management and methane reduction. However, we wanted to see what more we could do for the low carbon future and energy transition. We expanded our view and concluded that CRC stands at the intersection of today and tomorrow. CRC is in a unique position to utilize our footprint to advance carbon reducing projects such as carbon storage. As noted before, we've identified up to a billion metric tons of potential CO2 storage capability, which when coupled with CRC's leading land and mineral position, our technical and commercial expertise, and the support of California regulatory regime, enable CRC to develop a critically needed climate solution via what we call Carbon TerraVault. We are still in the early stages of development with CCS deployment in California, but believe Carbon TerraVault is positioned to be a premier carbon management provider for California and its low carbon future. As I mentioned, CRC stands at the intersection of today and tomorrow. A recent Clean Air Task Force study showed that CRC has the lowest greenhouse gas emissions of the top 100 U.S. oil and gas producers. As you can see on the chart, our carbon intensity is 45% lower than the next lowest emitter, and 94% lower than the average. We are proud to safely deliver much needed production to California communities and to utilize our asset position to advance the low carbon future and energy transition. Today, we produce low carbon intensity oil, and we are looking to use our assets for further reductions for tomorrow. The three components of a CCS project include an emission source, a storage tank, and transportation as the connective tissue. CRC is well-positioned with all three elements. Our footprint provides access to a high concentration of emitters near CRC reservoirs, providing multiple ways to partner with sources. We also have the ability to leverage our own midstream infrastructure, which includes over 8,000 mi of gathering lines and substantial right of ways to provide an advantage for the build-out of CO2 transportation. This, combined with our potential storage capacity, offers CTV a lot of running room to make a meaningful impact in carbon reductions. Our field operating experience demonstrates our track record of safe operations and highlights our ability to partner with local regulators and key stakeholders to responsibly manage our natural resources. Developing at scale CCS won't be easy. However, we have competitively positioned Carbon TerraVault as a first mover and for market leadership. This zoomed in look of the map from the prior page shows CRC's footprint across the state and reflects this position. CRC's storage potential originated from decades of drilling, which means we understand these reservoirs in a way that new entrants to the space would not. We can leverage skill sets that we use on a daily basis within our core E&P business, including reservoir and injection management, operating integrated midstream assets, and leveraging our 3D seismic database to analyze the subsurface. In fact, we've created a dedicated carbon management team. CRC's history of drilling is also a key factor for success with CCS. LCFS permitting requires storage to be at a depth greater than 2,600 ft below the surface. The depth requirement provides two main benefits from a safety and optimization perspective. Lower depths offer more geologic barriers between the reservoir and the surface. The liquid state of CO2 allows for more secure containment and more pore space optimization. CRC's history of deeper wells means we are not only advantaged versus new entrants, but also well-positioned versus other oil and gas operators in the state. Approximately 82% of CRC's drilling has been below the required depth threshold. In fact, the average depth of our wells is approximately double the requirement at 5,000 ft. CTV I is even deeper at approximately 6,000 ft below the surface. This means our depleted reservoirs meet permitting requirements for LCFS. Given our presence in these fields, we have the well control and injection experience at deeper depths. This map shows our prolific Elk Hills field. Elk Hills is approximately the size of Washington, D.C., and houses two of our early stage projects, CTV I and CalCapture. Carbon TerraVault I is our project focused on CCS and does not include EOR. Carbon TerraVault I will utilize two reservoirs as the vault for this initial project. We filed a Class VI permit for the A1, A2 reservoir and plan to file a permit for 26R by November. CTV has a dedicated staff of engineers, geologists, and legal expertise, and we will continue to build a pipeline of other CTV projects focusing on the first 200 million tons of storage opportunity. CalCapture is our fully controlled CCUS project, which uses our own Elk Hills power plant as the emission source for enhanced oil recovery or EOR. CRC is evaluating the FEED study, which outlines capture design and midstream infrastructure build-out. Because both sink and source are co-located, the project should have minimal pipeline requirements, helping us to accelerate its time to market. As we continue to evaluate the economic feasibility of CalCapture, we have the capability to submit a Class II well permit and conditional use permit in the beginning of 2022. We will provide further details before the end of the year on CalCapture. Both projects are able to leverage our competitive advantages for first-mover positioning. Turning to the economics. CRC's robust free cash flow and solid financial foundation provide flexibility for us to self-fund our carbon management activities. CRC is targeting over $2.5 billion in cumulative free cash flow from 2021 to 2025, and that is after reinvesting nearly $1.7 billion to hold production flat over this period. This free cash flow estimate is approximately $1 billion higher than what we showed at our strategy day in March. That's after we've updated for pricing and a few other assumptions. We've provided a framework which shows that up to 50% of our free cash flow could be used for shareholder return actions. Those could include dividends, repurchase programs, or enhancing our financial strength. Approximately 50% of our free cash flow could be allocated to fund our carbon management opportunities, giving us the flexibility to invest more than $1 billion for this new line of business, while still maintaining production and returning cash to shareholders. Everyone has been asking for carbon management economics and what does it look like for CTV. Here is an illustrative example of how our carbon management services could look. Terms and structures have yet to be negotiated, and financial assumptions reflect the various business model possibilities, which could range from storage only to full end-to-end service. In this example, we see total incentive potential through 45Q and LCFS of $170-$200 per metric ton. OpEx could range from $25-$75 per metric ton, and capture CapEx and pipe retrofits could average between $200 million and $800 million of initial capital investment. Our expectation is that earlier projects are likely to have lower capital investment. The costs shown in the chart have been divided by 40 years, which is a proxy for the expected project life. As we said at the beginning, these are forecasts and examples and not representative of any single project. We expect each CTV project to be negotiated and highly customized. On average, our example yields $50-$100 per ton of EBITDA annually. For simplicity, EBITDA calculations assume tax incentives are monetized and recorded as revenue. As we mentioned, the carbon management business model could be fully integrated, source to sink, or as simple as we provide the storage capability with the emissions taken at our fence line. Depending on our structure, it could require a higher or lower amount of CRC capital. What we showed on the previous slide was an unoptimized business model. As we get closer to FID, we could introduce third-party sources of financing and bring in partners, which could have a positive effect on results. We are developing a playbook with CTV I that we can use to scale, drive value, and equally important, drive change for the low-carbon future of California. We are targeting injection of up to five million metric tons per year through 2027. As I've said before, those are our goals. They are challenging, but we are committed. CRC's footprint and expertise position us to be the premier carbon management provider in California. Carbon management is a natural extension of our core competencies, and CRC is able to bring scalable commercial carbon management solutions via our new entity, Carbon TerraVault. We continue to utilize both our expertise and our assets to help advance the energy transition for a lower carbon future. Thanks for being here today and your interest in CRC. I'll now turn it over to Joanna for Q&A. Thank you, Mac. We'll now open the discussion for Q&A. Please use the Q&A. Please use the raise hand function within Zoom and wait for your name to be called upon. We ask that you remember to take yourself off mute before asking your question. Questions may also be submitted via the Q&A function, and we ask that you include your name and your firm name with your submission. In order to get to as many questions as possible, we ask that you ask one question and one follow-up, and ask all your questions up front and re-queue if necessary. Thank you, and we'll get started. As a reminder, we have with Mac here today, Francisco Leon, our Chief Financial Officer, and Chris Gould, our Chief Sustainability Officer. Great. Our first question will be from Scott Hanold from RBC. Scott, you're open. Morning, Scott. Hello, can you hear me now? Yes. Can you hear me now? Okay. Scott, how are you? I'm doing fine. Thanks for that info. Appreciate the fact that obviously, as you mentioned several times, everything's still very early in the process, and you're all remaining pretty committed. When you step back looking at the economics, which I think is obviously key to understanding how much value opportunity this has for CRC, can you give us a little bit of color on any kind of discussions you're having or the agreements that you're seeing out there that are being discussed or maybe even signed in California at this point? When you look at that, the revenue-sharing opportunity with the LCFS or the 45Q, what are you seeing right now? You did obviously indicate you're risking, I think, the EBITDA by somewhere around 20%-50%, and there's also a 10% buffer. It'd be interesting to see what you guys are hearing and understanding everyone's unique as you go through these. Can you give us a little bit of color? Well, obviously, Scott, that's key to this whole new line of business. What I would tell you is that we are in multiple discussions. We obviously can't discuss those. I do think that as we look at defining the business model, that's why we laid out what the different business models are all the way from owning the source to owning the sink and everything in between. We have multiple discussions across a variety of different business models, and that's why we try to provide the economic type curve, if you will, for what we see as sort of down the middle of the fairway of a typical CTV project. Obviously, one of the things that we see is we probably on the front end, because we're looking to optimize our premier or flagship CTV I in the Elk Hills field, we're looking at lower capital cost projects up front, lower in the range, whatever that leads you to. We really can't go into the specifics of any one deal or any one discussion that we're having, given that those are all commercial arrangements. As I mentioned, they will all be highly negotiated and customized. We're hopeful that over the course of the next couple of quarters, we'll be able to put some more framework around that. That said, that's why we try to outline the $50-$100 a ton per year of EBITDA for a typical project, as we see that's in the middle of the fairway, if you will. Anything you want to add, Francisco? No, I think the only thing to add, Mac, there's a lot of people working CCS, in particular on the emission side, and we feel we have the right components through permitting the sink, the ownership that we have of Elk Hills to be able to take all of that CO2. High confidence in execution. We'll talk about details in weeks to come. Yeah, let me just add on to that, because you had a couple questions in there. One thing that I didn't mention. As I mentioned earlier, we are oversubscribed in the amount of CO2 that we could actually talk in the discussions that we're having. You asked about, is there an ability to describe what we're seeing in the market, and is there a model out there? The answer is that there's not a model out there. There are models that we are having discussions about, I don't necessarily know of a transaction that has been signed and in place that sets the framework for how people should think about this, and that's why we came up with the economic type curve. Okay. It's still a process, and it sounds very negotiated. I think it ultimately comes down to who really has the most leverage in this, in terms of capturing much of that revenue or credit value, I guess, at the end of the day. That seems like it's still in the discovery process, if I'm understanding you. It's still in the discovery process. We're the first commercial scale permit application out there that is open for business. It'll be defined over time. Coming from the renewable sector, it reminds me of thinking about when purchased power agreements in 1999. They had never been done before. Once that domino effect starts cascading, you have a model by which people use to bounce off of. You effectively get a boilerplate. It's not that easy, but you get a boilerplate contract to think about. Understood. Okay, as my follow-up question, again, I understand I'm probably going to get a very similar answer, I'm going to try anyway. Obviously, the other big part of this is signing up a CO2 source, the emitter, right? There's a lot of stars and circles and dots on the map around your acreage. Can you give us a sense of-- I know you probably can't be specific to exactly who you're targeting, the type of industries that you should all be targeting first. It's obviously going to be the more concentrated, the dirtier the CO2, the better. Are those sources in proximity definitely looking at having a conversation with you all? Does the eligibility for some of these sources for the LCFS credit, has that been something that's been part of this discussion, right? There's a lot of, do cement factories qualify for that credit, and should they be considered, right? How do you look at that and see that progressing? I'll give you a different answer. No. I'm just joking, Scott. Listen, obviously, we can't talk about the sources where we are, there's a couple of things. I mentioned the cement factory, SB 596. That's being developed. I think that'll eventually get to an LCFS-like outcome that'll have those incentives. As we look at Carbon TerraVault I, our first project, our flagship project, our premier sort of pore space, that's why we went forward with it first, is because we already had it in the works based off of working on Elk Hills field with CalCapture. We put that out there, and as we said before, that is specifically targeting LCFS compliance as a sink and an LCFS source to match with that. I would say that's how we're defining where we're looking at from a sources. We feel comfortable with the discussions that we're having, that there are viable projects and we'll meet this type curve. Our next question will be from Leo Mariani, with KeyBanc. Leo, your line is open. Morning, Leo. Morning, guys. Wanted to follow up a little bit on some of these economics that you threw out here. I know this is kind of a hypothetical case, but just kind of a few questions for you guys. I guess what kind of struck me is that the OpEx in the hypothetical case seemed kind of high. I guess I had more of a thought that there'd been maybe a little heavier on the CapEx and quite a bit lighter on the OpEx here, particularly because I know there's a midstream component, which certainly my understanding of that is usually there's not super high OpEx. Just wanted to get a better sense of kind of where some of that OpEx comes from. Just in terms of the $50- $100 per ton of EBITDA that you think a project generates, I just wanted to be clear on that. In this hypothetical case, would that $50-$100 accrue entirely to the entity that is doing the transport and sequestering, or would you have to share the $50-$100 with the emitter? Yeah, Leo, I'll take that one. To answer the second question first, when we talk about $50-$100 per ton of EBITDA, that's a net number to CTV, to Carbon TerraVault. That already assumes there's been a sharing of the economics throughout the value chain. That's our net number. To talk about OpEx and CapEx, our estimates are informed with active discussions that we're having. When we look at it and we're providing a business model where we can be end-to-end service or storage only, we kind of have to provide that big fairway because we're going to fit the projects in between that fairway. When we have the higher OpEx number, we assume that we're putting in the capture system, but then we're also managing that capture system. That takes into account potential separation, dehydration, compression to get it to that supercritical phase of CO2. You have to transport it, you have to inject it, you have to monitor it. That assumes that end-to-end cost structure. You look at it, where are you relative to existing infrastructure? Near Elk Hills, our energy costs are going to be very low. We can use our power plant. If it's outside of Elk Hills, then you have to look at non-energy costs. Sorry, you have to look at energy costs that you're going through the grid. If you look at the non-energy cost, you look at overhead, you look at insurance. If you deconstruct it and you think about, okay, what does this look like if you're building an end-to-end model, that's going to be your upper end of the boundary. You have to look at OpEx on a relative basis to revenue. If you're taking the higher end of the OpEx line and you assume that we're controlling the entire value chain, you're also then earning the majority of that revenue stream as well, right? We tried to guide, because we can't be specific at this point, we tried to guide it into a broad fairway. Ultimately, when you deconstruct it, if you take storage only, the cost profile is going to be much lower. If you're going to be end-to-end service, you're going to be on the higher end on the cost structure. On the capital side, that's the construction of a potential capture system of the pipeline. That will depend on CO2 concentration, that will depend on technology that's used on the capture system. On the pipelines, you're going to look at distance from source to sink. You're going to look at the volume that you can do as throughput. We understand that the ranges are pretty big at this stage, we think they're indicative of what our business is going to look like, ultimately netting down to the $50-$100 of EBITDA for Carbon TerraVault on a net basis per ton. Yeah, I'd also say that this is standalone project economics. We are fully burdening this. It's not as though you get to put this on the back of a different project. This is a standalone set of project economics that we're providing, fully burdened. Okay. That's very helpful for sure. I guess maybe just to kind of piggyback off that a little bit here, it certainly sounds like the high end of the range here on the OpEx assumes basically you guys may do everything in any kind of given project here. Maybe just to kind of get a little bit more down to where do you think the most likely pieces of the value chain that you guys participate on. Obviously, you control a number of potential sinks in the state. That seems to be the most logical answer. Transport obviously has some experience there. Do you guys think that it's going to be all that likely that you get involved in the kind of installation of the capture equipment, the operations on that as well? Do you think the kind of more economic parts of the value chain for you guys are just in kind of running the sinks and then potentially maybe some of the transport in certain situations? Look, I'll ask Chris to jump in on some of the capture that we've been looking at, but just realize that we've been studying CalCapture for a number of years, so we're fairly familiar, I'd say, with the engineering and the design work that goes through these amine capture systems. Obviously the capture system on a gas-fired power plant, because there's less concentration in the flue gas, is more costly than other sources, as you mentioned. When you look at the upper end of the range, it requires more capital. It gets a higher revenue stream, potentially has more OpEx. As we showed in the financial projections, the cumulative free cash flow, we have $1 billion that we are generating after we spend $1.7 billion to keep production flat, not just oil, but production flat for the next five years, while still sending 50% thereafter back to the shareholders. We can still take $1 billion, $1.2 billion, and put it into this business. It gives us capital to deploy in these different business models. We are open to doing the capture system. With respect to the capture system, designing it, and we have engineers that know how to project manage and to do those types of things, with respect to the capture system, we'll rely on other capture systems. Chris, you want to talk about some of the discussions you've had? Yeah. Just to build on what Mac said. We've been at this for looking at Elk Hills. We were one of nine projects for CalCapture that was selected by the DOE, and we've been involved in technology screening, both existing technology and amine systems that have been around for quite some time that are proven. As you all may know, there is a lot of emerging technology in capture space that has the potential to redefine the space from both a cost and resource perspective, such as water consumption and things of that nature. We're very encouraged by that. In addition to any policy changes that may help to incent capture on technologies such as combined cycles, with lower concentrations. We're also excited about our experience being put to work to help identify technologies that could be useful for the emission sources. As Mac referenced earlier, it's an evolving model. The discussions with emitters includes those exact discussions. What is the best technology? They look to us for insights into that and the ongoing discussion of who builds and operates it. Okay. We're going to move on to our next question. The next question will be from Doug Leggate of Bank of America. Doug, your line should be open. Morning, Doug. Okay. Doug Leggate from Bank of America, are you there? Your line is open if you're ready. Okay. We're going to keep things moving, and we'll come back to you, Doug, in a second. We'll take one from our Q&A. This is from Brian Singer from Goldman Sachs. He asked, "Without going too far down the path of specific deal considerations, can you talk about where the sources of CO2 are coming from, how far that CO2 may need to travel to get to a place like Elk Hills, and what industries are likely to comprise the biggest sources of your projects? Yeah, that gets into a lot of detail that would basically identify the sources themselves. Look, again, I think the answer is that we are looking to partner with a source or to provide the capture system from a source that is within reasonable proximity, that we have the ability to figure out the transport or have a right of way or pipelines that are easily accessible to figure out the transport. That is LCFS compliant, so therefore, it must be a transportation fuel. That's about all we can say on that front, unfortunately, at this point. Okay. We can go back to Doug, if you're ready. Doug, are you there? All right. Can you hear me now? Yes. Morning, Doug. Awesome. Idiots, guys. I didn't realize I was supposed to unmute the button. Okay, I've got a couple of questions, guys. Thanks for all the information. Mac, you mentioned that you'd be applying for Class II well permits for CalCapture, but you didn't mention anything about enhanced oil recovery coming out the other side of that. Can you talk about the production ramifications of going with Class II well permits? I think just to clarify, Doug, what we said was we have the ability or will be prepared to file a Class II permit, which would then be for the capture off of Elk Hills, the use of that carbon for EOR in an Elk Hills field. I forget the exact number of the barrels. Yes. 60? You're right. On the total reserve basis, about 60. Right. We estimate on average, about having about 8,000 bbl a day of incremental production due to the EOR. That's not a peak. That's more of an average over a period of a plateau, but the peak obviously would be higher. That's about 8,000 bbl of incremental production with about 1.4 million of injection of CO2 associated with CalCapture. But that's at a- Okay. Yeah, that's at a reservoir right there at Elk Hills. Yes, sorry, Doug. That would be incremental to the economics that you've already disclosed directly with the capture project. Correct. That's correct. Yeah, the economics are only for the storage business only. We haven't provided the economics for the EOR. Okay, thank you. My follow-up is Oh, okay. Hey, Doug, we'll come back to you if you're still on. You dropped somehow. Okay. We're going to go to a Q&A question from online. We have it from Nitin Kumar from Wells Fargo. Can you explain the comment regarding the assumption that tax credits are monetized? In reality, would the tax credits be an offset to revenues? The second question would be, is there any maintenance CapEx that could or would be needed? It seems like you are pretty much assuming build it, and then the rest is OpEx. Is that correct, or are those baked into economics? Maybe go at them in reverse. I view it as the maintenance CapEx is sort of built into the OpEx. It's sort of like having a long-term services agreement where you pay as you go, and you build up a pool of funds by which you would then have to reinvest what would be capital. It's in there. What was the first part, Joanna? I'm sorry. 45Q. 45Q tax credits. Yes. For simplicity's sake, we just showed them as in EBITDA, so in other words, as a revenue. The reality is, you're absolutely right. They are a tax credit currently and would have to be used that way. We would either have to have the tax appetite, or we'd have to find tax equity to monetize those. Maybe that is a point by which we can talk about what's going on in Congress right now. There's a lot of talk about 45Q being increased to $80+ and also being direct pay. If you look over time, some of either the investment tax credit with respect to solar, the PTCs, they have morphed into this ability to be tax pay, and it actually creates a easier system because it doesn't bring tax equity in for those that aren't taxpayers. Yeah, we did that for simplicity's sake so that we could show a full EBITDA. Great. Show it in EBITDA, so sort of a full cash flow. We'll take one more from Ray Deacon from Petro Lotus. What is the status of expanding LCFS to other industries beyond refining in the fuel sector? I'm sorry. The question is, what's the status of LCFS expanding to other industries beyond the refining or fuel sector? Yeah. As Mac mentioned earlier that there is a CCS protocol in the CARB achieving neutrality for net zero. When you look at the scope of the net zero goal and what has to be achieved in California, we are optimistic about the expansion of programs, whether they be LCFS, cap and trade, or other incentive-based programs that are going to be needed for California to achieve the goals that are set out. We're encouraged by the recent Senate Bill 596 around cement. Net zero cement is an industry that's currently not covered or eligible for LCFS under the CCS protocol or otherwise. We see that as a very positive sign and a sign of things to come that are going to be needed to expand the incentives and the economic model around achieving net zero in California. Yeah. The governor also floated a energy bill that didn't actually make it to the floor. In that bill, it addressed mostly energy policy, electricity policy. One of the things that it said was it mentioned gas-fired power plants and the need to address carbon dioxide or greenhouse gases off of gas-fired power plants. Again, if that was to take a similar form as of SB 596, now you have a growth that is piggybacking the LCFS type framework, or what we think will piggyback the LCFS framework because, as I mentioned, it drives economic CCS, and economic CCS is needed in order to achieve net zero by 2045. In fact, some of it's needed to achieve the 40% reduction by 2030. Great. We're going to circle back to Doug, who submitted his question via Q&A. Seventy dollar oil is assumed. How low can your oil price assumption go, and still commit to self-fund the project? You take that? Yeah. I think the nice thing is, we have the capacity to self-fund a big portion of our projects on carbon management. We're building the cash flow. We have really high confidence in the cash flows from our very low decline asset base. That creates a lot of flexibility, a lot of options. We will look at other financing alternatives. We will look at the DOE Loan Program, may be a good fit for some of our projects. We might look at equity to come into different parts of the structure for these carbon projects. The reality is, we have a model where we can self-fund a big portion of it, but we don't have to. We'll just have to look at the best cost of capital and the best avenue for high returns. Ultimately, $80 oil today makes the EOR project a very exciting one. To be clear to the question you asked earlier, it is not in our projections in the cash flow profile, the incremental that comes from that oil, so that we haven't captured that in there. We'll just look at what the financing options are available to us. If it makes sense for us to step in with our own cash, we'll do so. One of the interesting things is we're seeing a great evolution of financial products that are coming out. They might not be in place today. People are still trying to get their head around how to invest into CCS. As we put forward the business model, the financing solutions will come behind it and give us a lot more opportunity to think about how to best use that cash to make that project a reality. Doug, apologies if the IT issues are on our side, but good question. I think one of the things that I said during was our cumulative free cash flow is now at 2.5 at the current deck, as we outlined in the footnotes or the assumptions that you'll see there, versus the strategy day in March, which had a different pricing deck. That's about a $1+ billion difference in the free cash flow. I think that is literally going from $70 down to around $60, give or take. You can see it in the notes on both of those days. That would go down. Let's just take that. Right now, at this current deck, we're saying we have $1.2 billion. That would cut it down to $600 million, and that's just the equity portion, as Francisco is saying. As we develop these projects and we structure them up, we believe that they will avail themselves to project financing and incremental sources of capital. One of the things that we discuss all the time is that after we had the second quarter announcement about filing the permit, I like to say we started having inbounds. Inbounds of the two Cs for carbon capture and sequestration, not capture carbon, but carbon and capital. We think that there's going to the ability to do capital raises at the project level that will leverage that free cash flow that we have. I think the point we're making is that because of our base business and the low decline, and because it throws off these stable cash flows, we find ourselves in the unique position of being able to fund several of these projects with higher capital costs. Again, we're targeting the lower capital cost projects on the outset. Thank you. We're going to move to a question from our phone line. We have a question from Neal Dingmann from Truist. Neal, your line should be open. Morning, Neal. Can you hear me well? Can you hear me? Sure can. How are you? Hey. Good details so far. Thanks, Mac. Interesting comment you made earlier that when you look at these projects, the scope of the projects could be anything from the full CCS or the capture transport storage to just storage, given obviously what the advantage you have. How would you determine that? You obviously have a lot of advantages by having these assets in place. How would you determine maybe early on about just tackling the storage first and taking some fees versus, "Hey, we want to handle all three? Well, look, I think, Neal, the answer is we're actually a bit agnostic as to where we are on that. Obviously, the risk is different, right? The more capital deployed, the more capital's at risk. The storage we have, we have to put capital in. We'd have to put capital in to connect and midstream and gathering, sort of field gathering. P&A work that has to be done to prime the fields, et cetera. I think it really comes down to when we find the counterparty or partner, what are they looking for in the deal? Given that, again, we have this cash and we have the ability to deploy it, we're willing to deploy it to make the right partnership happen. It's really going to depend on the nature of the deal, Neal. Okay. As you said, really, there's not a comparable out there, what makes it difficult for us analysts. You guys have done a good job on attempting to put a timeframe out there. I'm just wondering for the three of you all maybe to comment on what do you think are options as far as what could run ahead of schedule? I know a lot of things you're talking about 2025 coming on, but I know you have some optionality even before that. I'm just wondering, maybe in the next even year to two, what are some of the things that you would highlight or get you most excited maybe for the next year or two? Chris and Francisco can chime in here too, but there's that schedule that we laid out, and it talks about permitting. I don't see permitting being accelerated. I think it's going to use the two years because, as I've mentioned in past times, the Class VI permits in the past have taken six years to do. The EPA has said that they're trying to shorten that to a two-year period, and we're working hard to provide whatever's necessary and working with the EPA to get that done. I don't see that taking a shorter timeframe. During that time, identifying sources, structuring the deal, doing the necessary engineering and design, whatever's required there in order to get to FID. We're hopeful that what we do is that we have a permit, we're ready to go FID thereafter. On the right-hand side of that slide, I guess, that shows sort of the cash flows. We show that as having some negative cash flows in year one and year two, the reason why we do that is because it's getting exactly to your point, which is if we felt like we had a good partner and a source identified, we had that partnership identified and there were long lead time items, whether it be CO2 compressors or spending money on engineering design, or there were pipe retrofits that needed to happen, plug and abandonment. We would go ahead and do those in anticipation of getting to FID, provided, obviously, all of this is board dependent, I guess I should say make sure I say that, because it's going to be dependent upon the investment decision. We see those as accelerating and possibly then saying you could get to injection quicker. Again, it's all going to be case by case dependent and partner by partner dependent. Well said. Thanks, Mac. Okay. Thanks, Neal. We have Ray Deacon from Petro Lotus with a follow-up. As California moves to reactivate some combined cycle gas-fired power generation because of the tight power markets, is it likely to create more potential customers? Is it right to assume that these plants don't fall under LCFS even though gas is also used as a transportation fuel? Yes. The second part of that is correct. The gas plants don't qualify. That's one of the biggest. Quite frankly, if you look at CalCapture, we're capturing a million plus tons off of the power plant, at least that's the design, off of the power plant, in total, 1.4 million tons, but only about a third of that counts for LCFS because only a third of the power plant is used to generate oil or the transportation fuel. The other 2/3, it goes out to the grid and supports the grid. We have a power plant that is just like those power plants coming back online. That's one of the great debates, because you see the electricity grid in California, and there's a big debate about the stability and the move to renewables, that you're going to need gas plants as well. If you need gas plants, how do you get to net zero? That's why they need to be included. Do you want to pick up on that, Chris? Yeah, I think that's right. There are multiple mechanisms, as I mentioned previously. It could be an expansion of a LCFS type market for energy. It could be inclusion in the cap and trade program, such that CCS was viable for natural gas plants to alleviate what Mac just referred to. I think there's been some good studies out there that show that on a net basis, CCS for the combined cycle fleet is a better economic alternative for the California ratepayers than storage at this point, just given where the cost structures are. We would be very encouraged to see those expansions because we think it would be in the best interest of the energy customers in California and helping to achieve, and get to the net zero goal. We have a quick modeling question from on our Q&A. Can you walk through how on slide 18, you go from 170-200 ton incentive potential down to $50-$100 a ton for EBITDA? The second one would be: How does the $200 million-$800 million square with the per million metric ton CapEx number that you've provided? The first part of the question. This slide's meant to provide that modeling overview best we can give it, and that's why we came up with the economic type of concept. It's inputs into a model. You can see some of the footnotes in the back. We did apply some risking to the LCFS pricing. Last week's price on LCFS, for example, was $180 a ton. We're applying some risking to that just to be conservative. The way to think about it is, you have on the P&L, you have the revenue line, and you have your OpEx as a big component. We're trying to guide to a net number. You have to triangulate a little bit what we put on the slide, but you are trying to guide to what we think that the net number to CRC is going to be. That's the $50 - $100 per ton. What you have to assume is that the rest of it is being shared along with other potential participants in the value chain. Because we're not saying we're only going to do storage or we're only going to do end-to-end, we're basically walking through a framework that allows you to see, here's the incentive, here are the costs, and then there's a split of the economics along the way. That's the implication of the numbers in the slide. You kind of have to walk through that. The way we thought about the per unit cost in our economic type curve is we take the total cost of the project, and we divide that by 40, in this case, or by the total amount of the storage tank. Where we said CapEx between $200 million and $800 million, you divide that by the resource life, just like we do F&D in oil and gas, to be able to come up with a per unit estimate on that capital. We also are showing on the right side of the page that if that capital really, it's more construction capital that happens upfront. That has implications into your NPV or your IRR, but we're guiding to, okay, what is the total cost on the system if you were to do this on an annual basis to provide that modeling overview that should be able to come up with the cash flows and then assume, like I said, assume sharing along the way from different parts of the value chain and getting to our $50 - $100 per ton of EBITDA. Just to expand on the point, I want to mention one other thing. What we see is if you look at, we have a target of a million tons of injection by 2025 and five million by 2027. We see this as a big contributor to our business. If you kind of walk through the math of that, our range is about $250 million-$500 million of EBITDA on a total basis once you have five million injection already put in place. Assume the mid-point, $375 million-$400 million of incremental EBITDA. That represents roughly 50% of the EBITDA of our E&P legacy business. You put that on top of it, over $1.2 billion of EBITDA in five years, that's about a 10% compounded annual growth rate, assuming the base business is stable, prices stay where they are from the oil and gas side, and this kind of builds on top of that. We see this as a very exciting business opportunity for CRC, and we'll provide a lot more details when we can after we negotiate this contract, but this is the framework to help you think about possibility, the value proposition of Carbon TerraVault. We're going to take one more question before we wrap things up. We have a follow-up from Scott Hanold. What should be the key next steps for investors to watch? Is it a contract with the CO2 source, and when does this need to occur by to stay on track? Yeah, good question, Scott. I think there's a couple goalposts as we go through permitting. That's one. As we evolve through that, we'll let you know. With respect to sources, obviously active doing that. I don't know that there's a hard and fast date. Obviously, if you push things all the way to the end, you start getting into critical path of trying to meet our objectives of first injection. As I said before, and I think this is an important part, one of the things we did by filing the permit, and we're going to file on the heels here to get the full 40, or up to 40, is take the critical path, the long pole in the tent out, if you will. Now we've compressed the schedule. Now we're thinking about, okay, at what point do we need to make sure we have a source and then do the engineering, et cetera? I don't know there's a hard and fast date, but I would think over the next, in 2022, we're going to be working really hard to put a million tons per year subscription into CTV I. Thank you. There are several questions that we didn't get to. We invite you to email those over to Danny, Jack, and I in IR. With this, I'll turn it over to Mac to close. Well, great. Thanks, Joanna. Thank you everyone for joining us today. We appreciate your interest in CRC and Carbon TerraVault, and we look forward to providing more updates in the future. Have a great day.