Good day and welcome to the Talos Fourth Quarter 2021 earnings call. All participants will be in listen-only mode. After today's presentation, there will be an opportunity to ask questions. Please note that this event is being recorded. I would now like to turn the conference over to Sergio Maiworm, please go ahead.

Thank you, Operator. Good morning, everyone. And welcome to our Fourth Quarter 2021 Earnings Conference Call. Joining me today to discuss our results are Tim Duncan, President and Chief Executive Officer. Shane Young, Executive Vice President and Chief Financial Officer. And Robin Fielder, Executive Vice President, low carbon strategy, and Chief Sustainability Officer. Before we get started, I'd like to take this opportunity to remind you that our remarks today will include forward-looking statements. Actual results may differ materially from those contemplated by these forward-looking statements. Factors that could cause these results to differ materially are set forth in yesterday's press release. And in our Form 10-K for the year ending December 31st, 2021, filed with the SEC yesterday. Any forward-looking statements that we make on this call are based on assumptions as of today. And we undertake no obligation to update these statements because of new information or future events. During this call, we may present both GAAP and non-GAAP financial measures. A reconciliation of GAAP to non-GAAP measures was included in yesterday's earnings press release, which was filed with the SEC, and which is also available on our website at Talosenergy.com. And now I'd like to turn the call over to Tim.

Thank you, Sergio. I'll first discuss our results for the fourth quarter of 2021. We delivered a strong operational and financial performance to conclude 2021, starting with achieving another record quarterly production milestone of 68.7 thousand barrels of oil equivalent per day. Our production is favorably oil weighted for the current commodity environment at almost 70% oil and 75% total liquids. Our margins were very strong. We generated adjusted EBITDA per barrel of oil equivalent of over $30, or over $46 when adjusting for the cash hedge losses in the quarter, which demonstrates the benefit of our strategy of adding new high-margin, oil weighted production through Talos owned, largely fixed cost infrastructure. Lastly, we generated very strong $93 million of free cash flow in the quarter. For the full-year 2021, we also delivered record production of 64.4 thousand barrels of oil equivalent per day for the year, despite third-quarter downtime associated with Hurricane Ida. An annual increase of approximately 18% over 2020. This led to adjusted EBITDA of over $600 million in free cash flow of approximately $135 million. This strong performance allowed us to significantly reduce our leverage ratio and increase liquidity throughout the year. And Shane will provide those details shortly. Operationally, our team had an outstanding year that goes beyond their efforts on production and cost control alone, recording zero lost time safety incidents in 2021 and continuing to drive down recordables from already strong levels amongst our offshore peers. For the third consecutive year, we recorded zero hydrocarbon releases of more than one barrel offshore and further reduced our GHG intensity, putting us ahead of schedule to achieve our 30% reduction target by 2025 from our 2018 baseline and on track to meet our stretch goal of a 40% reduction. Turning to our Carbon Capture business, as a reminder of our entry into this attractive business opportunity, Talos conducted an in-depth review in late 2020 and early 2021 on how we can best utilize our skill set to contribute to the energy transition and decarbonization. Our expertise with conventional geology combined with our operational capabilities make carbon capture sequestration a natural fit. We rapidly formed a team and very quickly we achieved success, being named the operator of the state of Texas' first offshore carbon sequestration site, or the GLO site, just offshore of Jefferson County. Since that milestone, we've accelerated progress and we've quickly established a strong portfolio of both physical process projects as well as alliance and partnerships across the value chain. In the fourth quarter, and subsequently in the early weeks of 2022, we also made significant strides with our carbon capture business, announcing a technical alliance with TechnipFMC, our first point source project, and our next regional hub project. The Technip alliance will accelerate front-end engineering design, or feed processes during project development phase across our CCS portfolio. And moving forward, it's going to save us significant time and money. The project with Freeport LNG, one of the largest LNG export facilities in the world, will develop a custom point source solution to capture, transport, and sequester CO2 emissions on-site at the facility along the Texas Gulf Coast. This will be one of the first commercial dedicated sequestration projects along the Gulf Coast and a model for decarbonizing an important source of global energy. And then, most recently we announced our Riverbend CCS project in collaboration with EnLink Midstream, which is the first CCS project along the Gulf Coast to offer an integrated transport and sequestration solution to potential customers. Due to the outstanding geology, including a 3,000-foot saline aquifer column, and a large surface acreage footprint, the project holds significant capacity of over 500 million metric tons. It's coupled with EnLink's over 4,000 miles of pipe that are connected to a large customer base of industrial emitters. It's one of the largest announced projects to date and the first with a fully integrated midstream and sequestration solution combined. The Riverbend project is strategically located along the Mississippi River corridor between Baton Rouge and New Orleans, where the highest industrial emissions regions in the United States, it provides a huge addressable market. We look forward to advancing this project in the coming months. We've already begun engaging with potential customers. On our last call, we were confident we would continue to build out our portfolio of CCS projects and become a visible market leader. We're thrilled with the progress we've made and are continuing to pursue a variety of business development opportunities across the Gulf Coast while advancing key milestones in our current projects. To further drive that business, we proactively added a new key executive from our team to lead our CCS efforts as well as our broad sustainability efforts across the company. Robin Fielder brings a diverse background of technical and commercial expertise ranging from in-field engineering roles to most recently the CEO of two publicly traded midstream companies. I think she is going to do a tremendous job building our CCS business and positioning us as the sustainability leader. Robin is joining us on the call this morning and is available for Q&A at the conclusion of our prepared remarks. Turning back to our upstream business with year-end reserves, we concluded the year with $162 million barrels equivalent of proved reserves which is approximately 84% proved developed and 69% oil. This reserve base held a PV-10 value of approximately $3.9 billion at year-end utilizing SEC prices of $66.55 per barrel and $3.60 per MMbtu. At a price sensitivity of $80 per barrel, more reflective of today's commodity environment, our proved reserves carry a PV-10 of over $4.9 billion. These reserve figures are fully audited and include all PNA associated with those properties in the report. Importantly, we hold an additional $60 million barrels of probable reserves with the PV-10 at SEC prices of $1.4 billion. Our reserve base is very solid, and we see significant unrecognized fundamental value that we aim to unlock in the future. With that, I will turn it over to Shane to address some of the financial details of the quarter and the full year, as well as an update on our 2022 operational and financial guidance. I'll then conclude with more details on our 2022 capital program and some closing remarks.

Thank you, Tim. And thank you everyone for joining the call this morning. This morning, I will discuss our fourth quarter and full-year 2021 results. In addition, I will cover our guidance for 2022 as well as our financial goals for the year. Production for the fourth quarter averaged 68.7 thousand barrels equivalent per day and was highly liquids weighted at 77%. This is at the high end of the production range provided in our operational update earlier this year and benefited from efficient operations and extremely high uptime in the quarter. Lease operating expenses for the quarter totaled approximately $75 million or less than $12 per barrel equivalent, while recurring cash G&A totaled $16.4 million or less than $3 per barrel equivalent. As a result of strong production, high realized prices of approximately $74 per barrel and over $5 per MCF. Competitive cash costs generated adjusted EBITDA of $190.4 million for the quarter. Further adjusting for realized hedge losses, the core operating business generated adjusted EBITDA of over $291 million. These results equate to strong net backs of over $30 and $46 per barrel equivalent respectively. Net income was a positive $81 million equating to $0.98 per share. Adjusted net income was $37.4 million or $0.45 per share. All of these after realized hedge losses of approximately $100 million in the quarter. Capital expenditures totaled $64.2 million, resulting in free cash flow before working capital of just over $93 million during the quarter. Turning to full year 2021, Talos generated average production of 64,400 barrels equivalent per day, again, highly liquids weighted and approximately 18% over 2020 production levels. Adjusted EBITDA for the full year was $606.5 million, inclusive of the impact of $290 million of realized losses from legacy financial hedges entered during the early COVID-19 pandemic. Capital expenditures were approximately $339 million for the full year, which is below the low end of our 2021 guidance and equated to a 56% reinvestment rate. Ultimately, Talos generated free cash flow of $134.5 million for the full year before working capital. In 2021, we used a significant portion of our free cash flow to repay borrowings under the company's credit facility. Over the last three quarters, Talos has rapidly reduced leverage by almost one full turn and reached a leverage ratio of approximately 1.7 times at year-end. During 2022, we expect to continue to deliver strong free cash flow and will continue to prioritize further debt reduction. To that end, we expect the company should achieve approximately one times net debt-to-EBITDA by year-end 2022 and will be within our one to one-and-a-half times target leverage range over the next quarter or two. Finally, liquidity built rapidly over the course of 2021 with approximately $135 million of free cash flow before working capital and the addition of two new banks to our credit facility. As a result, year-end liquidity stood at $473 million. I'll now address some of the details of our 2022 guidance disclosed in yesterday's press release. Starting with production; we expect daily production to average between 60,000 and 64,000 barrels of oil equivalent for the year, roughly consistent with our 2021 production levels. Factors, including both planned downtime and recent third-party unplanned downtime, negatively impacted 2022 production guidance by approximately 3,000 to 4,000 barrels equivalent per day. The planned downtime relates primarily to the previously disclosed HP-1 dry-dock process, which will have a 2,000 to 3,000 barrels equivalent per day impact for the year. The HP-1 floating production unit is the vessel that handles volumes from our Phoenix and Tornado fields. For regulatory requirements, the vessel undergoes maintenance every several years of 45 to 60 days, during which production is deferred. This dry-dock window will begin in the second quarter and will be completed during the third quarter. This process addresses key regular maintenance items, which in turn extend field life and contribute to the fields' otherwise extremely high uptime. Second, our full-year forecast includes the impact of recent third-party midstream downtime from the Eugene Island Pipeline System in the first quarter of the year. We expect EIPS to return to service imminently, and that it will result in a 3,500 to 4,000 barrels equivalent per day impact in the first quarter, and approximately 1,000 barrels equivalent per day over the full year, 2022. For 2022, we expect cash operating costs of $300 million to $320 million and cash G&A expenses of $68 million to $73 million. Operating expenses are inclusive of approximately $20 million of HP-1 dry-dock related costs as well as our full-year expectations for cost inflation. G&A also includes incremental expenses over 2021 to allow for the additional build-out of our rapidly growing Carbon Capture business. Capital expenditures for the year are expected to total between $450 million and $480 million. Roughly 65% of the program will be invested in asset management, lower-risk infield development around our own infrastructure and high-impact appraisal and exploitation projects. The balance of the program will be invested in G&G, land, TNA, CCS, and other capitalized items. Capital expenditures are expected to be slightly weighted for the second half of the year when we expect to have our open water drilling operations active. Due to the timing of a portion of the drilling program and completion lead times, approximately 50% of the 2022 drilling and completion investment will come online and begin generating production adds for 2023 and beyond, supporting our future production growth. On our CCS business, we will be disciplined and measured and expect to invest approximately $30 million during 2022. This year's capital program is exciting for Talos. It includes spending to support our base production, as well as investing and production adds for future years. It exposes capital to material resource additions through the drill bit and progresses our leadership position in Gulf Coast Carbon Capture and sequestration. Our reinvestment rate for 2022 is expected to be approximately 55% when looking at upstream investments alone, with an additional 4% to 5% when factoring in investments in carbon capture and sequestration. Given current market conditions, we expect this plan to deliver significant free cash flow during the year. As previously mentioned, our primary objective will be debt paydown. We expect this to result in reaching approximately one times leverage by year-end 2022, ending the year with lower leverage and greater liquidity than Talos was pre-pandemic. On the equity side, trading liquidity and Talos stock has significantly increased throughout 2021 and is now 4 to 5 times the daily volume we enjoyed pre-pandemic. As a significant shareholder has exited its position in the stock after a long-term investment, we believe the previous technical overhang in our trading has been largely resolved and should accrue to the benefit of stockholders going forward. With that, I'll hand the call back over to Tim.

Thank you, Shane. As Shane discussed, in this year's program, we will still have our normal balance of asset management projects and development drilling, including our platform rig work on the Pompano facility, but we will also focus on growing reserves and investing in projects that will provide impactful production. In the second half of 2023 and into 2024, our focus area will be a series of subsea tie-back drilling projects and the Mississippi Canyon Miocene Corridor for two to three operated projects that would tie back to the Talos operated facilities more specifically around our Pompano and Ram Powell facilities. Our working interest levels on these projects will be between 50% and 60%. We will also participate in three additional non-operated subsea projects that will also tie back to local infrastructure and in these projects, we will have a 20% working interest. These single-well tiebacks can generally provide initial gross production rates between 5,000 and 10,000 barrels equivalent per day per well. In our Puma West discovery, we look forward to initiating our appraisal well in the second half of 2022 with our partners BP and Chevron with BP as the operator. The goal of the appraisal will be to delineate the resource discovered in the original well as well as evaluating additional perspective Miocene sands. The initial sub-salt discovery was drilled to a depth of 23,350 feet and is surrounded by prolific fields with similar rock and fluid properties to those we found in Puma West. These adjacent fields also represent nearby opportunities to accelerate production utilizing the unused capacity of these facilities. Because we suspended the discovery well, as a keeper, if we're successful in our appraisal program, our hope and expectation would be to accelerate development as a multi-well subsea tieback to one of these nearby facilities. Our capital guidance with respect to our growing CCS business allows us to advance feed work and drill multiple stratigraphic test wells on previously announced project sites to advance the required EPA class 6 permitting process during the year. We have also set aside lease costs to continue to grow our portfolio and hope to announce additional progress on that front soon. We truly believe we found a new vertical business that's not only critically important for lowering industrial emissions broadly, but a great transfer of the expertise we have in-house. I'm proud of our team's effort in moving quickly and with conviction that we will become a market leader. To wrap up, our 2022 plan delivers stable production, high margins, and significant free cash flow while our capital program is targeted at optimizing the resource and skill sets that make Talos unique amongst U.S. EMP companies. Access to material conventional offshore resources across the risk-reward spectrum provides Talos opportunities to build the business in the future and differentiated carbon capture and sequestration opportunities in an evolving industry, all of which we believe will build material long-term shareholder value. Now, as Shane mentioned, we've also experienced a challenging technical headwind in our stock throughout the past year. With that selling pressure alleviated and as the trading liquidity has increased, we believe it's a net positive for equity holders, anchored by higher impact subsea drilling projects from our existing inventory, both into the 2022 budget and in the coming years. We expect that our base business can generate over a billion in free cash flow through 2025. So, technical challenges removed, incredibly strong fundamentals driving the base business for several years in the future. Plus, diversification of rapid growth in our Carbon Capture business. We think Talos is very attractively positioned and represents a highly compelling investment opportunity. We look forward to an exciting 2022. With that, Operator, will open the line for Q&A.

Thank you. We will now begin the question-and-answer session. Our first question comes from Subash Chandra with Benchmark Company. Please go ahead.

Thanks, Tim. A billion dollars is a significant number. I just wanted to first, before I get to that, talk about CCS. What is the pathway first to get to definitive status on the projects you're working on and then the pathway to FID? Where does the class 6 permits fit in this process?

Thank you, Subash. I hope you're doing well. Let me share my perspective on the high-level aspects of your question, and then I’ll turn it over to Robin for further insights. These projects we've previously discussed consist of three components in the value chain. It begins with an emitter who needs an incentive to capture their carbon, as they may have the opportunity to retain some credits by doing so. Next, we have the transportation, storage, and monitoring aspects. Currently, we can control the storage and monitoring components while collaborating with emitters on the transportation side. Ultimately, all these elements need to come together before we reach a final investment decision. This is why a point source project, like the one we have with Freeport LNG, can progress faster than a hub project, which includes storage and midstream efforts—such as our alliance announced in Riverbend with emitters. There's a lot happening to reach a final investment decision. Robin, you might want to add comments regarding the EPA permit process, because when everything is combined, we enter that stage, and I can also mention what we are doing to speed up these processes.

Thanks, Tim. And good to hear from you. As you mentioned, obviously the anchor emitter is a key piece, but for all three of our projects, for Freeport, our Jefferson County GLO acreage, and the newly announced Riverbend CCS project in Louisiana, we want to continue to advance the pre-FEED work. Part of that is to go out and collect data necessary to file these class 6 permits. So that's part of what we talked about drilling these stratigraphic test wells, collecting some additional subsurface data to help us better characterize the reservoir to ensure that when we apply for these permits, we've got sufficient data included in that application process to push that through in a timely manner. As far as the timeline on that, as you know today, the regulatory body overseeing those class 6 CO2 injection permits is still the EPA. The state of Louisiana has filed for primacy, and we would expect to hear something hopefully later this year on that. We think the state of Texas will be not too far behind on filing for primacy as well. That will be a key piece of our timelines here. Meanwhile, again, we're working with our technical alliance on some of the wellhead and subsurface pre-FEED and advancing into feed work as we advance all three of these projects, both on the onshore stores and then, the GLO, which is in our shallow state waters.

To wrap that, we've advanced from, I think, a couple of calls ago. We have a goal of establishing store regions where we know there's a big industrial emitter addressable market. Can we partner with midstream players? You're seeing that. You're seeing the advancement the teams work so hard on. Now we have things we need to execute on, so you have seen the stratigraphic test, but we still have ambition on what else we can build out throughout the Gulf Coast from a business development standpoint. Last year was extraordinarily busy for the team, and now it's got some great leadership with Robin, and we expect this year to be equally busy, if not busier.

Yeah. Hey, Robin, good to see you again as well. Tim, I guess the terminology on MOU versus definitive, etc. what's the moving parts there to get from one to the other?

Look, it's a good question, and it's funny. There are often when we have a mature business like what we have on the oil and gas side, and people want to say, hey, look, you announced things when they're definitive because it's so easy to get to some definitive agreement, if someone is selling an asset, none buying an asset, you'll hear about that where we're at a definitive agreement. Here, we're moving very quickly. We want to establish this business. We want people in the market to know that we're here and that we're working. We're not alone in that and that's why sometimes it makes sense to put an MOU together where we add another counterparty. For example, the agreements say, hey, look, we've got assets that we think are very interesting. We entered this lease that they compelling lease relative to the addressable emitter market, and they've got a great asset and infrastructure in their pipeline network. Why don't we collaborate to see if we can pull this together into a project that ultimately, again, reaches up by and builds a business for both of us? So that's a memorandum of understanding as we work on that together, and as we hope to pull that together, that then becomes, it works itself into a definitive agreement. But again, you need that anchor emitter that Robin alluded to. Until you get that, you've really got to work, you've got to collaborate more before you enter into a definitive agreement. It's just a different process for an evolving business than what we would have in a more mature business. Robin, you have anything additional to that?

All great comments. The only thing I'll add, as Tim was alluding to, is we're letting the market know that we now have a bundled solution in that Baton Rouge, Mississippi, River, New Orleans Corridor area.

Again, that model is going to be duplicated in other areas for the same reasons. You want to be able to look for an obvious partner, a side you're going to collaborate, but really what you're doing in that collaboration is looking for the industrial accessible and meta market that you can pull into the store you're creating.

Okay, got it. And my follow-up, so the billion free cash flow is close to the market cap, etc., over four years it sounds like. How should we think about that? Are you going to buy back every single stock? I suppose a good amount of this that goes into future opportunities, but how do you think of that post-2025?

No, that's a great question. There are definitely some gaps here since Subash has covered most of my questions. But to put it simply, looking at this year, we generated $135 million in free cash flow. We implemented some hedges in 2020 when the pandemic began to ease, but lower oil prices led to hedge losses. If we factor those losses back into our operations as the market improves and project that over a couple of years, it's reasonable to foresee our business generating over a billion dollars by 2025 as a starting point. Now, regarding our main objective, I’ll let Shane chime in too. Ultimately, we aim to reduce our debt to one time, which was around 1.2 to 1.3 before the pandemic. That reduction kept us around 2.5 to 2.6 when prices dropped, and we are gradually working towards bringing that down again this year, aiming for one time. This is our main focus, and it should remain our priority through much of this year. Beyond that, we have ambitions to return capital to our shareholders. Shane, please continue addressing the question.

Yeah, happy to do that. So, look, I think it's exactly right. We went through, we were in last year 2.6, we ended this year at 1.7. So rapid deleveraging. We paid off just under $100 million of debt over the course of the year. We intend to stay the course until we get down to one time. I think our range that we put out for a period as we want to be between one and one-and-a-half times. We think we'll get there inside that range over the next quarter or two and then we intend to keep driving down below there. I think as it relates to that longer window, the Tim talks about. Look, obviously, a lot of things are around the table you mentioned, essentially M&A. I don’t know that M&A is mutually exclusive to other things because we tend to do our M&A in ways that keeps the balance sheet in good shape. But I think then that opens us up to the possibility of getting into more return of capital-type activities and taking it forward from there once we hit that 1.1 times leverage marker.

Excellent, thanks.

Our next question comes from Michael, please go ahead.

Good morning, everyone. Congratulations on your new position, Robin. I'm excited to work with you again. It appears that the CCS business is progressing faster than expected. You've set aside about $30 million for it this year. As you look ahead, do you believe that during this testing and pre-class six permit phase, this will be the level you anticipate for the business over the next couple of years, or do you expect it to grow more rapidly?

Well, look, I mean so there's a couple of things. I think we go back to previous calls, Michael. We've talked about this at some conferences before. We had to ask ourselves once we really started thinking about how we play into transition. We're conventional geology professionals here; it's what we know. Can we utilize that skill set? We're offshore operators; we know that. Gulf Coast operators from previous companies, and we decided to play into the CCS evolving industry. Once we put that bidding on GLO and were lucky enough to be a successful bidder, we really looked around the room and said, why aren't we trying hard across every space that we know and understand? State regulated for space, private ownership for space. Hopefully one day federally regulated for space that all can be used for purposeful sequestration. Once we built that team, we were about it. We were really working hard and that came with the point source announcement. You've seen the River Bend announcement. We've said in previous calls, and I think in even previous decks we expect to do more. And I would still say that. I think that there are plenty more opportunities to explore and develop.

I'll just say with increased success and as we continue to look across the U.S. Gulf Coast, there are opportunities where you've got a stacking of the space and contiguous leasehold at the surface and local emissions; we will continue to advance these projects. We talked about getting in from pre-FEED moving into FEED and developing what that development plan looks like while identifying how many injection wells. With success, again, over time, yes, we would expect to continue to put forth the dollars needed to advance these projects and get not just our Freeport point source online in the next few years but to position these hubs to be able to come online in just a few years’ time.

I think the capital spend we have in that program is appropriate. It's not too much, but it's enough to make sure that we're addressing what we think is needed to get these projects to FID and then bringing forth more announcements shortly.

Well, good. I look forward to those. Want to see if you could talk a little bit more about your Miocene exploration wells that you plan this year. I assume those don't depend on the November lease sales going through. I know at one point, you had anticipated some of those, but do you already have partners there? Do your plans change if the interior comes back and says those lease sales aren't going forward? Anything more you can tell us about those?

These are all good questions, and we'll categorize them. First, the leases we plan to draw this year are based on executed agreements. It's understandable to question permitting and potential scenarios during politically uncertain times. As we've mentioned in previous calls, we haven't experienced any delays on permits with a strong precedent record. This applies to drilling permits, recompletion, and asset management activities, including plugging and abandonment. These permits are being processed in due course, mainly due to the existing lease agreements between us as the operator and the government. This applies to all of our drilling plans for this year. Regarding the recently vacated lease sale, we were very close to finalizing those new lease agreements at the time of the cancellation, which is disappointing. However, I won't comment further on energy policy during this call. It's essential to emphasize the need for robust offshore development, which we currently have under the lease agreements. With respect to Mississippi Canyon, just to kind of get into that a little bit, some of that depends on the timing of how we do transactions. As you know, last year was heavy in the Green Canyon area, including the Puma West discovery because we did some transactions several years ago that led to more science, more reprocessing of the seismic. That was great. We're thrilled with what we did in the Green Canyon area. It was also a little bit defensive. It was heavy on development because we were in the middle of recovering from a pandemic which led to our highest level of proved developed reserves at the end of last year’s report. As we move into Mississippi Canyon, these are more exploitation and exploration. They're one-well subsea tiebacks. Think of these targets as $10 to $20 million barrels gross oil equivalent type targets that are within 10 miles or so of our facilities. In this case, facilities we operate at Pompano and Ram Powell. There are also some things on the non-op that have a similar profile. The difference is working interest. We have partners very close to being lined up. We don't get a rig until the second half of the year, so everything timing-wise is working out. As we roll out some corporate decks, we will give you some more details on these as well. Look, we're really excited about it. As you know, Mississippi is a prolific area. It's an area where we want to spend quite a bit of money and reinvest in the business. Last year, Green Canyon was a great program, we're just moving it to the east this year. Also, with some appraisal of Puma West in the second half of the year.

I appreciate the color, Tim, thanks.

Our next question comes from Steven Dechert with KeyBanc. Please go ahead.

Hey, guys. I just wanted to follow up on that Class 6 permits. It sounds like a lot of that's going to depend on what happens with the EPA, and I'd say the Louisiana, but is there any kind of more specific timing you guys have in mind? Like do you think you could potentially file those at some point this year? Thanks.

I'm going to address the federal government matters briefly before we discuss specifics on the stratigraphic test and our plans there. Throughout our careers, we've dealt with the federal government due to the nature of our assets being on federal lands. When the federal government is motivated, they can act quickly; if not, it may take a longer time. We believe that the federal government is currently motivated. However, we must be cautious since there's significant interest in this area and many permits will be submitted. It's easy to claim that we're in the process of filing a permit without taking substantial action. It’s essential to actually conduct drilling on these assets where we have clear leases. We will follow the necessary process and see how long it takes, although there's no definitive timeline. Still, I believe the government is invested in seeing this succeed.

Yes. As we're completing all of these, both the well testing and continuing to work on Reservoir Characterization using some of our existing seismic data set and some geo modeling. We want to be able to start filing these applications later this year. So that's the intent.

It starts with the strat test, and we are absolutely going to drill that strat test where we have definitive leases in this budget, that’s what we've allocated for.

Got it. Okay, great. And then just a follow up. Just kind of want to see what you guys were with discussions with the emitters, any color you can provide there would be great. Thanks.

Well, look, obviously on Freeport, we have one. That's why that point source project is so interesting, and it's also why we're trying to expand that side of our portfolio. In Freeport, there's obviously work to do. We're talking; it's a huge addressable market, and we're talking to everybody in that addressable market. I think in River Bend, because of that offering where you have our pore space and EnLink's pipe and EnLink's kind of their partner with that customer base, we're thrilled to be working with those guys. They've got great infrastructure; they're going to be a great partner, and they've got those relationships already in progress. So, we're very bullish on how quickly I think River Bend can come together.

Yes. And just adding to that, between the regional emissions and that Riverbend Mississippi River Corridor, when you add that to what's in the Beaumont-Port Arthur Corridor, that fits adjacent to our Texas GLO lease site. We're talking more than 100 million tons per annum of total emissions out there. We're actively having dialogues with our new potential customers. We've already subscribed Freeport. For some of these emissions sources that are a little easier to bait and where the capture technology doesn't exceed the current 45Q, some of these things like natural gas processing, methanol, those kinds of emissions, we can make those work today. But there are quite a few that we still are waiting for some enhancements to the 45Q IRS tax code for those to lift that dollar per ton relief and for direct pay. We think that will help increase the pool of emissions that we'll be able to subscribe to our projects.

Let me elaborate on that point because I believe it's significant. The current 45Q framework is effective for some emissions in the addressable market but does not cover everything. As we've discussed, there is a recognized need for improved incentives to attract a larger portion of the addressable market that performs the best. The question we face is whether we can afford to wait for perfect policy. If we aim to lead in this sector, it's crucial that we engage with emitters, as we did in a recent conversation. They expressed the importance of knowing that we are prepared when they decide to invest. To be ready on our end, we must proactively work on securing the necessary permits, conducting stratigraphic tests, and ensuring we are available for customers willing to invest. It's a bit of a chicken and egg scenario, but we cannot afford to fall behind. We strive to be leaders and take the initiative.

Okay, great. I appreciate the time.

Thank you.

Our next question comes from Jeff Robertson with Watertown Research. Please go ahead.

Thank you. Good morning. At River Bend, you all I believe owned three different lease blocks based on the map that I had in your presentation. Is it right that you’ll need a separate class six permits for each area? Do you work them all at one time, or do you work them individually to try to secure one and then move on to the others?

We're still in evaluation mode, but we'll look to see where those injection sites will be. For any injection well, obviously, you'll need a class six permit for that well. We'll continue that evaluation to see where the most optimal place may be all three. We also have an option on some additional acreage. Our current agreement with the large landholders is for 26,000 acres. The good news here is the pore space thickness exceeds 3,000 feet in some areas. We have tremendous storage space in just those three locations. But we do have the option to continue looking around the area to address one of the largest regional emission sources when you talk about the 80 million tons per annum in the Mississippi River Industrial Corridor.

I get the nature of that question, Jeff. Look, it's consistent geology. I mean, I think what's interesting about this without getting too technical is we're in an area that geology that typically in this area didn't have hydrocarbon extraction. So, there wasn't really a reason to do the level of geological detail that we need to do now to put CO2 away in these saline aquifers. But the geology is pretty consistent across that lease acreage. We want to do as much good as we can with a strat test to describe that geology and show why there's prepared and ready for sequestration.

Could you clarify on that River Bend, the additional 63,000 acres are a right of first refusal?

Let me clarify that even with the additional acreage we have a right of first refusal on, considering what we've announced, including the GLO pore space, the River Bend pore space, and even the smaller but still significant area around the Freeport LNG, we have approximately 900 million metric tons of available sequestration capacity. This demonstrates how hard the teams have worked to develop this in a short period.

Thanks. A broader question on CCS. You all, with the point source and then the two hub projects, can you talk at all about the return preference or economic, I'm sorry, return profile and how those two different sets of projects might compare?

Look, I think the point source removes a certain level of capital with it. You don't have to pipe it potentially five, ten, or fifteen miles, and that's meaningful. They have an opportunity to have slightly higher economics. When you think about a hub, there are a lot of moving pieces there. It requires committed volumes, and you’re trying to have an anchor; that anchor then pulls into some infrastructure. Part of that’s pipe, then part of that's the injection well and the monitoring well. It yields more of that tolling model that will be more of a midstream model, and I think you would expect midstream returns. Where exactly those land is a great question, we get it all the time. We know where the pore space is; we know where the addressable market is. As we build that out, we’ll show maps like you alluded to. You really have to start with who is going to anchor this. Once that’s established, we look; we talk to a lot of emitters, and we’ll see where they want to come into the play.

Thanks. Just moving in the Gulf of Mexico real quick. One of the leases that was vacated from the November sale, I think is adjacent to Puma West. Does that have any impact on your near-term development plans or appraisal plans for that discovery?

No, it's a good question. Not at all. We would call that fringe acreage or protection acreage. It's interesting; we want to have it because the upside case could be significant. It's nice to cover everything, but obviously, if we're not leasing it, then nobody else is leasing it right now. In terms of our base case and our goals for accelerating development, which we've discussed, we have kept that original well as a keeper. We're going to appraise and delineate the resource we found in the original well, and we're also looking at some additional Miocene sands. We want to find a way to connect those two wells quickly if we're successful. Having that fringe lease is important; you always want to acquire as much as possible. But to accelerate our plans, we don't necessarily need it. I would reiterate my frustration about that lease being vacated and the need to decide how to develop the resources offshore. Puma West serves as a great example of a discovery we'd like to delineate. We have plenty of opportunities in our large acreage position that we can work on for years, even with the current vacated status of this sale.

Great. Thank you very much.

Alright, thanks, Jeff.

This concludes our question-and-answer session. I would like to turn the conference back over to Tim Duncan for any closing remarks.

Okay, thank you, operator. The team had a great fourth quarter. The fun thing about this call sometimes is I know our employees are listening in. I want to take a moment to thank them for all their hard work. They had a great year last year; we had a great quarter. Our team is working extremely hard with record production and building a new business. I'm very proud of them, and I want them to know that, and we're excited about what we can do this year. We're excited about where we go from here, and we look forward to giving you guys updates throughout the year.

The conference is now concluded. Thank you for attending today's presentation. You may now disconnect.