Good day, and welcome to the Talos fourth quarter 2021 earnings call. All participants will be in listen-only mode. Should you need assistance, please signal a conference specialist by pressing the star key followed by zero. After today's presentation, there will be an opportunity to ask questions. To ask a question, you may press star, then one on your telephone keypad. To withdraw your question, please press star, then two. Please note 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 31, 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 as a result 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. Now I'd like to turn the call over to Tim. Thank you, Sergio. I'll first discuss our results from 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 and 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 could best utilize our skill set to contribute to the energy transition into decarbonization. Our expertise with conventional geology, combined with our operational capabilities, made 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 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 then our next regional hub project. The TechnipFMC alliance will accelerate front-end engineering design, or FEED, processes during project development phase across our CCS portfolio moving forward. It's gonna 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 their 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. Most recently, we announced a River Bend 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, and 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 River Bend project is strategically located along the Mississippi River Corridor between Baton Rouge and New Orleans, one of 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, and we've already begun engaging with potential customers. In our last call, we were confident we would continue to build out a 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 infield engineering roles to, most recently, the CEO of two publicly traded midstream companies. I think she's going to do a tremendous job building our CCS business and positioning us as a sustainability leader. Robin is joining us on the call this morning, 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 was 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 P&A associated with those properties in the report. Importantly, we hold an additional 60 million barrels of probable reserves with a PV10 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'll 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. 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'll 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 and competitive cash costs, we 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 netbacks 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 64.4 thousand barrels equivalent per day, again, highly liquid 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 rapidly reduced leverage by almost 1 full turn and reached a leverage ratio of approximately 1.7x 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 1x net debt to EBITDA by year-end 2022, and will be within our 1x to 1.5x 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 3,000-4,000 barrels of oil equivalent per day. The planned downtime relates primarily to the previously disclosed HP-1 dry dock process, which will have a 2,000-3,000 barrels of oil 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. Per regulatory requirements, the vessel undergoes maintenance every several years of 45-60 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 field's otherwise extremely high uptimes. 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 3.5-4,000 barrels equivalent per day impact to 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-$320 million and cash G&A expenses of $68-$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 in-field development around our own infrastructure, and high impact appraisal and exploitation projects. The balance of the program will be invested in G&G, land, G&A, 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 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'll 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 in 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 additional 4%-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 continuing debt paydown. We expect this to result in reaching approximately 1x 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 in Talos stock has significantly increased throughout 2021 and is now four to five 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 sub-sea tieback drilling projects in the Mississippi Canyon Miocene Corridor, with two to three operator projects that would tie back to Talos-operated facilities, more specifically around our Pompano and Ram Powell facilities. Our working interest levels on these projects will be between 50%-60%. We will also participate in three additional non-operated sub-sea projects that will also tie back to local infrastructure, and in these projects, we will have a 10%-20% working interest. These single well tiebacks can generally provide initial gross production rates between 5,000-10,000 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 prospective 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 that 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 discovery well as a keeper, if we are 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 VI 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've 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, and I'm proud of our team's effort in moving quickly and with conviction that we would become a market leader. To wrap up, our 2022 plan delivers stable production, high margins, and solid free cash flow. While our capital program is targeted at optimizing the resource and skill set that make Talos unique amongst U.S. E&P companies, access to material conventional offshore resources across the risk-reward spectrum, catalyst 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 in the 2022 budget and in the coming years, we expect that our base business can generate over $1 billion in free cash flow through 2025. With 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, we'll open up the line for Q&A. Thank you. We will now begin the question-and-answer session. To ask a question, you may press star then one on your telephone keypad. If you are using a speakerphone, please pick up your handset before pressing the keys. To withdraw your question, please press star and two. At this time, we will pause momentarily to assemble our roster. Our first question comes from Subash Chandra with Benchmark Company. Please go ahead. Thanks. Thanks, Tim. $1 billion is a heck of a number. Just wanted to first, before I get to that, just talk about CCS. What is sort of the pathway first to get to definitive on the projects you're working on status, and then the pathway to FID? Where does the Class VI permits fit in in the process? Yeah. Look, let me. First of all, hey, Subhash, I hope you're doing well. I'm gonna give you a little bit of my view on a high level, you know, answer part to that, and then maybe some of the Class VI, Robin. I'll hand it over to Robin to, you know, kind of opine here as well. You know, look, these projects, and we've talked about it before, they've got three parts of that value chain, and it always starts with an emitter who has to have a motivation or an incentive to decide they're gonna go capture their carbon. And that starts with them. They're the ones that potentially have an opportunity to retain some credits when they do that. Then there's a transportation and a storage and monitoring piece of that. The parts we can control right now is the storage and the monitoring piece, and then we try to bring together the piping and the transportation piece while we work with the emitters. Ultimately, all of that has to come together before one of these projects FID. That's why a point source project, which we have with Freeport LNG, can be a little quicker than a hub where you have a store and a midstream, you know, which is what we announced in River Bend as an alliance working with emitters. There's a lot going on to get to FID. Then Robin, you know, you may have some more comments on that, and she can talk about the EPA permit process. Because ultimately, when you pull all those together, now you're entering into that process, and we can also talk about some of the things we're doing to accelerate those processes. Yeah. Thanks, Tim. Hi, Subash. Good to hear from you. As we mentioned, obviously the anchor emitter is a key piece. For all three of our projects, for Freeport, our Jefferson County GLO acreage, and the newly announced River Bend CCS project in Louisiana, we want to continue to advance the pre-FEED work, and part of that is to go out and collect the data necessary to file these Class VI permits. 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 in order to make sure when we apply for these permits, we've got sufficient data included in that application process that we can push that through in a timely manner. As far as the timeline on that, as you know today that the regulatory body overseeing those Class VI 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'll be a key piece of our timelines here. Meanwhile, again, working with our technical alliance on some of the wellhead and subsurface pre-FEED, and then moving that, advancing into FEED work as we advance all three of these projects, both on the onshore storage and then the GLO, which is in our shallow state waters. Yeah. I think, you know, to wrap that up, we've advanced from, I think, a couple calls ago. Look, we have a goal of setting up established storage regions, where we know there's a big industrial emitter addressable market. You know, can we partner with midstream players? You're seeing that. You're seeing the advancement that the team's worked so hard on. Now we have things we need to execute on, so we're seeing 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 expect this year to be equally busy, if not busier. Yeah. Hey, Robin. Yeah. Good to talk to you again as well. Tim, I guess, the terminology on MOU versus, you know, definitive- Yeah ... et cetera. Yeah, what's, you know, what's the, I guess the moving parts there to- Yeah get from one to the other? Look, it's a good question, and it's funny. You know, there's often times when we have a mature business like what we have on the oil and gas side, and people wanna say, "Hey, look, you know, you announce things when they're definitive because it's so easy to get to some definitive agreement." If someone's selling an asset and I'm buying an asset, you'll hear about that when 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 kind of put an MOU together, where maybe we and another counterparty, for example, the EnLink agreement says, "Hey, look, we've got assets that we think are very interesting. We entered into this lease that's a 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 FID and builds a business for both of us? 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. Again, you need that anchor emitter that Robin alluded to. Until you get that, you know, you really got to kind of, you know, work. You got to collaborate more than you're entering 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 know, if anything additional to that. All great comments. The only thing I'll add, as Tim was alluding is we're really 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 gonna be duplicated in other areas for the same reasons. You know, again, you wanna be able to kind of look for an obvious partner, decide you're gonna collaborate, but really what you're doing in that collaboration is looking for the industrial accessible emitter market that you can pull into, you know, kind of the story you're creating. Okay, got it. My follow-up, so the $1 billion free cash flow, you know, pretty close to your market cap, et cetera, four years it sounds like. How should we think about that? You know, you're gonna buy back every single stock. I suppose, you know, there'll be a good amount of this that goes into future opportunities, but how do you think of that post 2020? No, good question. There's gonna be guys behind you like, Subash is taking all my questions, just by the way. They're good questions. Look, I mean, if you look at this year, I think we had $135 million of free cash flow. Obviously, we had some hedges we put on in 2020 as the pandemic was starting to wind down, but you still had lower oil prices. Those created hedge losses. You can imagine kind of pulling those hedge losses maybe back into the system as we have a more constructive environment and multiplying that by a couple years. It's not hard to see where our business could generate over $1 billion, you know, through 2025, just to kind of start with that foundation. Then I'm gonna talk about our primary goal. I'm gonna let Shane add some comments here as well. Look, we obviously wanna get our debt profile down to 1x. It was 1.2, 1.3 before the pandemic, which is a good thing because that allowed it to only creep around the 2.5, 2.6 area when we had prices collapse. Now we're slowly working that back down and hopefully accelerating that this year to closer to 1x. That, that's our priority. It should be our priority, and I think it takes us through the bulk of this year. From there, obviously, we have ambition to do kind of, you know, look at where we deliver capital back to shareholders. Shane, why don't you kind of keep addressing the question? Yeah. Happy to do that. So look, I think that's exactly right. We went through. We were in last year at 2.6. We ended this year at 1.7. Rapid deleveraging paid off, you know, just under $100 million of debt over the course of the year. We intend to stay the course until we get down to 1x. I think our range that we've the window we sort of put out for a period of time is we wanna be between 1x and 1.5x. We think we'll get there inside that range over the next quarter or two. We intend to keep driving down below there. I think as it relates to that, to that longer window that Tim talks about, look, obviously, a lot of things are on the table. You mentioned potentially some 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. 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 1x leverage marker. Yeah. Okay. Excellent. Thanks, guys. All right. Thank you, Subash. Our next question comes from Michael Scialla with BofA. Please go ahead. Yeah. Hi, good morning, everyone. Robin, congratulations on your new position. Looking forward to working with you again. It seems like the CCS business has been moving along maybe more quickly than you anticipated. You allocated about $30 million to it this year. Just trying to get a sense of, as you look forward, do you think as you're in this kind of testing and pre-Class VI permit stage, is that sort of the level you anticipate for the business for the next couple of years, or do you see it ramping more quickly than that? Well, look, I mean, there's a couple things. One, you know, I think we go back to previous calls, Michael. We've talked about this at some conferences before. You know, we had to ask ourselves once we really started thinking about how do we play into transition? We're conventional geology, you know, 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. We decided to play in the CCS, you know, evolving industry. Once we put that bid in on GLO, we were lucky enough to be a successful bidder. We really looked around the room and said, "Why aren't we trying hard across every ounce of pore space that we know, that we understand, state-regulated pore space, private ownership pore space, potentially, hopefully one day, federally regulated pore space?" It all can be used for, you know, purposeful sequestration, so safe sequestration. Once we built that team, look, we were about it. You know, 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. I would still say that. Look, when we really said, "Hey, we think we've got the skill set. We think we've got the business development and the ambition and the agility and the urgency. You know, there's only so much of my time. Bob Abendschein, who's been a big part of this, was leading it, but we should probably look at additional executive leadership, and that led to Robin. Hey, look, I'm gonna hand it over to Robin so she can kind of express her own ambitions, but I would say that they're plentiful. Anything you wanna add to that on where we see the team going? I'll just say with increased success and as we continue to look across the U.S. Gulf Coast, that opportunities where you've got a stacking of the pore 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 also developing what that development plan looks like, identifying how many injection wells. With success, again over time, yes, we would expect we'll 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. Yeah. I think. Look, 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 also needed to go look, hopefully bring some more announcements shortly. Well, good. I look forward to those. Wanna see if you could talk a little bit more about your Miocene exploration wells that you planned this year? Sure. I assume those don't depend on the November lease sale going through. I know at one point you had anticipated that being a part of I think some of those. Do you and do you already have partners there? Do your plans change if the Interior comes back and says those lease sales aren't going forward? Just anything more you can tell us about those? Yeah. Well, so those are all good questions, and we'll put those into a couple buckets. First of all, what we're gonna drill this year are all leases where we have executed lease agreements. You know, we've talked about in the past, and it's often a fair question when people feel like there's political uncertainty to ask about permitting and a lot of what-if scenarios, right? One thing that we've said in previous calls is we haven't had any delays on the permits that have a good precedent record, whether that's a drilling permit, whether that's a recompletion or things related to asset management, certainly things related to our plugging and abandonment activities. Those permits are happening in due course, primarily because we have a working lease agreement between the parties, us and operator, and the government on how we're gonna execute on that lease. That's the case with all of these things we're gonna drill, you know, we're gonna drill this year. On that lease sale that was just vacated, we were very close to entering into those new lease agreements when that was vacated. We don't actually have, and it's disappointing, and it's a whole another commentary around energy policy that I'll not make on this call 'cause there's other things for us to discuss on, you know, why we need good, robust development offshore. Because we need it, and it's a shame that we don't have it. We do have it where we have lease agreements. We'll let that sit there. With respect to why Mississippi Canyon, just to kind of get into that a little bit. You know, some of that depends on the timing of how we do transactions, and as you know, Michael, how we think about reprocessing seismic data. 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, and it led to field redevelopments, and ultimately, it also led to our interpretation of Puma West that was successful. 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 this year's report or last year's report. As we move into Mississippi Canyon, these are more exploitation, exploration. They're one well subsea tiebacks. Think of these targets as 10-20 million barrels gross, oil equivalent type targets that are within 10 miles or so of facilities, and in this case, facilities we operate in Pompano and Ram Powell. Then there's 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. That's fine. We don't get a rig till the second half of the year. Everything timing-wise is working out. As we roll out some corporate decks, we'll give you some more details on these as well. Look, we're really excited about it. As you know, Mississippi Canyon's a prolific area. It's an area where we wanna 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. Then again, with some appraisal at Puma West in the second half of the year as well. Appreciate the color, Tim. Thanks. Yeah. Our next question comes from Steven Dechert with KeyBanc. Please go ahead. Hey guys, I just wanted to follow up on the Class VI permits. It sounds like, you know, a lot of that's gonna depend on what happens with the EPA and the state of 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 gonna address a little bit of the federal government stuff, and then you can address specifics on the strat test and what we're doing there. Look, I think, you know, I would tell you, we've spent our whole careers, and I, you know, I think you know that just by the nature of our assets being on federal lands dealing with the federal government, you know. I think when the federal government has will, the federal government can move fairly quickly. If the federal government doesn't have political will, then it may take a little longer. I think this is an area where we think the federal government does have political will. I do think we have to caution though, that there's a lot of interest here, and there's gonna be a lot of permits that are filed. You know, we wanna start. We think it's easy to say we're in the process of filing a permit, and you're really not doing much at all. You really need to get out there and drill a stratigraphic test on these assets where you have definitive leases, and then we follow a process and, you know, we'll see how long that takes. There's no perfect answer. I do think we have a government that really wants to see this succeed. Yes. As we're completing all of these, the both the strat well testing and continuing to work the subsurface from a reservoir characterization using some of our existing seismic data sets and some geomodeling, we wanna be in a position to start filing these applications later this year. That's the intent. Yep. It's really just about the timeline of those approvals, depending on which regulatory body will be the ones who award those over time. You know, again, it starts with the strat test, and we're absolutely gonna drill strat tests where we have definitive leases in this budget. That's what we've allocated for. Got it. Okay, great. Then just to follow up, just kinda wanna see where you guys were with discussions with emitters, any color you can provide there'd be great. Thanks. Yeah. 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, you know, because of that offering where you have our pore space and EnLink's pipe and EnLink's, you know, kind of, they're our partner with that customer base, with that infrastructure, you know, we're really thrilled to be working with those guys. They've got great infrastructure. They're gonna be a great partner, and they've got those relationships already in progress. We're very bullish on how quickly I think River Bend can come together. Yeah. Just adding to that, between the regional emissions in that River Bend, Mississippi River Corridor, when you add that to what's in the Beaumont-Port Arthur corridor that sits adjacent to our Texas GLO lease site, we're talking more than 100 million tons per annum of total emissions out there. We are actively having dialogues with our new potential customers, and as Tim pointed out, we've already subscribed Freeport. When you've got some of these emission sources that are a little bit easier to abate and they can, the capture technology doesn't exceed the current 45Q, some of these things like natural gas processing, methanol, those kind of emissions, we can make those work today. There are quite a few that we still are waiting for some enhancements to the 45Q IRS tax code for both to lift that $1 per ton relief and also for direct pay. We think that will help increase the pool of emissions that will be able to subscribe to our projects. Yeah. Let me expand a little bit on that because I think this is important. You know, there's the current 45Q framework works for some of the emissions in the addressable market, but not all of them. Obviously, you know, we've talked about, and others that are playing in the space have talked about the need for enhanced incentives to really pull in more of the addressable market that does the most good, frankly. Now, those folks, the issue, the question for us is, can we wait for perfect policy? If we're gonna be a leader in this business, the one thing, and we've talked to emitters all the time, and we were in that conversation last week with a particular emitter, where they said, "Look, if we're gonna make this investment," 'cause it starts with those emitters and industrial partners making those investments, "we wanna know that when we're ready, you're ready." For us to be ready, we have to go ahead and move forward on preparing those Class VI permits and drilling those strat tests and being available for those customers who are ready to make that investment as well. It's a little bit of a chicken and the egg, but the last thing we can be is the laggard in that. We wanna be a leader in that and be upfront. Okay, great. I appreciate the time. All right. Thank you. Our next question comes from Jeff Robertson with Water Tower Research. Please go ahead. Thank you. Good morning. At River Bend, you all, I believe, own three different lease blocks based on the map that EnLink had in their presentation. Is it right that you'll need a separate Class VI permit for each area, and 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 the evaluation mode, but we'll look at to see where those injection sites will be. For any injection well, obviously you'll need a Class VI permit for that well. We'll continue that evaluation to see where the most optimal place. It may be all three, and we've also got an option on some additional acreage. Our current agreement with the large landholders for 26,000 acres, the really good news here is the pore space thickness exceeds 3,000 feet in some areas, so we've got tremendous storage space in just those three locations. But we do have an option to continue looking around the area to really address what is one of the largest I get the nature of that question, Jeff. Look, it's pretty consistent geology. I mean, I think what's interesting about this, without getting too technical, is we're in an area of the geology that typically, in this area, didn't have hydrocarbon extraction. 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. You know, but the geology is pretty consistent across that lease acreage. You know, we wanna do as much good as we can with a strat test to describe that geology and describe the rock properties and show why that is prepared and ready for sequestration. Can I- Yeah. I'll quickly clarify on that River Bend. The additional 63,000 acres are actually a right of first refusal. Now let me clear up that. Even with that additional acreage that we have a kind of a right of first refusal option on, in the stuff that we've announced, just so you kind of know we have it, when you take the GLO pore space, the River Bend pore space, and then even in the smaller but still meaningful around the Freeport LNG, we're up to around 900 million metric tons of available sequestration capacity. Again, that's before some of the additional acreage that Robin just alluded to. Again, going back to how hard this team's worked to kind of really build this out in a short amount of time. Thanks. A broader question on CCS. You all with the point source and then the two hub projects, can you talk at all about, I'm sorry, return profile and how those two different sets of projects might compare? Look, I think the point source, you know, removes a certain level of capital with it. You know, you don't have to pipe it potentially five, 10, 15 miles, and that's meaningful. And you know, so that's, they have an opportunity to have slightly higher economics. I think, when you think about a hub, there's a lot of moving pieces there. It really requires committed volumes, and then you're trying to have an anchor, and that anchor then pulls in into some infrastructure. Obviously, part of that's the pipe, and then part of that's the injection well and the monitoring well. It just yields for that more of that tolling model that is gonna be more of a midstream model, and I think you would expect midstream returns. You know, again, all this exactly where that lands, and it's a great question, and we get it all the time. You know, we know where the pore space is, and we know where the addressable market is, and as we build that out, we'll show maps to that. You just alluded to a map that you saw. You really have to start with who's gonna anchor this. Once that anchor is, I mean, look, again, we talk to a lot of emitters all the time as do other companies. A 500,000 metric ton emitter is very interesting. We wanna see them in the store. That's not gonna anchor a hub. You really have to figure out where is that anchor emitter, who's it gonna be, and how does that fit into the complex. You've got a little better feel for the capital involved, the tolling kind of structure that you're gonna need, and then you can kind of have a better feel on how the rest of the industrial partners can come into the space. 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. Yeah. Does that have any impact on your near-term development plans or appraisal plans for that discovery? No, not at all. I mean, yeah. No, it's a good question. Not at all. Look, it's you know, we would call that fringe acreage, protection acreage. It's interesting. We wanna have it and, you know, kind of the upside case, which could be, you know, material. It's nice to cover up everything, but obviously, if we're not leasing it, so nobody else is leasing it right now. It really on our base case and you know, our goals of accelerating development here, which we've talked about, we kept that original well as a keeper. We're gonna go appraise and go delineate that resource to what we found in the original well. We're also gonna look for some additional Miocene sands. You know, we wanna try to figure out how to hook those two wells up if we're successful as quickly as we can. Having a fringe lease, again, very important to always wanna get as much as you can, but for what we can do to accelerate this, we don't need it. I would go back to, you know, frustration around that being vacated and the need to really decide how we're gonna go develop the resources offshore. I just go back to Puma West as an example of a great discovery that we want to delineate. We have plenty of things in our large acreage position that we can go work on for years to come, you know, even with this kind of, you know, vacated process of this particular lease sale. Great. Thank you very much. All right. Thanks, Jeff. This concludes our question and answer session. I'd like to turn the conference back over to Tim Duncan for any closing remarks. Okay. Thank you, operator. Well, look, the team had a great, you know, fourth quarter. The fun thing about these calls sometimes is I know our employees listen in. I want to just 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's working extremely hard, you know, with record production and building a new business. I'm very proud of them, and I want them to know that. We're really excited about what we can do this year. We're excited about kind of 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.