Talos Energy Inc

NYSE:TALO

Earnings Call Transcript 2021-Q4

[Operator]

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

[Sergio Maiworm]

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.

[Tim Duncan, President & Chief Executive Officer]

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 increased 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 lose 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 into 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, and announcing a technical alliance with TechnipFMC, our first point source project, and then, 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 de -carbonizing 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 pet 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 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. And our last call, we were confident we would continue to build out as the portfolio 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. So, 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 a $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 a $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.

[Shane Young]

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. And competitive cash costs we generated adjusted EBITDA of a $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 a $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 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 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 up times. 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 eminently, and that it will result in a 3,500 to 4,000 barrels equivalent per day impact 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 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 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. And as previously mentioned, our primary objective will be continuing 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.

[Tim Duncan, President & Chief Executive Officer]

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 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 sub-sea projects that will also tie back to local infrastructure and in these projects, we will have attended 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 the 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 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're successful in our appraisal program, our hope and expectation would be to accelerate development as a multi-well sub-sea tie back 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. And 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 saw a 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, 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 a net positive for equity holders anchored by higher impact subsea drilling projects from our existing inventory, both into 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.

[Operator]

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

[Subash Chandra, Benchmark Company]

Thanks, Tim. Billion dollars as a like of a number. Just wanted to first before I get to that, just talked about CCS. What is the pathway first to get to definitive on the projects are working on status, and then the pathway to FID? And where does the classics permits fit in in the process?

[Tim Duncan, President & Chief Executive Officer]

Yeah. Look, let me -- so first, hey, Subash. I hope you're doing well. I'm going to give you a little bit of my view on a high-level answer part of that and then maybe some of the questions Robin -- I will hand it over to Robin to kind of opine here as well. But look, these projects, that we talked about it before, they've got three parts of that value chain. And it always starts with an emitter, who must have a motivation or an incentive to decide they're going to go capture their carbon. And that starts with them, they are the ones who potentially have an opportunity to retain some credits when they do that. And then there's a transportation and the 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 must come together before one of these projects have 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 the midstream, which is what we announced in River Bend as an alliance working with emitters. There's a lot going on to get to FID. And then Robin you may have some more comments on that as you could talk about the EPA permit process, because ultimately, when you pull all those together, now you're entering that process, and we can also talk about some of the things we're doing to accelerate those processes.

[Robin Fielder]

Thanks, Tim. And [Indiscernible] good to hear from you. So, 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 and part of that is to go out and collected data necessary to file these classic 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 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 classic CO2 injection permits, is still the EPA. State of Louisiana has filed for primacy, and we would expect to hear something, hopefully, later this year on that. And 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. And meanwhile, again, working with our technical alliance on some of the wellhead and subsurface pre -feed and moving that, advancing into feed work as we advanced all three of these projects, both on the onshore stores and then, the GLO, which is in our shallow state waters.

[Tim Duncan, President & Chief Executive Officer]

So, I think -- to wrap that, we've advanced from, I think, a couple of calls ago, look, we have a goal of setting up established 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. So last year was extraordinary 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.

[Subash Chandra, Benchmark Company]

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

[Tim Duncan, President & Chief Executive Officer]

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 selling an asset, none buying an asset, you'll 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 maybe we add another counterparty. For example, the [Indiscernible] 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 the -- and bill-to-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. And until you get that, you really got to work, you got to collaborate more when 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.

[Robin Fielder]

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

[Tim Duncan, President & Chief Executive Officer]

And again, that model is going to be duplicated in other areas for the same reasons. Again, you want to be able to look for an obvious partner, the 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.

[Subash Chandra, Benchmark Company]

Okay, got it. And my follow-up, so the billion free cash flow is close to the market cap, etc., 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 20 --

[Tim Duncan, President & Chief Executive Officer]

No, good question. So, there are going to gaps behind, like Subash has taken all my questions, just by the way, but they're good questions. But look -- if you look at this year, I think we had a $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 have lower oil prices. Those created hedge losses. You can imagine pulling those hedge losses maybe back into the system as we have a more constructive environment and multiplying that by a couple of years, it's not hard to see where our business could generate over a billion dollars through 2025 just to start with that foundation. And then I'm going to talk about our primary goal. I'm going to let Shane add some commentary as well, but look, obviously we want to get our debt profile down to one time it was 1, 2; 1, 3 before the pandemic, which is a good thing because that allowed it to only creep around a 2, 5; 2, 6 area when we have prices collapsed. And now we're slowly working that back down and hopefully accelerating that this year to closer to one time. 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 look at where we deliver capital back to shareholders. Shane, why don't you kind of keep addressing the question.

[Shane Young]

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. Paid off just under a $100 million of debt over the course of the year. And we intend to stay the course until we get down to one time. I think our range that with the window we sort of 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 to that longer window, the Tim talks about. Look obviously, a lot of things 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.

[Subash Chandra, Benchmark Company]

Excellent, thanks [Indiscernible].

[Shane Young]

Thanks, you [Indiscernible].

[Operator]

Our next question comes from Michael [Indiscernible] please go ahead.

[Michael Scialla, Stifel]

Yeah. Hi. Good morning, everyone. And Robin, congratulations on your new position. Looking forward to working with you again. It seems like the CCS business has been moving along 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 testing and pre -class six permit stage, does that -- the level you anticipate for the business for the next couple of years? Or do you see it ramping more quickly than that?

[Tim Duncan, President & Chief Executive Officer]

Well, look, I mean so there's a couple of things. 1, 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 CCS evolving industry. And then once we put that bidding on GLO, and we're lucky enough to be a successful bidder. We really looked around the room and said why aren't we trying hard across eve rye supposed space that we know that we understand. State regulated for space, private ownership for space. Potentially hopefully one day federally regulated for space that all can be used for purposeful sequestration, so savings sequestration. And once we built that team, look, 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 an even previous decks we expect to do more. And I would still say that. And so, 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. We probably also need to put -- there's only so much of my time, above that, Shane, who has been a big part of this, was leading it, but we should probably look at additional executive leadership and that led to Robin. And I look, I'm going to hand it over to Robin so she can express her own ambitions, but I would say that there are plenty. So, anything you want to add to that on where we see the team going?

[Robin Fielder]

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 [Indiscernible] space and contiguous lease hold at the surface and local emissions, we will continue to advance these projects. And we talked about getting in from pre - FEED moving into FEED and developing what that development plan looks like, identifying how many injection wells. So, 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.

[Tim Duncan, President & Chief Executive Officer]

And I think, look, I think, the capital spend we have in that program, it's 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 announcement shortly.

[Michael Scialla, Stifel]

Well, good. 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 that part of, I think, 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?

[Tim Duncan, President & Chief Executive Officer]

Yeah, these are -- so those are all good questions. And we'll put those into a couple of buckets. First, what we're going to draw this year, all leases we have executed lease agreements. And we've talked about in the past and it's up to fair question when people feel like there's political uncertainty to ask about permitting and a lot of what if scenarios. And 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 haven't working lease agreement between the parties, us an Operator in the government on how we're going to execute on that lease. And that's the case with all these things we're going to 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. So, we don't have and it's disappointing and it's a whole another commentary around energy policy that I will not make on this call, because there's other things for us to discuss on why we need good robust developed offshore. Because we need it and it's a shame that we don't have it, but we do have it where we have lease agreements. So that's there. With respect to why Mississippi Canyon just to kind of get into that a little bit, some of that depends on the timing of how we do transactions. And as you know, Michael, how we think about reprocessing seismic data. And last year was heavy in the Green Canyon area, including the Puma West discovery because we did some transactions several years ago that lead to more science, more reprocessing 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 sub-sea 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. And in this case, facilities we operate in Pompano and Ram Powell. And 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 until the second half of the year, so everything timing-wise is working out. And 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 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. And then again with some appraisal of Puma West in the second half of the year as well.

[Michael Scialla, Stifel]

I appreciate the color, Tim, thanks.

[Operator]

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

[Steven Dechert, KeyBanc]

Hey, guys. I just wanted to follow up on that Class six 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.

[Tim Duncan, President & Chief Executive Officer]

Yeah. I'm going to address the one on -- let me address the little bit of the federal government stuff and then you can address specifics on the start test and what we're doing there. But look, I think -- I would tell you we spend our whole careers and I think you know that just by the nature of our assets being on federal lands dealing with the federal government. And I think when the federal government has will, the federal government can move quickly. If 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 going to be a lot of permits that are filed. We want to start -- we think it's easy to say we are in the process of filing a permit and you're 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 we'll see how long that takes. There's no perfect answer but I do think we have a government that really wants to see this succeed.

[Robin Fielder]

Yes. So, as we're completing all of these, both the well testing and continuing to work the subsurface from 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.

[Tim Duncan, President & Chief Executive Officer]

Yes.

[Robin Fielder]

And then it's just about the timeline of those approvals depending on which regulatory body will be the ones to award those over time.

[Tim Duncan, President & Chief Executive Officer]

But it's starting to get it starts with the start test and we are absolutely going to drill start test where we have definitive leases in this budget that's what we've allocated for.

[Steven Dechert, KeyBanc]

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.

[Tim Duncan, President & Chief Executive Officer]

Yeah. Well, look, obviously on Freeport, we have one. That's why that point source projects is so interesting and it's also why we're trying to expand that side of our portfolio and then 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. And then I think in River Bend, because of that offering where you have our poor space and EnLink's pipe and EnLink's kind of their partner with that customer base, with that infrastructure, we're really 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.

[Robin Fielder]

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. And so we are actively having dialogues with our new potential customers. And as Tim pointed out, we've already subscribed Freeport. And when you've got some of these emissions sources that are a little bit easier to bait and they can -- 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 45 queue IRS tax code for those to lift that dollar per ton relief and for direct pay. And we think that will help increase the pool of emissions that we'll be able to subscribe to our projects.

[Tim Duncan, President & Chief Executive Officer]

Let me expand a little bit on that because I think this is important. There's the current 45 queue framework works for some of the emissions in the addressable market, but not all of them. Obviously, we talked about and others that are playing in space have talked about. The need for enhanced incentives to really pull in more of the addressable market that does the best frankly. Now those folks -- the issue -- the question for us is, can we wait for perfect policy? And if we're going to be a leader in this business, the one thing we've talked to emitters all the time and we were in that conversation last week with a, a bitter where they said, look if we're going to make this investment because it starts with those emitters and industrial partners making those investments. We want to know that we're ready, your ready, and for us to be ready, we must go ahead and move forward on preparing those classics, permits and drilling dose strat test, and being available for those customers who are ready to make that investment as well. So it's a little bit of a chicken and the egg, but the last thing we can be is the lag in that. We want to be a leader in that and be upfront.

[Steven Dechert, KeyBanc]

Okay, great. I appreciate the time.

[Tim Duncan, President & Chief Executive Officer]

Thank you.

[Operator]

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

[Jeff Robertson]

Thank you. Good morning. At River Bend, you all I believe owned three different lease blocks based on the map that [Indiscernible] had in their presentation. Is it right to, you'll need a separate class six permits 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?

[Robin Fielder]

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 6 permit for that well. We'll continue that evaluation to see where the most the optimal place -- it may be all 3, and we've also got an option on some additional acreage. Our current agreement with the large land holders for 26,000 acres, the good news here is the port space thickness exceeds 3,000 foot in some areas. So we've got tremendous storage space in just those 3 locations. But we do have the option to continue looking around the area to address what is one of the largest regional emission sources, when you talk about the 80 million tons per annum and the Mississippi River Industrial Corridor.

[Tim Duncan, President & Chief Executive Officer]

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 daily and aquifers. And so but the geology is pretty consistent across that lease acreage. So we want to do as much good as we can with a strat test to describe that geology and describe the rock properties and show why there is prepared and ready for sequestration.

[Robin Fielder]

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

[Shane Young]

Well in -- now, let me clear up that. And even with that additional acreage that we have a right of first refusal option on, in the stuff that we've announced to some that we have, 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. And again, that's before some of the additional acreage that Robin just alluded to. Again, going back to how hard the teams work to really build this out in a short amount of time.

[Jeff Robertson]

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

[Tim Duncan, President & Chief Executive Officer]

Look, I think the point source removes a certain level of capital with it. You don't have to pipe it potentially five, 10, 15 miles and that's meaningful and so that 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 pools in into some infrastructure. Obviously, part of that's pipe and then part of that's the injection well and the monitoring well. And it just yields for that -- more of that tolling model that is going to be more of a midstream model and I think you would expect midstream returns. But again, exactly where those lands. And it's a great question, we get it all the time. We know where to pour space s, we know where the addressable market is. And as we build that out will show maps that you just alluded to a map that you saw. You really have to start with who is going to anchor this. And then once that anchors, we look again, we talked a lot of emitters all the time as to other companies I have a million metric ton of emitter is very interesting. We want to see them in the store that's not going to anchor a hub. And so you really have to figure out where is that anchor emitter? Who is it going to be? And how does that fit into the complex? And then you've got a little better feel for the capital involved. The tolling structure that you're going to need, and then you have a better feel on how the rest of the industrial partners can come into the space.

[Jeff Robertson]

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?

[Tim Duncan, President & Chief Executive Officer]

No, it's a good question. Not at all. Look, it's -- we would call that -- if we would -- fringe acreage, protection acreage, it's interesting. We want to have it and the upside case, which could be material. It's nice to cover up everything. But obviously, if we're not leasing it, some -- nobody else is leasing it right now. And on our base case and our goals of accelerating development here, which we've talked about, we kept that original well as a keeper. And then, we're going to go appraise and go delineate that resource. And what we found in the original well, we're also going to look from some additional Miocene sands. And then, we want to try to figure out how to hook those 2 wells up if we're successful, as quickly as we can. And having a fringe lease, again, very important to always want to 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 frustration around that being vacated and the need to really decide how we're going to go develop the resources offshore. But I just go back to Puma West is an example of a great discovery that we wanted to lineate. We have plenty of things in our large acreage position that we can go work on for years to come. Even with this kind of vacated process of this sale.

[Jeff Robertson]

Great. Thank you very much.

[Tim Duncan, President & Chief Executive Officer]

Alright. Thanks, Jeff.

[Operator]

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

[Tim Duncan, President & Chief Executive Officer]

Okay, thank you, operator. Well look, the team had a great fourth quarter. And the fun thing about this call sometimes is I know our employees are listening 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 is working extremely hard with record production and building a new business and I'm very proud of them and I want them to know that, and we're really excited about what we can do this year. And we're excited about where we go from here, and we look forward to giving you guys’ updates throughout the year.

[Operator]

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