Good morning, and welcome to the Talos Energy Fourth Quarter and Full Year 2020 Earnings Call. Please note this event is being recorded. I’d 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 2020 earnings conference call. Joining me today to discuss our results are Tim Duncan, President and Chief Executive Officer; and Shane Young, Executive Vice President and Chief Financial 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, 2020, 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 press release, which was filed with the SEC and which is also available on our website at talosenergy.com. And now I’d like to turn the call over to Tim.

Thank you, Sergio. Good morning, everyone, and thanks for joining us today. The fourth quarter capped off a year of resiliency for the company on numerous aspects. Around this time a year ago, we were adjusting our plan so we could manage our business due to the commodity crisis brought on by the demand pullback associated with the global pandemic that was ensuing. Those adjustments included making difficult decisions to lower our overall cost structure and cutting projects from our capital program to focus our investments on those projects that were previously committed to and those that had short turnaround times to first oil, which would support our credit liquidity positions to withstand an extended commodity price downturn. 2020 also saw historical levels of hurricane activity in the Gulf of Mexico, which caused major production disruptions and project delivery delays. Despite all these challenges, Talos maintained its operating excellence. In the fourth quarter, we saw the benefits of those decisions taking hold. We exited the year with just over 71,000 barrels of oil equivalent a day and continued to manage our operating costs below our guidance and generated solid free cash flow. Also in the fourth quarter and early 2021, we opportunistically accessed the capital markets with proceeds used to refinance our old notes and significantly improve our liquidity position, which is now similar to what it was pre-pandemic. Today Talos is very well positioned to execute on its strategy, which is a well-balanced combination of development wells and lower risk subsea tiebacks, high impact exploration and value-added M&A activities. We have a more diverse set of assets today than a year ago, robust liquidity, and a drilling program that will allow us to generate meaningful free cash flow in 2021 and beyond. Let’s dive into some key highlights for the quarter and full year results. Production averaged 59,400 barrels of oil equivalent per day for the quarter and 54,700 barrels of oil equivalent per day for the year. As discussed on previous calls, an unprecedented hurricane season was a large part of the production story in 2020, which persisted into the fourth quarter, and it’s something we are being more conservative on as we guide 2021. Production was approximately 67% oil for the quarter and 68% oil for the full year. Total liquids averaged 76% for the year. Lease operating expenses totaled $62.4 million, and G&A expenses totaled $12.3 million for the quarter, excluding non-cash and non-recurring items. These figures equate to a competitive cost per Boe metric considering the oily nature of our assets of less than $11.50 per Boe and $2.25 per Boe, respectively. Capital expenditures for the quarter totaled $71 million, inclusive of P&A. This capital number was higher than expected due to the late change of scope and completion operations on our successful Kaleidoscope well earlier than expected awards of leases from the November 2020 federal lease sale, and unexpected costs related to properties that are operated by others. The adjusted EBITDA for the quarter was $106.4 million on significantly improved margins, which allowed the company to generate $12.2 million of free cash flow for the quarter. At year end, Talos recorded 163 million barrels equivalent of proved reserves for the PV-10 value of approximately $2 billion utilizing SEC prices of $39.54 per barrel and $1.99 per MMBtu. Audited probable reserves at year end comprise an additional 69 million barrels equivalent for the PV-10 of approximately $770 million at the same price deck. These numbers are net of all plugging and abandonment costs associated with those reserves. Yesterday’s earnings press release included pricing activities on our year end reserve volumes and associated PV-10 that highlight those figures at prices closer to what we’re experiencing today. For example, at $55 a barrel and $2.50 in MMBtu, which is closer to the SEC price at year end 2019, proved reserves increased to approximately 185 million barrels equivalent, which compared to 142 million barrels equivalent from year end 2019 represents an increase of over 30%, but the PV-10 of almost $3.3 billion. When oil prices move to $60 a barrel, the current value of proved reserves increases to almost $3.8 billion. All of these figures also include and are fully burdened by the plugging and abandonment obligations associated with those reserves. They do not include, however, any volumes from our two discoveries in offshore Mexico, specifically and I want to be clear here. These reserves and values do not include anything from our Zama field yet, where our third-party reserve auditors have recently updated and increased their most likely gross contingent recoverable volume to 735 million barrels equivalent. On the drilling and completions front, Talos was highly active in the fourth quarter of 2020. We continue to see positive results from our first of its kind Tornado intra-well water flood, which we expect to generate increased recovery of 25 million to 35 million barrels of equivalent in combination with our planned Tornado Attic well in 2021, which is part of the guidance that Shane will discuss shortly. We initiated production from our Kaleidoscope well in late December 2020, which is flowing at almost 5,000 barrels equivalent gross per day. The Puma West project BP reentered that well in late February of 2021 after suspending operations in early 2020. Talos and its Block 7 partners in Pemex continue to advance unitization discussions ahead of the March 25th, 2021 deadline to submit a unitization plan to Mexico’s Ministry of Energy or SENER, which we expect they will need to review before any public announcements. Assuming unitization is completed on a timely basis, Talos hopes to achieve final investment decision or FID on this project by year end 2021, which would immediately allow us to book a significant portion of the Zama contingent resources into the company’s proved reserves once the FID milestone is reached. The completion of unitization and the declaration of FID represents a major catalyst for the company, removing uncertainties and allowing a line of sight to first oil from this extraordinary asset. Talos continued to advance its ESG activities during 2020, releasing our first annual ESG report in the third quarter of 2020. We anticipate in this year’s report, which we expect to be released in the summer, we’ll show a third straight year of meaningful emissions reductions. Regarding safety, we had one recordable incident by a Talos employee for the entire year, and we continued an excellent spill track record relative to industry with less than one barrel released from over 24 million barrels of production operated and handled by Talos. We have built a culture of ownership and inclusion at Talos, and it shows in our employee-led ESG advisory committee that is tackling 11 key initiatives from emissions reductions to key environmental best practices offshore, to expanding diversity inclusion programs and community involvement. Furthermore, we’re fortunate that our employees have recognized our company as the top workplace in Houston for eight straight years, each year we have been in business. Finally, on the regulatory front, recent actions by the Department of the Interior and the White House have not had any material near-term impact on our business. We have continued to receive permits for our production and drilling activities. We have recently been officially awarded new leases where we were high bidders in the last lease sale. And we continue to see collaboration at timely responses across our regulatory interactions day-to-day. It’s important to clarify again that we believe we are well-positioned to tackle any perceived regulatory risks moving forward. Our management team has spent the majority of their careers offshore, focused in the Gulf of Mexico. Throughout our careers, the basin has continuously been not only a prolific producing basin but has represented the leading edge of technology, safety, and environmental performance for the industry across the globe. Although our company does not expect material near-term impacts from these recent regulatory actions, we believe the discourse around oil and gas production on federal lands is an opportunity to remind policymakers of the benefit of our operations as an industry offshore. The demand for energy continues to grow because of the positive impact it has on all our lives. The supply of these resources, geologically, comes from our own domestic efforts, which are secure, safe, reliable, and also provide hundreds of thousands of high-paying jobs, particularly along the Gulf Coast. From a safety standpoint, the Gulf of Mexico is one of the best performing areas, not only in energy and exploration and production but across many industrial sectors of the economy. Finally, deepwater Gulf of Mexico oil production carries the lowest emissions intensity per unit of production and certainly lower than many other areas or countries, where we would otherwise likely have to import supply to meet domestic demand. The U.S. Gulf of Mexico is a critical part of the energy discussion today, which must balance domestic growth in renewable energy with reliable and responsible delivery of traditional oil and gas production so that affordable energy costs are maintained with the highest environmental standards and the biggest economic impact to our local communities. Thoughtful environmental and economic policies should include the Gulf of Mexico for years to come. With that, I’ll turn the call over to Shane to discuss further details of the quarter and our 2021 guidance.

Thank you, Tim. I’d like to take a few minutes to add further color to three things. First, our results for the quarter; second, our recent capital market activities, which help facilitate the refinancing of our high yield maturity to 2026 and enhance liquidity; and third, to outline our 2021 production and cost guidance. Turning to the fourth quarter, realized pricing for the quarter was $40.63 per barrel and $2.38 per MMBtu. Revenue was over $175 million, exclusive of $2.4 million of realized hedge gains for the quarter. The company generated adjusted EBITDA for the quarter of approximately $106.4 million, equating to a margin of $19.47 per barrel equivalent, and over 60%. We maintain a competitive cost structure with LOE, including repairs, maintenance, and insurance of $11.41 per BOE and cash G&A of $2.25 per BOE. EPS for the quarter was an adjusted net loss per share of $0.41 after adjusting the impact of approximately $267 million in pretax ceiling test write-downs at year end, driven primarily by negative changes to the SEC price deck for the year and the non-cash tax expense of $162 million related to the recognition of a valuation allowance for our excess deferred tax assets. Capital expenditures for the quarter were approximately $71 million. As Tim mentioned, this was due to a late change in scope and completion operations on our successful Kaleidoscope well, earlier than expected award of leases from the November 2020 federal lease sale, and unexpected costs related to properties that are operated by others. Free cash flow for the quarter was over $12 million after capital and interest expense. Turning to our refinancing. In December 2020 and January 2021, we executed three capital markets transactions to retire our Notes due in the first half of 2022 and to reduce our borrowings under our credit facility. The company raised approximately $675 million in gross proceeds through these transactions. Our January 31, 2021 balance sheet, inclusive of the cumulative effect of these transactions, generates a net debt to 12/31 LTM EBITDA ratio of approximately 2.2 times, and liquidity of approximately $546 million, one of the highest liquidity levels in the company’s history. These transactions eliminated a material near-term maturity and provided Talos with substantial flexibility as we move into 2021. Currently, Talos is actively working on the spring borrowing base redetermination process and pursuing a maturity extension of that facility. We are confident that the company will continue to maintain robust liquidity and a healthy maturity profile enabling Talos to meet its operational and strategic objectives. In yesterday’s press release, we also provided our 2021 operational and financial guidance, which I’ll now discuss in more detail. For 2021, we expect daily production to average between 63,000 and 67,000 barrels equivalent per day, which equates to nearly 20% growth over actual 2020 production and 2% growth from 2020 levels after normalizing for COVID and hurricane-related impacts. This guidance is inclusive of downtime at our Pompano facility in the Mississippi Canyon area, beginning later this month to hookup a third-party well, which we will provide future production handling fee cash flow and the installation of the platform rig proceeding our four-well program there. Further, in an abundance of caution, we have materially increased our assumed weather-related downtime days in this guidance from what we have averaged for the five to 10-year prior to the 2020 hurricane season and for additional plant downtime over the year. Cash operating and G&A expenses are expected to total between $290 million and $310 million and $60 million to $65 million respectively. These figures include a full year impact of multiple completed acquisitions in 2020 and an incremental $15 million in workovers for the year compared to 2020, which this year includes a deepwater subsea intervention. At the midpoint of the production and cost guidance, including workovers, we expect per BOE operating costs of around $12.65 per BOE and cash G&A of $2.60 per BOE, representing further reductions from 2020 costs, excluding workovers. Finally, our capital program for the year will be between $340 million and $370 million, significantly lower than the 2020 capital program. 2021’s program will be weighted towards lower risk asset management, development, and exploitation projects with quick turnarounds to first production. These projects are centered around existing operated infrastructure. The Green Canyon 18 platform program, which builds on the success of the 2020 Kaleidoscope project, has already achieved success with the Tokum well, which was brought online in February 2021, is currently producing over 2,000 barrels a day equivalent to gross. We plan to mobilize the platform rig to our Pompano facility in the next operationally available window, where we will execute a four-well program throughout the remainder of the year and into 2022. At our Tornado field, we’ve planned to build upon the success of our waterflood project with the Tornado Attic well, which could generate incremental production of up to 8,000 to 10,000 barrels equivalent per day gross. Lastly, we’re selectively taking on high-impact exploration projects this year with Puma West currently drilling, and we may add an additional project in the second half of the year. Major exploration projects are a key differentiating factor of our basin, compared to onshore basins, and offer the ability to significantly add resources, future production, and value when successful. In total, our 2021 guidance can be summarized as delivering modest growth over 2020 production levels with a competitive cost structure and an attractive capital program focused on lower risk, quick turnaround projects near infrastructure we own and operate. With consistent strong margins and a measured capital plan, we expect to generate significant free cash flow at the recent strip, while also exposing the business to key catalysts, including the unitization in FID at Zama as well as Puma West and additional high impact exploration projects. We’re excited about the plan for 2021 and what it can deliver for Talos. With that, I’d like to hand the call back over to Tim for his final comments.

Thank you, Shane. We’re proud that all we were able to accomplish in 2020, despite the historic year of interruptions from the COVID pandemic and weather-related production shut-ins and delays. Despite all of this adversity, we maintained a stable business, maintained our already solid credit profile, advanced our safety and ESG goals, and positioned the company for success in 2021 on numerous fronts. As we move into 2021, we aim to execute the balanced plan that Shane presented, mature the rich set of catalysts we have in front of us in the near term, and drive value creation for all of our shareholders as a result. With that, Operator, we’ll open the line for Q&A.

Our first question comes from Richard Tullis with Capital One. Richard, please proceed.

Good morning, Tim and Shane. Tim, if we could maybe talk initially about the comment in the press release related to the range of business development and M&A opportunities kind of being reviewed, if you can kind of give us some details along those lines of what you might be looking at?

Yes. Sure, Richard, good morning to you. Look, I think as part of this is a theme of – we come out of this year, last year, and you see the margins improving and I think you see a measured capital program. We have more free cash generation. We’ve got more liquidity coming out of the capital markets effort. And so I think we’re in a position to think about M&A both strategically and opportunistically. And so exactly where that comes from is always a question. We’ve worked with private companies that could be in a position where they look for a liquidity event. We’ve worked with majors who could be monetizing assets, and that could be a basket of assets or could be individual assets. I think as the commodity price has stabilized, some of those bid-ask spreads and the wildness of all that and the uncertainty around the commodity last year, buyers and sellers from transacting at certain times last year have lessened. I think there’s a better opportunity to transact this year. And we’re also expanding our horizons and thinking about, are there other basins, other jurisdictions, where we have a skill set in offshore operations of full lifecycle operatorship and asset development and follow-on exploration. Is there other basins where we can transfer that skill set to different jurisdictions? So we have looked at some other things in LatAm and some things in the Atlantic margins. We have a very active team. I think this business will do better with more scale and more diversity. I think, we ultimately, it’ll help drive down our cost of capital as we grow for a bigger business two years from now or three years from now. You’ve got to be smart on how you do it, and we’ve got to have our minds open on where we think we can execute well. If we don’t do it in the U.S. Gulf, we typically look for partners to do it with somewhere else. But it’s a busy part of the team’s effort this year. And in the summer, we’re going to stay focused on it.

Thank you, Tim. That’s helpful. And as a follow-up, if you could maybe Shane provide some more details on kind of the conservative approach you’re taking this year to Gulf of Mexico – potential Gulf of Mexico storm downtime, and other downtimes factored into the 2021 production guide? Just so maybe we could get an indication of upside, if some of these things don’t materialize during the year?

Yes. That’s a great question. So historically, we’ve taken a look back approach and looked at the last five years compared that to the seven-year window, 10-year window, etc., to see what kind of downtime we’ve experienced. I think, look, up until 2020, we’d had a pretty modest run, frankly for well over a decade. The average that we used was something less than a week. I mean, maybe five, six days on average over that period. You bake in a year like last year into that five-year look back or five-year average, and there's a pronounced effect. Those numbers, I would say, have doubled or perhaps even a bit over doubled in terms of how they get rolled through a risking from a weather downtime standpoint.

And Richard, this is Tim. And another thing I would add to that and again, I understand that that got a little attention, but I think it’s the right abundance of caution. So that platform rig that we have on the Green Canyon 18 facility. So we put – when you put a platform rig on a facility, the good news is you’re going to drill a nice well, it’s going to have robust rates, and you’re going to get that rate right away. So that’s the nice thing about a platform rig. But it’s a bit of a construction project. You have to move some things out of the way. When we put it on GC 18, I think that facility was making 1,200 barrels a day, maybe 1,500 barrels a day, now we’ve added two wells that are making close to 7,000 barrels a day. So that’s a heck of a success story. Now we’re going to go move it and put it on Pompano. So we’ve got to shut in for some period of time that production just added to deconstruct that platform rig. Then go put it on another platform rig that’s actually making 10,000 to 12,000 barrels a day in the Pompano area. That construction has to happen; there’s some shut-ins. But then it stays out there for maybe a solid year, maybe a year and a half. And hopefully, we’re going to have a heck of a lot more volume when we’re done. But those types of projects don’t happen every year; we have to bake some of that shut-in time. The facilities that we’re putting them on, Green Canyon is a better looking facility from a production perspective than when we started. Pompano is actually a bigger facility when we start. Hopefully, it looks a lot better when we stop, so a lot of explanation there, but all that kind of weighs into how we think about guiding production in this particular budget.

Thank you, Tim. Appreciate it.

And our next question comes from Subash Chandra of Northland Securities. Please proceed.

Yes. Hi Tim, good morning. On your exploration sort of wedge for this year, do you think this – will this been a Talos operated prospect and any more sort of status detail on Puma West where that well is exactly?

Right. Yes, sure. So it’s sort of a couple of themes and thanks for the question on that. We’re trying to make sure we get across here. One is, we’re putting some exploration kind of back in the budget. We think the budgets, by the way, are very measured. It’s a 65%, 70% reinvestment of EBITDA. We have a significant acreage position, Subash, as you know, and we think we can start to put even in a measured budget some wedge of that in exploration and Puma West is an interesting project. That’s not one we operate; our friends at BP operate that. It’s playing a middle Miocene trend that kind of ties around to the Mad Dog area. You have some other discoveries in the area. There could be deeper oil cost potential in that type of prospect. So we’re excited to get that done. It took a while to get back here; they’re working hard on it. Hopefully, we’ll have something to discuss kind of in the weeks or months to come. And so that’s exciting. And then we’re going to go get a rig associated with our waterflood project that we talked about on the call. That rig will have some options. We don’t have any real incentive to try to get a deep long kind of multi-year rig contract. We think in this cost of goods environment, we can maintain optionality. But with that optionality, we might pull in another exploration project. Part of it depends on where we are with Puma West. Part of it depends on where we are both in terms of kind of our own business development effort and what we think the right move is in the second half of the year. So I would frame that as second half of the year optionality and a rig contract based on some of the things we might or might not see in the first half of the year. I think that’s the way, Subash, we want to play it.

Okay, got it. Then onto the – I guess the bank facility. So first, do you have sort of sense of where you might close the quarter on the amount borrowed given all the dynamics in the first quarter? And second, in extending the maturity, do you anticipate there’ll be any significant change in terms?

So I’ll talk about just quickly to the bank group. And then Shane, you can talk a little bit more detail on where we’re going next with the bank group. We’ve had a supportive bank group. Obviously, we were able to get through a flat borrowing base redetermination in the fall and prices have improved since then. I think we’ve heard some chatter about various banks and where they are in different plays on onshore plays and conventional plays. We think we’ve gotten very good behavior from banks that understand the offshore environment. We have a lot of banks that are European banks still lending in other basins there. So we’re going to go through this redetermination and look for an RBL extension. I think we expect support from the vast majority of our banks. The assets are more diverse; they’re more bankable. We’ve got a better price deck. But Shane, you want to provide extra color on that?

Yes. Well, I think part of the question on front was sort of, what does the balance looked like over the course of the year and then to that process? And look, I think, as I said in my comments earlier, anywhere near sort of the current strip or even recent strips, etc., even lower, we think this guidance delivers a lot of free cash flow. The question, I guess, Subash, is what happens to that cash flow. I would expect that that would go to reducing that utilization number over the course of the year, where it’s going to be kind of quarter-to-quarter, it’s going to depend on how the capital program lays out on a quarterly basis and then whatever price deck you or investors split into their models in terms of how that free cash flow sort of rolls out over the course of a year. But I think that would be the use number one. In terms of the group itself, again, Tim sort of covered it. I think I would just only point out that, this is a group that’s been very supportive of us for a very long time. They were very supportive of us in 2020, which was probably the most challenging year many of us had faced from a finance standpoint and a commodity standpoint. The bank market, and that was a market where, look, in a spring with the commodity where it was, we were down 14% relative to most of the oily peers that might’ve been down anywhere from 15% to 30% plus. We held flat in a fall redetermination. They demonstrated great support there. And then as well, I’d say through the recent couple of months of capital markets activity, they continued to show strong support for us. Therefore, I don’t expect that as a group, that’s going to be that much different sort of going into this cycle.

Okay. That’s great color. I guess we’ll say two. And if I just sneak this one in along those lines. So the cash – it looks like cash OpEx for 2021 at least versus consensus was higher. Some portion of that was the additional workovers. What would you attribute sort of the balance of the increase too?

Well... I was going to say, a good portion of it is just a normalization or sort of a full year, if you will, of some of the acquisition activity that took place over the course of the year. We picked up a couple extra months on the ILX and Castex properties and then an extra seven, eight months on the Castex 2005 properties as well. So all that sort of rolls into it – you talked about the additional workover capital that we’ll see this year, that we didn’t see last year. So we wanted to call that out explicitly.

Yes. Then look, that’s always tricky on; it would be preferable to take some of those workovers and capitalize them as asset management. Because a lot of that is like asset management, we’re working on restored production, but we take a conservative approach on kind of how to book that. And it’s appropriate to book at an expense. We book it an expense. So that’s a good part of it. There’s a little bit of rotating equipment, a generator that we want to swap out that maybe we didn’t have to do it last year, or you weren’t willing to do it in a $40 environment, but it makes more sense to do those repairs in a $60 environment. You see a little bit of that, if you have the opportunity to do those projects in a stronger environment.

And I think on an overall per barrel basis, you’ll actually see – it’s pretty favorable. 2021 will be pretty favorable.

I think the message for us is, we’ve clawed back into that corporate margin, inclusive of everything back over 60% in the fourth quarter. And that’s a nice spot for us. It gives us a lot of flexibility to benefit from being oily, having physical differentials come back. If we can stay there and improve on that, I think we’ll be in a good spot.

Thanks, Tim and Shane.

Our next question comes from Leo Mariani of KeyBanc. Please proceed.

Hey guys, I was hoping you could talk a little bit to kind of quarterly production and CapEx cadence. May I see the strong exit rate ending 2020 here, would this imply kind of a higher first quarter production and then maybe it starts to move lower in the second quarter due to the Pompano downtime? And then third quarter, obviously, you’ve got potential hurricane downtime and then kind of moving back up in 4Q on production. Just trying to guess if that’s kind of what it would look like? And then any color you can kind of give us on how the CapEx is kind of spaced out during the year?

Yes. I’ll give a start, and Shane will correct me if I’m wrong. But yes, look, I mean, you’re right. No reason to think January is not hot, obviously, we all had a little weather. You’re going to have a little weather downtime when things ice up, and it’s not like onshore, but you get a little bit of that inconvenience from time to time. We start having some downtime really at the end of this quarter related to some construction work in Pompano. It’s manageable. We do that a little more in the second quarter. You’re going to have a little more, if you will, blend down in the second quarter and then as you get to the third quarter and fourth quarter, you’ll see that blend up. That’s what we expect from the next well in the waterflood project and Tornado to come in. Again, some of the impact of what we do in the Pompano program as that construction project is completed and we start those. We’re going to start the Pompano program. It’s actually some recompletions just kind of right off the bat stuff that gives us some rate and gives us some good economics before we get into drilling. We’re going to have a slide deck that kind of shows how that program works. I think generally you’re thinking about it the right way, Leo. I mean, Shane, did you want to add on that?

Yes, look, I think you’ve got sort of the production path, the concept pretty well for 2021 as we kind of roll through the quarters here. I think on the capital path, kind of the thing to think about is when we do start on the Attic well, and that’s going to be a higher dollar piece of equipment. And so those middle quarters, I think, are when you’re going to see likely maximum activity and therefore maximum capital for the year. So you’ll probably see a flattening out on the production and then turning in the second half. You’ll see the capital a bit of a touch higher in the second and third than you wouldn’t in the first and the fourth. I would suspect that the activity plays out the way we think it is.

And then it comes down, Leo, to some of those – what are the other things that can cause some shut-ins in the Gulf around the weather season? Again, we just have to – we’ve put a layer of risk there. You may or may not see that as appropriate. Typically, that’s been as Shane said, five or six days a year, but if we use a rolling five-year average, which we think is appropriate, that rolling five-year average changed after last year’s season and still, it’s not obviously as busy as last year’s season, it just reflects the possibility of that.

Okay. That’s helpful color. And I guess, maybe just jumping back to the Puma West here for a second. Sounds like you guys are maybe hoping to get some results in roughly a month here. Wanted to get a sense of what the potential in this well just in terms of what the gross recoverable range of resources could be? And then just also wanted to get a sense of kind of what your latest conversations have been with Pemex. Obviously, we’re just a couple of weeks away from the deadline here on utilization.

Yes. We got partners in Puma West and BP and Chevron. It’s great to be in a partnership with those guys. They certainly have all the cutting edge technology that we use. It’s nice to see them use it as well. When you’re partners with those guys and they say, look, we’re not going to disclose pre-drill ranges, you can pretty much hold the line on that. Now, what I would tell you is, it’s a decent neighborhood. What makes this area so interesting is, it was just an area where people couldn’t image the salt. You have a fairly good idea that there’s some geology there, and that geology is kind of the middle and lower Miocene. You see that in the Mad Dog area off to the East, and then there’s potentially Wilcox, which you see to the South. So, you know, you’re in an interesting geological area. This was always about imaging salt and understanding where to put a well and how to image the base of that salt? I think that’s what we brought to the table, certainly BP brought that to the table, and that’s what caused us all to put some acreage together and drill a well. So, I think the guidance is you’re in a good neighborhood that guarantees us nothing other than that’s an area where people should find out if there’s potential, and that’s what we’re in the middle of. Let’s hope we can get through it and have something to say; it’s tricky when you’re drilling 25,000-foot wells through 8,000 to 10,000-foot salt sheets. But the team’s working hard; BP is doing a great job. I think we’re still probably a month or so away from talking about it, and we’ll see where those results land us. Now on Zama, Zama is interesting because we really started talking in earnest last year; we had to catch them up on all the technical stuff. As you know, we were the ones who gathered all of the technical data. We drilled the wells, the core data, the fluid data all that had to get caught up, all that had to be shared, and make sure they fully understood it. Frankly, to give them a level playing field in these negotiations. It was an obligation for us to do it. We were happy to do it. The fourth quarter really shifted to more of a commercial discussion. We started picking up the pace on those items, and what those items are, are operatorship, their equity splits in the beginning that get redetermined later, some of these other voting rights, and nuances that would come with an operating agreement when this is finalized. We really started working that in earnest in the fourth quarter, didn’t quite get to a conclusion, went to the Energy Ministry, showed them the progress. They’re happy with the progress and said, look, we’ll give you another quarter to try to get this panned out. We’re in the middle of that right now. I’m not going to break any news on this call. It’s a day-to-day discussion. Our hope is we will meet that deadline. Look, the Energy Ministry down there expects us to meet that deadline. We’ll present to them at the deadline where we are, and then we’ve got to wait on them to weigh in on where we are, and then we’ll announce that. In the meantime, the comfort we’re trying to give is, we’ve effectively completed most of our feed work. We have all of our design work. Once we get this thing unitized and put into a partnership, this thing can start moving towards that pace towards FID, and that line of sight the first production becomes a little more clear.

All right. Thanks for the update.

Well, Michael, thanks for the question. I don’t ever jinx an exploration project by talking; it’s a general rule for offshore explorers. Look, it’s testing multiple geological layers, and I think that’s one thing that it’s worth understanding. What makes it interesting and what caused all three companies to say, hey, look, imaging is never going to be perfect below salt. We think it’s good enough that we should make this attempt is because of the breadth of the geological section. The reason I bring that up is, you really don’t know what you’re going to end up with until you test all of it. You can find something and then need to go drill the well to try to find something else. Depending on what we find, it’s going to depend on whether you have a subsea tie back that you think you can get to quickly or whether it needs a praise, and you have something different. But that’s all in a situation where you have success; we’ve got to get this theme drilled out and see where we are. If you jinx this, Michael, I’m going to call you in a month and a half, and we’ll have to have a conversation about that. It’s just understanding: you’re testing a big geological section. Although we’d love to hear what happens in the works, you have to get through the process and understand what you know, what you might not know, and what you need to know to make those decisions. So it’s pretty early.

Understood. And I’ll take full responsibility if it’s not a huge success.

All right.

You mentioned that in terms of the Interior’s order, really no near-term impacts on what you’re doing in the Gulf of Mexico. I’m just wondering if it changes your view, obviously you talked about the need for the Gulf of Mexico, but does it change your view at all and your long-term thoughts on operating in the Gulf of Mexico? And you talked about looking at other areas outside the Gulf, does that accelerate your desire to diversify your asset portfolio at all?

Well, so the first question, I mean, it doesn’t change our view on the prospectivity in the opportunity in the Gulf. I think we have a huge acreage position. I think you know that it’s large both on what we hold—our held by producing acreage, where we have assets and facilities. Then in our primary term acreage said, I mean, I think that’s almost 800,000 acres. We’ve got a big acreage position. I think that what everybody else has is a nice acreage position as well. Between our own acreage position and between other folks that are in the basin who are thinking about what’s the best way to partner, monetize, put together different ideas. I actually think you’re going to see a lot of business development come through this as people navigate; they’re going to be future lease sales, or they’re going to be fewer lease sales. How do we manage inventory over the next four to six years? I’m actually excited about, again, how all of us manage this inventory together to make sure we’re making things happen in the Gulf of Mexico. So I’m no less excited about it. I’m frustrated a little bit about the rhetoric around leasing and any kind of conversation on whether our basin isn’t important when we know how important it really is. But I’m not less excited about the business opportunity. Again, we think most of the permits we do are prescriptive, and we’re seeing that play out with this administration. However, to your other question, it does make us think about, look, ultimately, I believe we need to be a bigger company. We need to drive down our cost of capital. That’s not going to happen just by drilling wells; there needs to be some M&A there. We’ve got a skill set; we were able to transfer to Mexico. That’s a different jurisdiction. It might be the same time zone but a different jurisdiction. There’s no reason we can’t transfer that skill set to other offshore jurisdictions in play and other conventional places. Yes, we’re looking at that. I would say some of the regulatory action just kind of says, look, we really need to make that as part of our broad corporate development and M&A focus.

Make sense. Thanks, Tim.

Our next question comes from David Heikkinen of Heikkinen Energy Advisors. David, please proceed.

Good morning, guys and hope everybody fared well through the freeze and thaw. The first question really is on this multiple jurisdictions, Tim, and you’ve kind of hinted towards Latin America; I mean, the offshore skill sets and assets for sale range around Africa and the North Sea as well. Are those off the table?

No.

There’s anything off the table. Okay.

I would say, in that broad Atlantic margin area, no. Again, I don’t want to suggest that you can expect an announcement anytime soon, but no, we are looking at ideas in the Western African region and the LatAm region, and then potentially in the North Sea region. Again, I think it’s because you’ve got maturing assets; we’re lifecycle operators. I think we understand how to get in there and find that next round of value. There’s good seismic, good rock properties. It has the type of ingredients that if we could execute that strategy in the U.S. Gulf of Mexico, the question should be kind of why can’t we? If the question is, well, you need a team, then can you go find a team, or can you find a local partner on some assets? We found a local partner when we went into Mexico to make sure we kind of had the right— we were handling the regulators the right way and thinking about permitting and those types of things the right way. I think you can look at those partnerships or find those entities to make sure you don’t stumble if you go into a new jurisdiction. We have to be thoughtful. I don’t want to over-preview anything, but it’s just—we’re opening our minds up to deal flow in those areas.

And as you think about opening up your minds, Exxon talked a lot about the first 3,000 feet of water that you have to drill through and the subsurface as carbon capture and underground storage in the Gulf Coast. I mean, if you open your mind in that direction at all as well, I mean, there’s a whole lot of regulatory question about who owns floor space and what the opportunity is, but you’re a major project organization with skills and from shallow water to deep water.

Yes. That’s a good question. Well, it’s funny; I mentioned on the call that we’ve obviously, with all dividends dove into the ESG efforts and different companies dive in at different ways and what’s consistent amongst the companies. We’re all trying to figure out how to measure our emissions and then improve and fix as many of those measurements and make sure it’s tight and how we do it and if it’s improving. We’re doing all those things; again, I think we’re going to see three years in a row of that coming down. Then there are some of the social responsibility and some of the social justice issues everyone’s doing that. The nuance then David, I think your question, okay, I’m offshore. We all know the things that everybody’s doing, but is there something different I can be doing offshore because I’m unique to offshore? I talked about in the earnings release, we have these different committees, and it’s all kind of employee-led and homegrown. A lot of that rolls up to Bob Abendschein, who runs our Operations. Yes, we’re thinking about other things where we can play in the space. Some of those things might be able to utilize our platform and extend the life of those platforms; it actually helps you manage P&A budget. Some of those things can be in wave and wind, and could it be in other areas. And then is it just too cost prohibitive for a company our size? Can we partner with a university? I would treat it almost like when I was learning about Mexico. When we were learning, they were opening up Mexico, and there could be Middle Miocene geological prospects down there. I thought if we find out another independent had the courage to try down there and we didn’t try, I’d be pretty frustrated. As we go into this discussion around carbon capture and renewables, if there’s something that can be done in the Gulf in an area where we know how to operate that a company our size can actually play around and be supportive of it. We’re not trying; I’d be pretty upset about that. But what’s trying look like? I think David, that’s what we’re trying to figure out. We would love to see where we can transfer skill sets in different spaces that make sense, certainly in the Gulf of Mexico.

Yes. It’s definitely an OPM other people’s money environment for Exxon. So y’all could have a good way of getting into other people’s money.

We don’t have to brunt the bear of it. I mean, hey, look, we’re good at these things; we offer these skills, labor management, project delivery. How can we help you? Where can we be in this thing? This isn’t a platform well that I need to own 100% of. So I get it, and I agree with that. Yes, we’re opening our minds to it. No doubt about it.

That concludes our Q&A session. I’ll now turn the conference back over to Tim Duncan for any closing remarks.

Thanks, operator. I want to leave you with a couple of points that we think are important because this call is as much about understanding what we’re trying to do going forward and where we’ve been in the past year. Right now, as we sit here getting into 2021, we’ve got a very valuable resource base. You can see some of those sensitivities on our proved reserves. I think the enterprise value of the company is less than $50 a barrel on PDP. So we have a valuable reserve base that doesn’t include the things we talked about on the call and Zama and other offshore catalyst opportunities. We’ve got a huge acreage position with deep inventory—1.4 million acres. One of the biggest acreage positions in the U.S. Gulf of Mexico. We saw improving margins in the fourth quarter, and we expect to hold good positive margins into next year. You can expect a better net barrel, I think part of that’s because of the cost structure initiatives; we’re getting better physical pricing. We tried to show a disciplined capital plan. I mean, could we have put more capital into that program? We could have, but I think we can meet the objectives we want to meet—a 65% to 70% reinvestment rate. We still have—we’re going to stabilize this business; we still have catalysts. By doing that, we generate more free cash flow, which gives us flexibility, adds to an already strong liquidity position, and gives us some opportunity in the M&A space. That’s why we’re so excited about this year. That’s why we’re excited about reporting back to you as we go throughout the year. We’ll freshen up a deck, and we’re going to be in some of the conferences coming up in the coming weeks. We look forward to catching up with many of you then. Thanks for your questions, and thanks for being on the call. We hope to talk to many of you very soon.

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