All right. Good morning, everyone. This is Lloyd Byrne from UBS Energy. We are really pleased to be hosting the senior management team from Hess this morning. Let me begin with a statement I need to read first. As research analysts, we're required to provide certain disclosures relating to the nature of our relationships, and that UBS with any company we express views on, these disclosures are available at ubs.com/disclosures. Alternatively, reach out to myself. I can provide them. All right. Now from Hess, we are thrilled to have CEO John Hess, CFO John Rielly, and COO Greg Hill, along with Jay Wilson, who heads up investor relations. I want to hit on a few highlights of their respective careers first. Then I will turn it over to John. I'm always impressed reading your CV, John. 25 years as CEO and deserves a lot of credit for leading a strategic transformation of this company into a pure play E&P with some of the best resource, if not the best resource in the world. Serves on multiple boards, KKR, Board of Trustees, Center for Strategic and International Studies, Executive Committee of the API, numerous charitable endeavors. I could be here all morning on that. Recently served as secretary of the Energy Advisory Review Task Force. There's lots more, I'll stop there. Let me hit a couple of things for Greg and John. Greg Hill, most of you know, COO, President since 2009, 25 years at Shell in a variety of operations, engineering, technical, business leadership, Asia Pacific, Europe, U.S. exposure. He's on the board of Harbour Energy, a private equity firm. He's chair of Wyoming's ENDOW initiative, board members on a number of other institutions. John Rielly, responsible for overseeing treasury, tax, risk management, investor relations, accounting, financial reporting, audit, prior to joining Hess, spent 17 years at Ernst & Young, where he was a partner in 1996. Really impressive group. Thank you for coming on. Let me start, John, with you, and maybe you can hit on a little bit on the macro, how you feel about that today, and then what are your priorities for Hess? I have a number of questions that are already coming in from clients. Yeah, great. Let's start there. Lloyd, thanks a lot for hosting this session. Always enjoy being with you. Just some quick thoughts on the macro. The market's been rebalancing really since last June, I'd say, after OPEC made their historic production agreement, with U.S. involvement and obviously, Russia involvement. That rebalancing continues today, where demand is greater than supply. The market's in deficit. Just to hit a few key points on demand, V-shaped recovery, we think oil demand is currently running about 95 MMbpd. While there are headwinds from the COVID outbreaks, the tragic outbreaks in India, the U.S. and China growth is definitely accelerating. I think Europe's not far behind as Europe starts to open up for the tourism season this summer. It's all about the vaccines and the economy reopenings and warmer weather. You got to remember, and it's painful, oil was only about $40 a barrel WTI in November, and it's $65 a barrel today. Obviously the price recovery is very much, I think, underpinned by the demand recovery. Supply is another matter where demand was V-shaped recovery. We see supply as U-shaped. It's a lot stickier to recover. You look here at shale, U.S. rig count's about 455, going up very gradually now. While it's up versus a year ago when the industry shut down as there was no place to store the oil, the rig count's still down from 1,000 about 18 months ago. We see U.S. crude production in the range of 11 MMbpd, down nearly 2 MMbpd from December 2019. I think some interesting things, certainly the shale recovery being sticky is in part because companies have a newfound discipline to run their companies for cash flow as opposed to just production growth. I also think there's another reality. As the rig count went to historically low levels a year ago, getting the people back, getting the equipment back, it's a lot stickier. Getting the permits to have drilling locations, a lot stickier. We can't go from zero to 60 in one second. I think just the physical infrastructure to get in place, both people and equipment, I think we're at those levels where to go up much higher would be difficult. At the same time, investors, rightfully so, wouldn't allow it. I think that stickiness is going to stay for this year. When you look at the rig count, we've modeled it out. Even if the rig count got to 500, maybe year-on-year growth would be 300,000 bbl a day. If the rig count were 600, maybe it's 500,000 bbl a day. We're not going back to the growth halcyon years of a million barrel a day growth coming from shale. Shale, I think now has taken a backseat to OPEC in terms of keeping the market in balance and the market in equilibrium. I think those are key points. We see shale having gone from a growth industry to a harvest industry with financial discipline guiding behavior. Right now, production is sort of flatlining a bit. Maybe it's going to be up by the end of the year, 100,000 bbl a day, and if it levels out at 500 or 600, it will play a role, and that oil's going to be needed as demand outstrips supply. The key point here is it's going to be a very different role going forward in the oil mix for the world than it was in the past. OPEC's back in the driver's seat. I think they've been very clever, intelligent, wise in how they brought their oil back on, about 2 MMbpd between Saudi Arabia and the OPEC+ group coming back between May, June and July. Remains to be seen where that is going forward. Right now the market's still in deficit of 1 million-2 MMbpd. You have a V-shaped recovery in demand, a U-shaped recovery in supply. What does that all add up in inventory? Inventory supply glut a year ago, April, was about 1,100 million bbl. A bit over 1 billion bbl. At the end of December, it was about 550 million bbl. We think by July, the market's going to be back into equilibrium and at pre-COVID levels. The futures market anticipates that and reflects that. Going forward, going into the second half of the year as well as next year, I think there are three 'I's that guide the market. One is inflation, one is investment, and one is Iran. On inflation, the stimulus programs in the U.S. as well as across the world have turbocharged the consumer GDP growth. I don't think that accelerator's going to let up, and that underpins oil demand. You and I were talking before this session. There's probably 3 MMbpd of jet fuel demand that has been curbed. People are going to start, they already have in the U.S., start flying again. When Europe opens up, I think that's just going to increase 2 MMbpd of demand growth. We really see demand growth going up between now and the end of year, at least 3 MMbpd. That sort of perpetuates the inventory deficit. Investment's key. The IEA was controversial last week. We can talk about it in coming up with a scenario. People took that to mean that's their position on outlook. While there's some political advocacy there, at the end of the day, I think it's just a scenario. The IEA has pointed out the world needs to invest basically $500 billion-$600 billion a year to grow global oil and gas production to keep up with demand. Last year, that number was $300 billion. For the last four or five years, that number's been $450 billion down to $300 billion. We're not investing enough, and really it was the COVID shock from demand shutting the supply side of the business down that finally got the market back into equilibrium. Ultimately, as demand grows, you're going to need to offset production declines and meet demand growth by increasing the whole investment. Ultimately, the other wild card that faces us today is Iran. What's the deal that the U.S. and Iran are going to make? Do they make it in one step? Do they make it in multiple steps? Obviously, a lot of negotiations are going on in Vienna. According to news flow, the market goes down a couple of dollars, goes up a couple of dollars a barrel. At the end of the day, we believe Iran's already moving about 750,000 bbl a day of exports out there. At the end of the Trump administration, that number was 250,000 bbl a day. There's incrementally at least another 500,000 bbl a day on the market. Remains to be seen, the 1,200,000 bbl a day that's probably left as spare capacity. Does that get feathered in as the sanctions get relieved and Iran gets back to the JCPOA status quo ante? Remains to be seen. We don't know how that's called, obviously that's going to be a headwind and it's going to be something that the market's going to have to absorb. We'll see where that is. You've talked about our priorities. We have a differentiated strategy versus other oil companies that are very shale dominated. We believe in having longer cycle and shorter cycle reserves. The longer cycle in Guyana aren't so long. Basically from investment decision to first oil, it's about three years. ExxonMobil is providing industry leading project management and bringing these production ships online. Basically our strategy is pretty straightforward. First, it's to grow the resource in a capital discipline manner, investing only in high return, low cost opportunities. We want to have a low cost to supply. We're driving our cost to supply for our portfolio to $40 a barrel Brent. Even as oil demand may curb, and we don't think it curbs actually out until you get to about 2030, even with the efficiencies of electric cars that are coming on. Volatile business as well as where does demand go longer term. The key is oil and gas are going to be needed 20 years from now. The key for any company is to have a low cost of supply. Ultimately, it's to provide industry leading cash flow growth. If you look at page 19 in our investor pack, we benchmark ourselves with third-party estimates versus our peers. Third-party estimates on price, on cost, on capital, et cetera, and volumes. What you see there is, we compound our cash flow growth 38% between now and 2023. The peers are 18% median. Basically, we're in the top 5% of the S&P. What differentiates Hess the most is cash flow compounding growth, and free cash flow as a consequence, and it's sustainable. I was at an investor conference not too long ago as an investor to try to learn what's really on the mind of investors. They said, "We want companies with durable cash flow." They were talking about companies like Amazon. We have competitive cash flow with some of the best companies in the S&P. That's really what makes us different, and that allows us to sustain, once we get our debt paid off, increasing our cash returns to shareholders through first dividend increase and then ultimately variable increases, whether it's share repurchases or variable dividends, but it's a cash flow growth that is differentiated versus any of our peers. Major oil companies can grow cash flow but not grow. Shale companies can grow and not generate cash, and if they generate cash, they can't grow. We can grow, but we can also generate free cash. That's the value proposition that differentiates us, and I'd say that's the overarching priority for the company to deliver that cash flow growth by executing the strategy. Portfolio is differentiated because it is balanced between short cycle and long cycle. It is about that low cost to supply. When you look at it's three cash engines in the Bakken, our largest operated asset, Gulf of Mexico, that is low cost and generates cash, where we're an operator, and also Malaysia, where we have basically a cash annuity from gas fields out there that have oil indexed to the pricing. They're advantaged. Prices there are closer to $5-$6 an MCF, where obviously in the U.S. it's half that now. The growth engine is Guyana. What's interesting about Guyana, once the second ship, Liza phase II, comes on the beginning of next year, Guyana becomes a cash engine. All of Hess's assets are cash engines, even though we're reinvesting in the business. This year, the capital guide is about $1.9 billion. As we go forward the next five years of reinvesting predominantly in Guyana, but also in the Bakken, where we're growing the resource, growing our production, growing our revenue, but we're growing our cash flow at basically twice the rate of what our top line is. Ultimately, as multiple phases of low-cost oil developments come online in Guyana, our portfolio break even, as I said before, it gets to $40 Brent by the mid-decade. We deliver that industry-leading free cash flow growth that I talked about. That is something that the shale-dominated companies can't compete with. The strategic priorities for us, as we go forward with that strategy that I just talked about, is to preserve cash, preserve capability, and preserve our long-term value of our assets. Cash at the end of March 31st was $1.86 billion. Our revolver was just extended to 2024, $3.5 billion that's undrawn. No debt maturity until 2023, and that's basically our $1 billion term loan, which by the way, is a key priority for us to pay off before it comes to expiration. Capital program of $1.9 billion, 80% going to Guyana and the Bakken. The Guyana development, so phase I, phase II, and Payara, have a break-even of $25-$35 Brent. Those are industry-leading statistics by any measure. In the Bakken, Greg will talk more about it. Basically, we have a four-rig program, and right now we're running two rigs. For a four-rig program, we have a 15-year inventory at $60 WTI. Oil hedging, we use puts, so you don't cap the upside. Basically 120,000 barrels a day at $55 floor this year, and 30,000 bbl a day Brent with a $60 floor. John will talk more about it, but we'll look to add an insurance program next year with puts as well. Also, in this, we want to keep the portfolio focused on those highest return, lowest cost opportunities. We have been opportunistic in the business development market, where we sold the southern half of our Bakken acreage that we weren't going to drill for the next five years, wasn't tied to our Hess Midstream infrastructure. We got $312 million that's already in the bank from Enerplus. That is on top of that 1.86 billion that I talked about that we had at the end of March. $150 million selling Denmark. Hopefully, that closes third quarter. We also monetized a very small amount of our interest in Hess Midstream, where we put more units in the public's hands. We got $70 million for our net share there. In the Bakken, we're giving serious consideration to go to a third rig as we enter into next year. It's about keeping the Bakken as a cash engine, but also optimizing it for our infrastructure and optimizing it to maximize our cash flow growth, and Greg can talk more about that. The company is positioned well, certainly in this environment. Next year, we're going to be getting in the range of about a billion dollars of incremental EBITDA on top of what we have. That's part of what drives our industry-leading cash flow growth. That's as Liza phase II comes on, assuming current prices. The cash flow differentiation is what differentiates our company. The fact that we can extend it not just to 2025, but outwards to the end of the decade, is something that I think offers unique value proposition for our shareholders. That's the lead-in. Happy to open it up to any questions you or anybody has. Perfect. Thank you, John. For people who are on the line, if you want to send in questions you want specifically answered, I've got a bunch coming in already. Please do so through the system, and I'll get those to these guys. Let me start, maybe we go to Greg Hill, and you can talk a little bit about Guyana, the flash gas compressor discharge silencer. Maybe just where we are there. What I found interesting about recent comments from Hess is that the capacity actually can go higher on that unit going forward. If you look at kind of the quarterly progression and then the annual progression, it means it's going to be significantly higher in the fourth quarter. Maybe, Greg, you can just talk about where you are right now, and then we can talk about what it means for the capacity down there. Sure. Thanks, Lloyd. The vessel right now is operating at about 120,000 bbl a day. It's operating at nameplate right now, even without the flash gas compressor. The flash gas compressor has been repaired. Small amount of redesign. It will come back out on the platform in June such that it will be operational, call it July 1st, right? Once it becomes operational, then you'll be able to walk the production rate up somewhere between 120 and 130. They'll wind it out and get it somewhere in that range again. I think importantly, as you mentioned, in November of this year, we will do two things. We'll take a shutdown, and we'll install a new design flash gas compressor. Basically, a completely redesigned one to hopefully get it more reliable. The second most important objective of that November shutdown is to debottleneck or optimize the facility such that a new nameplate will be somewhere between 140 and 150, in that range. Certainly, hopefully in December, once all that work's done, you can see us begin to ramp up to that higher nameplate capacity for next year, having a new production plateau for that vessel. All going well. Again, we're operating at nameplate, as I said, right now, the 120. Get a little gas, flash gas compressor comes back out, and then the final jump up for shutdown. Greg, does that impact Liza phase II at all? You have a 220,000-bbl-a-day capacity there. If you look out at Payara, it's 220,000 bbl- Sure understanding some of the bottlenecks that you're seeing in Liza phase I as you go through it, does that change those capacities as well? Yeah, I think it will, which is very typical for these large projects like this. Why do you typically see a debottlenecking afterwards? The answer is very simple. You need the dynamic data of operating that vessel at its capacity to understand where your pinch points are. You need six months to a year of operating data. Then you can go in, put in some piping changes, et cetera, eliminate those bottlenecks, and then go to a higher nameplate capacity. Typically, you can probably count on 10%-15%, just round numbers. We'll wait and see until we get the dynamic data. I think within that range. The 220 maybe becomes 240, something like that. I think it's pretty typical. Okay. That's great. Maybe go back to John for one second, John Hess. As you go to the fourth development, Yellowtail is, I guess, the third development. The fourth development, Yellowtail is 2025. Any unique government approvals? Maybe just talk a little bit about. I know you were in Guyana recently. How the working with the new government has been. Just that relationship and how you expect that to progress going forward. Yeah. The government is very pro-business, wants oil investment to be accelerated, doesn't want it to be slowed down. I know from time to time, a Bloomberg reporter will quote someone. It's not someone from the government. It's actually not someone from the opposition government either. The people of Guyana, this current government especially, want to keep the momentum in oil investment because that's the best way for them to get shared prosperity and to improve the lives of every Guyanese citizen. Met with President Ali and Vice President Jagdeo about three weeks ago. Very constructive dialogue. Talked about Yellowtail too, how important it is to have a thoughtful but expeditious approval for that development. The fact of the matter is they took over in August, and before September 30th gave us approval for Payara, and now we're talking about Yellowtail. Yellowtail is a large resource. We're going to be ready to go. The environmental impact statement is already in to the government, Active dialogue between ExxonMobil as operator with the government to get that project sanctioned and approved before the end of the year to keep it on track for first oil in 2025. I'd say the government is very constructive in working with us. This whole issue in the flash gas scrubber is a good example of Exxon and they working together to resolve any outstanding issues. We're back to business there. In terms of Yellowtail, it's a top priority for us as a joint venture, The government's working with us to give us, I'd say, an expedited approval. Making sure all the issues that the government has are addressed, That's really what the next six months are for. I'd say the attitude of the government is very pro oil investment, because that's the best way to lift the country out of poverty and have a much better future for all Guyanese. Great. Thank you, John. Let me stick with Stabroek. A lot of the questions that are coming in are about the Santonian. Maybe you can just talk a little bit about how you're seeing that rock properties. I'll read you a couple of the comments. One of them is: Is it fair to say, so far, that the Santonian rock properties are less commercially viable than what you've encountered in the Campanian? What have you learned from other wells? Maybe you or Greg can talk a little bit about the exploration program as well going forward, and what zones you expect to test. Yeah, I think it's important, and Greg will answer this, it's still very early days to have definition on the Santonian. That's part of what this year's exploration and appraisal program is designed to do, and we're still in the early innings of that. Yeah. We've had some very encouraging results, but we also need to get more holes in the ground. We have an active program that Greg will talk about as well. Greg, with that. Sure. Yeah. Thanks, John. As you know, we have three rigs in theater really focused on exploration and appraisal this year. With that program, we'll get broadly 12 wells in the E & A space. There's three major objectives of that three-rig program. The first one is to appraise existing discoveries such that we can begin to underpin FPSOs five and six. For example, Uaru-2, nice discovery, 120 feet. We're also on Mako-2, current operations ongoing on that. We're also operations ongoing on Longtail-3. Again, the purpose of these appraisal wells is to underpin FPSOs five and six. Potentially, FPSO five is Uaru, Mako, again, kind of in that nice Liza corridor. Maybe FPSO six is Longtail. Again, that's the purpose of that leg of the program. The second objective is to continue to fill out that mosaic of Campanian opportunities that you see in our investor pack that really stretches from Turbot all the way up to Liza. Some upcoming wells on that one called Koebi, which current operations are underway, and also, just around the corner, a well called Whiptail. The third objective, which was what your question was really about, is we're going to get some penetrations in the deeper part of the play. The Santonian, I'm going to say it's lower Campanian and Santonian. It's not, I think we've used the word Santonian, but it's really lower Campanian and upper Santonian sand packages. They're about 3,000 ft below the upper Campanian, which of course, is where Liza and all the developments are. What do we know about it? Well, we've got four or five penetrations in it that show good reservoir quality and good hydrocarbon quality. We also know from Apache's results that have been public and also through industry circles that the lower Campanian/Santonian over there looks good. Again, good reservoir properties, good crude or good hydrocarbon properties. I think it's encouraging, but as John said, we've got a lot of drilling, we've got a lot of understanding to do. I think why it's so important is because the aerial extent of the reservoir system, the sand packages laid down by that ancient river system, is as extensive or more extensive than the upper Campanian. Obviously, we're going to need to understand that in the next couple of years. How does it play? I think it could play as ullage fillers, tieback opportunities, as well as standalone developments on their own right. Exciting space, but early days. We'll know a lot in the next 18 months about the size of that resource. Greg, thank you. One of the questions that has come in is, "Is the Apache discoveries at the same depth as your drilling?" I think they want to know whether it's anything comparable to what you're looking for. Yes, I think it so it is. Again, it's this kind of lower Campanian, upper Santonian stratigraphic interval which is basically consistent across the Stabroek Block over near the Apache Block. I think the important thing for us as well is that it not only has a read across into Stabroek because we have similar results in the four or five penetrations that we have, but also in Block 42 in Suriname, recall Hess has 1/3 interest in that, and also Block 59, which we have 1/3 interest in as well. We see those sand packages from Apache's Block going out into Block 42. We'll drill our next well in Block 42 in the first half of next year. We're excited about that as well because those sand channels go right out into our block. Excellent. Thank you. On Uaru, just quickly, I know you mentioned it, 6.8 mi away from the discovery well. Can you just talk about that and is the feeling that that's all one reservoir? Go ahead, Greg. Sure. Again, Uaru-2 was 120 net feet of pay. Very nice discovery, and certainly the static pressures show that it appears to be in communication with Uaru-1. We're going to want to go in there and get it tested and all that, but certainly very positive indications that it's connected to Uaru-1 based on those static pressures that we saw. Okay, awesome. All right. Let's move to the Bakken. John, strategically, it's a little bit higher cost asset. You talked about $50. You were very disciplined about not bringing rigs back till you got to $50. You talked about potentially bringing back 1/3 rig with a $65 oil market. Maybe can you just, would you go third rig? Would you go fourth rig? What makes economic sense at this point, and what are you looking at to do that going forward? Maybe start there, and then I want to talk about cost structure and some of the improvements there. Absolutely. Greg will field this one as well. I think the key point, running two rigs, we basically keep our production flat and our cash generation flat. Third rig compounds the cash flow growth, it's very complementary to our strategy. Greg, why don't we discuss our strategy for the Bakken and how it fits in the portfolio? Sure. Yeah. The function of the Bakken in the portfolio is to be a cash generator. The primary growth element for the company, as John mentioned, is going to come from Guyana, obviously. The role of the Bakken is a cash engine. The rate at which we add rigs to the Bakken will be a function of corporate cash flow needs, number one, which is obviously a function of oil price. Having said that, we don't want it to decline away. We've got an adequate inventory. As John mentioned, we've got 15 years of drilling, assuming a four-rig program of good high return locations. We'd like to keep that cash engine going in the Bakken. With the third rig, we can keep it flat in kind of the 185-200 range, somewhere in there. With the fourth rig, which again, we'll make that decision down the road, that's not going to come this year. Perhaps next year, towards the end of the year, we might make that decision. Firmly put the Bakken at 200,000+ bbl a day. Why is that important? At 200,000 barrels a day, as John Hess mentioned in his opening remarks, you really maximize the utilization of the infrastructure in the Bakken. At that point, the Bakken becomes a billion-dollar-a-year, plus or minus at $60 WTI cash generator, and we can hold it there for almost a decade with the inventory we have. Again, it becomes this massive cash engine. It's already a good cash engine, but imagine a billion-dollar free cash flow for a decade. That's our ultimate objective, as I said. That will be governed by corporate cash flow needs, crude price. Ultimately, we'd like to get back to that four rig to maximize utilization of the infrastructure and preserve this massive cash engine we have. Greg, let me ask you one more question on it. Can you just talk about costs? You've obviously done a good job bringing down your per well cost. I think plug and perf was probably the biggest driver. Can you talk about sustaining those costs, which are significantly lower than 2019, I mean, 15%-20% lower? Any of the cost pressures you're seeing today, steel, labor, diesel, et cetera. Can you pass all that with capital efficiency? Sure. As I think we announced in our earnings call, we reduced our guidance for the Bakken to $5.8 million per well average this year. That's relative to $6.2 last year. Those gains are primarily through lean manufacturing and technology. We are seeing pressure across the sector, as you mentioned, commodity-based chemicals, steel. Now we've mitigated the steel pressures because we pre-bought the majority of our oil country tubular goods at the start of the year. We saw those pressures coming and went out and bought all the pipe we needed for this year's drilling program. We feel really confident about that $5.8 million number. As we go into next year, let's see. What I will say is in the past, we faced those pressures, and we've been able to offset them with lean manufacturing gains and technology gains. Obviously, we'll guide well costs next year. There is pressure, the teams are laser beam focused on making sure we cover any inflation next year. Let's see where the end of the year brings us. Okay. That makes sense. Maybe I know John Rielly's on the line. I don't want to totally ignore him. John, it's a totally different year than a year ago or a different place than we were a year ago. You guys did a really good job managing through with the lines and hedging. Maybe you can talk a little bit about hedging next year. I know John Hess mentioned putting in some hedges, what are your priorities? You're paying off the $1 billion in 2023. Is that a comfortable level of debt at that point? Just some of your highlights on the financial side. Sure, Lloyd. Thanks. As John mentioned too, we had $1.86 billion of cash at the end of the first quarter. We've completed the Bakken acreage sale. We received those proceeds. That's $312 million. We received those already. We have the Denmark sale still to be completed, which we expect to close in the third quarter. We're in a very strong cash position this year. Where we are with hedges, we do have 120,000 bbl a day hedged at $55 WTI. We have a 30,000 bbl a day hedged at $60 Brent. Again, have a really nice floor. Obviously, price, as you said, it's a completely different year. Prices are up, with the cash position that we have here, we are looking and wouldn't have said this to your point six to eight months ago on being able to start paying off this term loan earlier. We were more talking by the end of the term or the end of 2022. We now, where prices, if they stay strong, we'll be looking to start some of that debt reduction of the term loan this year. To your point, once that term loan is paid off, the billion-dollar term loan, and we have phase II coming online next year. John mentioned it briefly in his remarks, but if you don't mind, I'd like to do it. I'm going to use round numbers. You could take our 30% entitlement on a 220,000 bbl a day ship there when phase II comes online. You just saved approximately 60,000 bbl a day. Multiply that by 365 days, you get 21.9 million bbl on a run rate when it's up running full. On an annualized basis, pick your Brent price. If you pick $60 Brent, let's just say that because we get Brent parity pricing from Guyana, and there's a $10 cash cost there, you have a $50 cash margin. You multiply that out by the barrels, you've got $1 billion of additional cash flow EBITDA coming into the company when that phase II is up and running. Once we have that online, one, obviously it's a nice cash inflection point for the company. From a balance sheet standpoint, we have the term loan paid off with that additional cash flow coming in. We're going to drive our debt to EBITDA underneath our 2x target, and that's the max we want to be. What we're going to do from there, Payara comes on. Now you've got another $1 billion of cash. Yellowtail comes on, another $1 billion of cash coming in. That debt to EBITDA is going to drive not only under two, but it's going to drive under one. Yes, we are very comfortable then with our balance sheet and believe our balance sheet's just going to continue to get stronger as each FPSO comes online from that standpoint. Comfortable with that. Debt maturities, we're in a very nice position. We have $300 million besides the term loan in 2024 and we don't have until 2027 another $1 billion. There's nothing that says we need any further debt reduction at that point. The balance sheet will be in really good shape, that's when, as John said, once we get that balance sheet under that two times target, basically when we pay off that term loan, we're going to start with our returns to shareholders. The first thing that will be increasing the dividend. We want our dividend to be more than competitive with the S&P 500. Again, riskier business, we want to do that. That'll be the first. As I mentioned, when you have Payara and you have Yellowtail and if Uaru-Mako is the fifth one, with this significant cash flow increase, that's the further returns will be opportunistic share repurchases or special dividends at that point. All right. That all makes sense. The $1 billion you're talking about from Payara Yellowtail, that's a $55 oil? What's the oil price assumption? I was using $60 Brent there. $60. Even if you use $60 Brent puts you over $1 billion, $55 Brent puts you just slightly under $1 billion. Under $1 billion. That's terrific. I can't believe we're running out of time. I want to go back to John Hess for one second and ask him about strategy going forward. He mentioned it. One of the things that you've really done well is manage this process and this transition, and you've continued to divest assets. Obviously, John Rielly just talked about Denmark, Little Knife and Murphy Creek acreage in the Bakken. How does the Gulf fit into that? How does the Asian gas assets tie in? As you start to generate a lot of free cash flow out of the Yellowtails and Payaras as well as Liza, how does the Bakken fit into that too? Because you talked about being a low-cost asset company being most important in the oil future going forward. Great questions. All of these assets, the cash engines talked about the Bakken, Gulf of Mexico, Deepwater, Malaysia, and obviously Guyana. They all fit the criteria of high return and low cost and basically driving our cost to supply down and generate that compounding cash flow growth. Those are all key to our portfolio. The only asset that's really out there that we would look to monetize, assuming we got price that met our value expectations, and you get a sitting government in Libya that could approve the sale, is our Libya holding. It's not core. It's a cash engine. It's fine in the portfolio, but it's certainly not strategic in the portfolio. That would be something we would look to monetize if and when the stars lined up, both with a buyer and also with the government. That's the point there. As Gulf of Mexico, you asked about, it's a low cost of supply. We run it as a cash engine. It also has some investment opportunities going ahead. While a lot of people were looking at building positions in the Permian, we just never could find in the last five years anything that made economic sense to compete with the portfolio that we had to meet our strategic priorities of resource growth as well as going down the cost curve and sustainable cash flow growth. In the Gulf of Mexico, when people were looking to the Permian, we actually built our inventory position. I think it's a coveted position now where we bought 60 exploration blocks for $120 million. With what's going on with Biden now of having a moratorium, I think they're worth more now than they were before. About 1/3 of them are for tiebacks, 1/3 of them to our infrastructure, 1/3 of them are for the Miocene play, and 1/3 are for the Cretaceous emerging play. They all have excellent returns that compete in our portfolio. That's what it's about. Having a portfolio of opportunities that have very high returns and low cost. The Gulf of Mexico is a keeper. Yes, we did sell Shenzi a year ago to BHP, the operator. We had a different view of capital requirements going forward and what the return profile were. It worked for them. We were able to get fair value. We're not looking to sell down more in the Gulf. We're actually looking to invest in the Gulf as we move forward. Maybe one tieback a year or one new exploration prospect a year, one particularly that we're looking at next year that we're reviewing. At the end of the day, the Gulf is a keeper as a cash generator, but also as an opportunity for future investment with high returns that are competitive in the portfolio. Malaysia is just a cash annuity that's low risk, very good cash returns, and so that's a keeper too. Obviously, the Bakken, we've sharpened the focus there to keep the highest return well locations in our portfolio. A lot of people in shale are worried about their inventory. We have an excellent inventory for a four-year program for the next 15 years. The focusing of the portfolio has been a long journey to get it to where it's gotten to. We're not looking to M&A to enhance it because basically anything we've seen in the business isn't competitive with the cash returns that we get. We're going to stay very focused on executing the strategy that we have. Other people are doing M&A predominantly in shale to either get their SG&A down or get their well inventories up. We've already taken care of basically our future cash flow growth opportunities by a portfolio of investment opportunities that are some of the best in the business. That's great. I'm going to keep you over for a couple of seconds because I have a couple more questions that are coming in. Can you talk about your carbon capture initiatives, ESG, and then particularly your work with the Salk Institute? Sure. Thanks. Look, sustainability is a core value of the company. We've been doing a sustainability report for the last 23 years. We support the aim of the Paris Agreement, which will ultimately be the Glasgow Agreement, and also the global ambition to net zero. We have in the past set aggressive targets for greenhouse gas emission intensity reductions, and also flaring intensity reductions in 2020, scope one and two, to get our greenhouse gas intensity down. We surpassed our targets and had a reduction of 40% flaring intensity, beat our targets where we reduced 60%. Greg and the team have come up with ambitious targets for 2025 that our board has engaged and approved, where greenhouse gas intensity goes down 44% by 2025. That's on top of the reductions I just talked about, and methane reductions down 50% between now and 2025. All of these are actually more aggressive targets than the OGCI has set. We're on a path actually that's better just for scope one and two to get to net zero by 2050. We're continuing to move the bar up and be aggressive in terms of reducing our own carbon footprint. We do believe the industry has a very important responsibility and role to play to combat scope three, even though scope three isn't just from production, it's from the consumers that consume the production. I think everybody's got to roll up their sleeves. Bill Gates' book, if people haven't read it, "How to Avoid a Climate Disaster," really talks about the difficulties in technology and innovation to be able to reach net zero, that it's something we must triple our efforts to do. The role that Hess is trying to play there is really looking at nature-based solutions as opposed to industrial-based solutions, and working with the Salk Institute, supporting their research. I was out there recently. Brilliant scientists. There are over 50 people working on this project right now, where basically you use Mother Nature. Who better than Mother Nature to capture carbon and store it in the ground? There's more carbon stored in the ground, in the soil, than there is carbon in the atmosphere. If there's a way that Mother Nature can get more efficient in doing its work, it could be a game changer where it could save gigatons of carbon a year from going in the atmosphere, keeping it in the soil. It's basically where you take different crops where they have wider roots, longer roots, and also more absorptive roots with an element called suberin to basically accelerate that process. It's still in early days, going from the greenhouse to field trials. It's something that we think is going to play a key role going forward in helping the world have more energy, have more oil and gas, but having a lower carbon footprint and really getting on a path to net zero. A lot of innovations are going to be needed. A number of them will be industrial based. We think there's a great opportunity in nature-based solutions, and that's why we're supporting that groundbreaking research, and we're very bullish about it, but it is in the early innings. John, thank you very much. By the way, I agree with you on Bill Gates's book. That is something worth everybody reading. It's a must-read. Yep. We are completely over and out of time. I'm sorry I didn't get to all the questions that were sent in. I appreciate everyone dialing in to listen, and I really appreciate John Hess, CEO, Greg Hill, COO, John Rielly, CFO, and Jay Wilson, Vice President, Investor Relations. Hess, thank you very much for your time, and we'll talk to you soon. Thanks for hosting us, Lloyd. Thank you very much. Thanks, Lloyd. Thank you.