Note to self, don't have a reception on a Wednesday evening and extend the bar hours. Welcome, everybody. Thank you for making the trip to Terranea for our second day. We are delighted to have Hess Corporation as our keynote kickoff for day two. John Hess is gonna join us on stage here in a minute, along with my colleague, Francisco Blanch, who covers the commodity sector for us. He's actually our lead strategist on commodity and derivative strategy, so a very important member of our team. As you know, we've been trying to do a little bit of polling as we go. I'm sure as everyone else joins us today, we'll get through more of these questions. I did wanna try and keep this survey to help us write our post-conference report moving along. Scott is gonna bring up a couple of questions for us before I invite John and Francisco onto the stage. If you could all get a hold of your buttons, and we're just looking for a little bit of interaction and some, you know, not necessarily obvious questions, but the first one is, reflecting on what happened a month or two ago when Saudi cut production at $85 oil. Here's an interesting question. Let's see what you think of that one. We're gonna give you some numbers, so concentrate a little harder on the next two. Okay, interesting. All right, let's go to the next question, Scott, please. This is really for Francisco's benefit. Give it a few minutes to figure out the buttons. Maybe, Scott, we need to cut the time to five seconds. These guys don't need that long. Okay, 2023, where are we coming out? Okay, interesting. Was at $80-$100, so right where we are currently. Let's go to the last question for this session. This is the one I care about. This is where the equities trade. Oh, boy. Okay. Well, I guess that's not too bad, $80-$90. Our view is that the sector is probably pricing in high $70s. That kind of says a lot about where we think value goes from here. Okay, we'll keep these going through the course of the day. Mr. Hess and Francisco, would you please come up and join me? Thanks very much indeed. This next session, we asked John basically to join us for a discussion on both about the macro, and Francisco is gonna lead that discussion. Yeah, sure. We're gonna get into some of the specifics about the company. I'm sure everybody knows how differentiated the Hess story has become this last four or five years. John, the macro is what, and sadly, rightly or wrongly, we all have to start our days trying to figure out what we think that's gonna look like. The question we get all the time, and it's one that you deal with every day, is whether this cycle is different and if so, what the drivers of that are and how it influences your thinking about it around your business. Maybe if you kick off with that, and Francisco will lead a 10 minute discussion. Perfect. Welcome, everyone. Thanks for coming this morning. Doug, thanks for hosting it. Francisco, it's a pleasure to be up here on the stage with you. This cycle is very different. Normally when we have had price moves in the oil industry over the years, it's either been demand shock or supply shock. This one is the first time that it's been actually both. Obviously, a lot of that has to do with COVID and COVID decreasing demand in 2020, virtually overnight by 25 million barrels a day versus the 100 million barrels a day that pre-COVID levels of oil demand were. You know, the recovery, just like it is in the overall world economy, is unprecedented and it's uncharted waters. You add the war between Russia and Ukraine, and there's just a lot of external variables that are adding a lot of volatility to market. Francisco would know better than I, but volatility is running like 40% for oil, which is at a high level. That reflects this is a different time. When we sort of peel the potato on oil price, I think, you know, in the last three months, the oil price, more than anything, was being determined by high interest rates and the strong dollar. As the dollar rose upward, oil prices went down, along with equities in the financial markets, along with fixed income instruments, and there was no one spared. Any financial asset got hit. You know, as the 10 years come back down, you're starting to see a little bit resilience or improvement in the oil price. I think it bottomed out at about $76 WTI. Now it's about $84. Really we're going into the winter now, and I think there are a lot of uncertainties with that. When you step away from, you know, the paper market being separated from the physical market, at the end of the day, it is a commodity. It has to balance every day. The physical fundamentals of oil are what really matter. Let me just talk a little bit about demand and supply. Demand is a V-shaped recovery. Right now, we see oil demand running at about 100 million barrels a day. It's at pre-COVID levels. In the number, there's probably 300,000-500,000 barrels a day of a drop in China. The country is shut down. I was with someone two days ago who had just spent 75 days there, and he says, "You have no idea." He was in Beijing and he was in Shanghai. He said the country's been ground to a halt. Hotels, people are, you know, virtually empty. There's no tourism. I think we, living over here, when we hear there's a slowdown in China, there's a shutdown in China. Even with that, oil demand is running 100 million barrels a day. When you look at next year, we see demand growing 1 million-1.5 million barrels a day. There are gonna be two drivers to that. About half from China, as China does reopen, and about half from air travel. Chinese aren't traveling, Asians aren't traveling. A lot of the world still wants to get out and travel. We're seeing that certainly in Europe and in the U.S. There's gonna be more of that. We actually see demand next year going up 1 million-1.5 million Barrels a day. You know, obviously, above pre-COVID levels. What's interesting, we're already at pre-COVID levels, and then the two areas that aren't are China and air travel. They're gonna get closer to pre-COVID levels next year. Demand, we see pretty resilient. We talked at dinner about this last night. We're not seeing this recession in the financial markets hit the economy of oil. You know, when oil got gasoline prices to $5 a gallon this summer, a lot of sales in the United States were down at the station 5%-10%. I think most of that's bounced back now. At the end of the day, you know, I'd say V-shape recovery and demand continuing to go up. On the supply side, that's a lot stickier recovering. You know, the supply chain for the oil industry shut down. You all recall April 2020. Basically, the U.S. ran out of storage, the world ran out of storage for oil, so people were chartering VLCCs that used to cost $60,000 a day for $300,000 a day just to put the oil in storage because onshore storage was full. That's been moved through the system as demand has come up, but it did start to build inventories. At the end of the day, you know, whether we look at shale struggling to grow, maybe growing 500,000 barrels a day this year, 500 next year, we don't get to pre-COVID levels for United States production of 13 million a day, probably for the next two or three years. When you look at non-OPEC ex the U.S., of the 10 countries that are in OPEC+ from non-OPEC, nine of them can't meet the benchmarks that are the guidelines that are being set for them. They're underproducing. When you look at OPEC itself, the 10 countries in, you know, the mainstay of OPEC, not the three that are exempted from the guidelines, of those 10 countries, seven can't meet, again, their allocations. You know, the market is struggling to have oil supply keep up with demand. There is literally a structural supply deficit that we say we think is gonna last for several years. What that does to the price forecast remains to be seen, but I agree with what Francisco and Doug have said, you know, $80 is really the new $60. $80 or higher. You know, inflation is part of that too. You're gonna have to spend more money to get the supply that the demand for the market's calling. At the end of the day, it adds up to inventory. Francisco knows this better than anybody. There's a direct correlation between inventories of oil and the price of oil. Right now, as we go into the winter, until we had the third quarter, we had eight quarters where world inventories of oil were drawn down. They're probably about 300 million barrels less than pre-COVID levels. The third quarter was the first build after eight quarters of draws, but we see the fourth quarter actually being a draw of about 1 million barrels a day. You're going into winter, you're not having the SPR anymore. At the end of the day, you know, it's a wild card what Russia's gonna do to the numbers too. How this sort of battle between Janet Yellen saying, "Let's have a price cap," and the Russians saying, you know, "We're gonna either get around it or we're not gonna honor it," how that plays out. We see the market being undersupplied in terms of inventory by about 400 million barrels come the beginning of the year of 2023. That's gonna keep the market tight. There's no cushion in the system in inventory. There's very little spare capacity left. Shale is doing all it can, but we really see a structural supply deficit for the next several years until investment picks up and you start getting supply from really all the above, from shale, from the offshore, deep water, and also from OPEC. That's gonna be a huge investment challenge. Market's tight. It's gonna stay tight. Oh, thank you. Thank you, John. That's a great intro. I think let's try to think about how some of those macro factors will benefit or hurt companies like yours, right? 'Cause my thinking here is obviously in the last two months, the world has changed. We've had OPEC announcing a cut, a very large production cut at $85 a barrel. A modest cut in the $90s, by the way. Let's not forget, because they've cut twice. Right. In September and October. We have the White House sent out a letter saying that they're gonna refill the SPR if WTI drops below $74 a barrel. Essentially, I mean, is this creating two free puts for oil investors? Kind of gonna benefit most companies that have large free cash flows like yours have a growth portfolio? Who's gonna benefit most in the energy sector from this potential? Right. Puts from OPEC retaining control of the market and the White House having to come in and refill the SPR? Okay. I think, you know, what really happened when OPEC cut, I think most members in OPEC were shocked that a cut was even being proposed by Saudi Arabia. This is really Saudi Arabia cutting as opposed to the rest of OPEC. The rest of OPEC obviously was supportive. Some of it, I think, had to do with economics. That was what was said publicly. Right. Because people were worried interest rates going up, strong dollar, recessionary fears, is demand really gonna be hit as the recession in the financial market spills over into the real economy? I think, you know, that was part of the rationale. I think equally as much, if not more so, there was a political motive behind it in Saudi Arabia. That is, you know, for two years, Saudi Arabia was even called a pariah by the United States. Right. They were humiliated, understandably so. Saudi, along with Israel, are our two strongest allies in the Mid East. I think President Biden played that card the wrong way. He insulted MBS, who is the royal Crown Prince and now Prime Minister. Most European leaders, even though they obviously had real issues, as we all do, with what happened with Khashoggi, you know, the European leaders were dealing with him. Biden decided for the first few years not to talk to him. You know, as any of us would be, I think MBS was humiliated, and I think he's had it up to here. I think he was sending a strong signal to Biden and our country that, "Look, you've got to show us respect and then we'll show you respect." I think the motive for the Saudi-led OPEC cut was as much political as it was economic. That's, I think, the first point. I think the other thing is, you know, what's the U.S. doing in all this? Well, when Russia invaded Ukraine, we were afraid of losing maybe 5 million barrels a day. Right. Turned out to be five hundred thousand barrels a day. Easy to see in the rearview mirror. T he market, was illiquid. Prices were shooting up. And, Francisco knows when you have an illiquid market in any commodity, prices can go, you know, vertical. And, I certainly believed and, and suggested to, our administration that we release the SPR. The IEA and the U.S. were only talking sixty million barrels, with the amount of oil we were gonna lose, especially since at that time, world oil inventories were already three hundred million barrels less than pre-COVID levels. It was important that we cool the market down. The release of 240 million barrels basically over the year, 180 coming from the U.S., 1 million barrels a day through September, I think, you know, had a positive effect. Obviously interest rates, I think, have had more of an effect in terms of bringing the price down. At the end of the day, it bought us time. Nobody knew when the Russians invaded Ukraine how long this war would be. It's turned out to be a long one. What the prospects are for how much longer it's gonna be. I think the White House played that one right. At the end of the day, you know, going to countries like, "Let's make an Iran deal. Let's do something with Venezuela," as a way of trying to put more oil in the market instead of coming to producers here, I think they played that one wrong. You know, I've seen ads recently where two years ago Biden said, you know, "Mark my words, no more drilling on federal lands." Now he's saying, "We want more drilling." The U.S. part of the problem here is the lack of an energy policy, and that's sending mixed signals. The takeaway, you know, you say, "Who are the winners here?" You know, look, I think both oil companies and investors are the winners here because what's the biggest challenge that I talked about? More investment in the business. The world needs $500 billion a year of investment globally to grow oil supply to meet demand. We have five years where the global investment in oil and gas has been between $300 billion and $400 billion, way short of that $500 billion. By the way, this number comes from the IEA. That $500 billion, and it includes the inflation effects that we're seeing now, that has got to be spent every year for the next 10 years. Whatever scenario that you talk about the energy transition, more investment's needed, so you're gonna need a higher price to elicit that investment. People that are making that investment are gonna be rewarded, and investors that are investing in companies that make that investment are gonna be rewarded. Very different than five years ago when I came to this conference where people were saying, you know, "Just stop investing in oil. The world and the shale producers are making too much." The coin's on the other side now. We need to invest more, and we need to do it on a sustainable basis to make sure we get a equilibrium price for oil. We think that is probably between $80 and $100 a barrel. Well, maybe I could pick up on that. I wanna ask both of you guys a question, if I may. I'm not meaning to hijack either of these conversations, but Francisco is gonna give us a very thorough view as to where he stands on the commodity over lunch. I do wanna ask you a question, John. You just said you just think oil, or you don't put words in your mouth. Oil will be $80-$100. Right. We all know what the ramifications of how we got there. Perhaps we'll see how the industry responds. On the other hand, Francisco, we still have $25 backwardation in the curve. We asked the audience what they thought the long-term oil price was gonna be. Why is there still such a big disconnect between, if I may, what you're using when you present a $65 revenue line for, you know, the basis of your business, and Francisco, where we sit in terms of BofA's view of the long-term oil price? I'll try. Why is there the backwardation? You know, in fact, I ran into Larry Summers not too long ago. Obviously, he was prescient, almost omniscient, calling inflation when other people were calling it transitory a year and a half ago. He just looked me right in the eye. He's always gathering his data, which is why he's a brilliant economist. He said, "You know, where's oil price going?" That's when oil was, by the way, about $79 a barrel. It was a little easier for me to make a call. I say, "It's gonna be up by the end of the year." He says, "Well, why is the curve so backwardated?" I said, "Larry, the curve in oil is very different than the curve in the Treasury. In the Treasury, there's a real market for 10 years, for five years, for 30 years, and there's a lot of liquidity there of buyers and sellers. In oil, there's very little activity, very little liquidity, very few buyers and sellers, you know, two years from now, five years from now, 10 years from now. If anything, there's more selling pressure in the back of the curve and very few buyers in the back of the curve. Really the real market for oil is the front 12 months, and the rest sort of goes along for the ride. Just by its sheer weight, because more buyers and sellers will probably lay themselves in the front, there's a natural backwardation. Now, obviously, that's also determined by inventories. Remember I said there's a direct correlation between inventories and the oil price? When inventories are low, that's gonna bring up the front. There's very little buying in the back of the curve, and that's the biggest difference between the Treasury market and the oil market, and that's why the market's backwardated. I have people say to me, "Well, the curve's backwardated, so oil's going down." I think those people are shortsighted because the real anchor in the market and the real determinant in the market is the front of the market, whether it's one month, three months or 12 months. Francisco? Yeah, I don't disagree. Obviously, I think the backwardation in the curve, at least in the very front, is purely driven by inventories. When the spot price is trading above the forward, the incentive for market is to pull barrels out of storage. Again, that essentially reflects a deficit, i.e., demand is running ahead of supply. Conversely, in order for the curve to flip into contango, you need to have a surplus in the market, which we haven't had. We've been in a structural deficit, right? This is what the backwardation means, is that we've been in a structural deficit for months and months and months and months. I think OPEC getting control of the market likely keeps structural backwardation more firm than not, right? For OPEC, a backwardated market has the additional benefit that it reduces volatility. Even though volatility is 40%, if we were in contango and the market was kind of dipping down to $50 and $70 a barrel, you would have potentially a lot more backwardation. A lot more volatility, right? I think the market's backwardated because inventories are low and because we have a structural deficit. If we move and we suddenly move into a surplus, which we haven't yet, then we'll go into contango, and I think the back will outperform the front. We'll see the front end coming down sharper than the long-dated prices. I would urge everybody to come listen to Francisco's presentation at lunch because it informs everything we do on the equity team, and I think that's a key thing to listen to. I want just to get back to your shale thoughts there, because it's something that you and I spoke about over lunch a couple of weeks ago. You know, I was very concerned. We said, you know, the shale resource is getting tighter, which is one of the reasons the OPEC group is regaining control of the market. You said, well, you know, exploration spending has collapsed. What happens next? We've seen the U.S. production severely underperforming in the last four months. We're expecting 13 million barrels a day of crude production in the U.S. We're gonna get 12.3. Yeah. I mean, that's a huge gap. You said, "Well, you know, the shale resource, you guys have the biggest acreage in the Bakken." What's going on? Why is shale not able to get this out? We've seen a lot more gas suddenly, more NGLs, but not enough crude. I mean, what's going on in the shale patch? Right. Shale, has gone from a, a growth business to a harvest business. It's very, very mature. It's gone from drill, baby, drill, to show me the money. And I'd say there are three major determinants, I call them three, we call them in the company, three I's, that are really determining the trajectory of growth for shale going forward. The first is investors, the second is inflation, and the third is inventory life, to get to your point about the resource. On investors, o-obviously, a lot of money was lost in shale, by overcapitalizing it. I know some people will say the problem with shale over the last five years wasn't too much oil, it was too much money. It had growth rates that weren't sustainable. It was fed by investors, but it was also fed by the oil companies spending that money or their internal cash flows. Investors, rightfully so, put their foot down and said, "Look, don't put all your money back in the ground. Maybe put 70% back in the ground." Now it's 30% back in the ground with the higher prices, and give me the rest along the way. The free cash flow yields have gone from barely zero to about 10%. At the end of the day, that recalibration and that sort of investor pact have sort of made a sustainable financial proposition for shale producers and shale investors, whether they be Wall Street or private equity, as we go forward. Investor discipline is number one. Number two is inflation. Inflation in the Bakken is probably about 15%. In the Permian, it's probably 20%. Our own company, Greg Hill, who's here, who's our Chief Operating Officer, has a great team that does lean manufacturing, and we've been able to wring out about half the inflation increase. Our cost to drill and complete a well is about $6.8 million. That's about 8.5% up year-on-year. We think that's probably gonna continue next year. You know, when you listen to the different oil service company CEOs, the system's running max out. It's max out in labor, it's max out in equipment, and it really can't go any faster. I think a lot of that had to do with, what did I say before? Supply shock. Supply shock affected the supply chain for drilling, completing, and producing oil and gas. You know, it hasn't gotten back to pre-COVID levels, and, you know, rig count's at about 770. I think before COVID, it had actually peaked at 1,000 rigs. We couldn't even get to 1,000 rigs now. We are maxed out as an industry in terms of being able to go ahead, and the inflation is a reflection of that, and I think that's gonna stay with us. The third one, which I think is the most important, shale is a finite resource. We are not adding to that endowment. The three biggest oil shale plays in the United States, the Bakken, the Eagle Ford, and the Permian. That's sort of it. Yeah, there are some new plays that certain companies are going after, but they're not as material as what's been found already. Basically, it's a liquidating business. It's a liquidating resource. How do you maximize the NPV of that as you go forward? Most companies that you talk to, Doug knows this better than anybody, say they have a 10-year life. Well, you know, some companies have more. We're fortunate. We have a big position in the Bakken at a four rig count, which we're currently running. We have a 15-year inventory. Some other companies in the downturn bought other companies. They have a 15-year inventory. The industry on average has a 10-year inventory. If those companies have multiples on their cash flow or EBITDA of about 5x, what happens if they bring that value forward? Well, that multiple's gonna compress. I think, Francisco, yeah, I'm surprised too that shale hasn't been more resilient in increasing its production. At the end of the day, I'm not surprised that there's sort of a finite life to how more can it grow, and the Saudis and OPEC know this as well as anybody. Yeah. Really, what we're seeing now is at the current rig count this year, oil production is probably gonna be up from shale 500,000 barrels a day in the United States. Next year, 500,000 barrels a day. As you look forward, that rate of growth is probably gonna slow down even more. The system's gonna be maxed out in part of well inventory life in terms of people's ability to go forward. As we see it, U.S. production will probably get back to that 13 million barrels a day that was the pre-COVID level, maybe in the next two-three years, and then it plateaus. Our own production in the Bakken is currently running in the 160,000 barrel a day range. It's projected at a four rig count to go to 200,000 barrels a day equivalent in 2024, and then we see it plateauing. Other shale producers are gonna have the same thing. There's a limited resource, and that's the max that that resource is gonna be able to do. It's gonna grow for a couple years, and then it's gonna flatten out and plateau. I think when people think about the world's need for oil, we're gonna need more than shale. In the past, shale was thought of as a swing producer. The Saudis and the OPEC has waited this out. Now, really, OPEC's back in the driver's seat where they are the swing producer. The problem there is there's not a lot of spare capacity there. You look at the one other area we can go in the world to get increased oil supply, and it's the offshore. Offshore is 30% of world supply. Exploration, and that's the key to finding new resource in the offshore. The fields are bigger. It's riskier to go. It's more expensive. At the end of the day, worldwide exploration, really since 2015-2016, has been running about $30 billion a year. That number really has to be about $50 billion a year. Not only are we under-investing in global oil and gas, that $500 billion versus $300 billion-$400 billion that I talked about, we're also under-investing in exploration, and that's the key to unlocking resources from the offshore, which the industry is starting to do. Obviously, we're very active in that in terms of what we're doing in Guyana. Which is a great segue. If I may, I'm gonna try and turn the conversation a little bit more to the portfolio and use what you've just said to inform how you think about the individual assets. Let's go to the Bakken to kick us off. We'll do a little tour around the world. Okay. If I may, we'll try, and we wanna spend most of our time on Guyana, obviously. You said that you've got a 15-year inventory, and I think what that translates to, if I'm not mistaken, is plateau of 200,000 barrels a day for about 10 years. That's right. When you look at your Bakken, it's gonna do about $1 billion a year of free cash flows, and I guess that's a $65 type oil price environment. When you get to that 200,000 barrels. Right, when you get to the 200. Is a ten-year inventory enough? What do you-- Like, because ultimately, the way you just described it, in 2024, which is two years from now, it's an eight-year inventory. Or it's an eight-year plateau. And by the time phase V of Guyana comes online, it's a four or five-year inventory. So how do you-- you've got extraordinary growth coming from Guyana, which we'll get to in a second, but how do you manage that shrinking visibility in the Bakken? And if you can't handle it, how do- Yeah. Other people deal with it? That was kind of my first one. Well, remember, our number is 15-year inventory. Most other producers are 10, so we have more visibility as we go forward. I don't know how many other companies could say they can plateau at 200,000 barrels a day. For 10 years. For 10 years. Right. That's really starting in 2024. We have visibility out to 2034. Production's not gonna stop in 2034. At that time, then it'll start to go down. You know, the way we run the Bakken is to maximize the net present value of each drilling spacing unit and the overall operation. We have found, and we've run all kinds of cases, that by running four rigs, we're most cost efficient. We also maximize the infrastructure that we have. All of our infrastructure, the pre-investment's been made, our Tioga Gas Plant, our Hess Midstream business. Some people say, "Well, oil's running $80 or $100 a barrel. Why don't you drill faster? Why don't you add a fifth rig, a sixth rig? Right. What we would have to do is invest in a lot more infrastructure, and that would be NPV destructive. We've optimized that, you know, the sustainable rate. Remember, we took our rig count from six rigs pre-COVID to one, just to weather the storm of low oil prices in 2020. We're back at four. Four is the run rate that really optimizes returns, optimizes free cash flow generation, and optimizes the use of the infrastructure, so we don't overcapitalizing the business. That's sort of the sweet spot. It's a cash engine. It provides some growth the next couple of years, and then it's basically an annuity for the next 10 years. 10 years is a long time, let's face it. Sure. Again, in the context of when we think about the buildup of your portfolio, you have Guyana as a big offset. Yeah. A lot of other companies don't. I guess where I'm going with this is that, I mean, Francisco, maybe I'll bring you back into this. When you think longer term about where long-term demand is going, and shale can't get above that 13 million barrel a day production, and you've got some of the best assets in the industry, frankly. Yeah. Because of infrastructure advantage. If you can't grow, what is the challenge? Well, the industry, it's a company-by-company thing, but a lot of companies already have hit the wall. Right. You're seeing that in the third quarter reports where they're missing production targets and they're missing their CapEx. They're overspending. Yeah. I think you're starting to see some cracks in the armor in that regard. I think the other thing that's important here, you talk about the construction of the portfolio. You know, we've worked hard to focus our portfolio to four key assets, the Bakken, Gulf of Mexico, Malaysia, which is a long life gas asset annuity, and Guyana. All four of them are cash producers. They're not using cash. I mean, obviously we spend money in them, but they generate free cash flows. The growth engine by far and large is Guyana first and the Bakken second, potentially the Gulf of Mexico as we go back to drilling there. The key for Hess is where we're investing in the reinvestment rate that we have is at current levels of oil prices is 73%. Most of the industry is 30%. We're putting a lot of money back in the ground. We're doing it at high returns and low costs, which allows us to have a high return on capital to give a higher, more durable return of capital. We're the only company that can grow intrinsic value. At the same time, we're growing cash returns. Shale producers at the current level of reinvestment are giving you cash returns, but they're actually not growing their net asset value. I think that's going to be the struggle for shale companies going forward. Depleting as you do. Yes. How do you keep growing your net asset value, your intrinsic value? It's a limited resource. Each year that you drill, your inventory life gets compressed. What multiple you as investors are gonna put on that? In Hess's case, we're actually growing the resource, which we obviously led by Guyana. We're in a resource business, and our strategy shows that. We wanna grow the resource by investing in high returns. We wanna go down the cost curve. Our cash cost per barrel over the next five years is gonna go down 25% to $9 a barrel. At the end of the day, we're gonna provide industry-leading cash flow growth of about 25% a year at $65 Brent. No shale producer can say that because they're liquidating. Let me jump into that because you've made a lot of statements there about depleting asset value for the traditional shale player. Explain in the simplest terms that you can why the value doesn't deplete in Guyana with time. Well, in Guyana, you know, we're in a resource business, and if you're gonna grow future cash flow, you have to grow your resource. We had our first discovery in Guyana in 2015. Obviously, you probably all know it, but it's over a 6 million acre block. We have 30%. ExxonMobil is the operator, 45%. The China National Offshore Oil Corporation, CNOOC, has 25%. Since then, we've had 29 more discoveries, just nine discoveries this year. Our resource has grown from 1 billion barrels of oil equivalent to 11 billion barrels of oil equivalent, and the nine discoveries this year are not in that resource estimate. There's gonna be an upgrade to that number. Fortunately, these are very low cost barrels. The first four FPSOs that we've authorized have a break even to make a 10% return of a Brent price between $25 and $35 a barrel. It's light crude. It's 32 gravity, 0.5% sulfur. It gets priced at a Brent equivalent price, sometimes a physical premium, sometimes a physical discount, but that's not material. It prices at Brent basically when we sell it at the FPSO. You know, I've always been a company that's, you know, we're in the resource business. I remember going to a different investor conference, and they said the most important thing about oil companies basically going forward is execution. The second thing is capital allocation, and the third is the resource. I take difference with that. The first thing, if you're a resource company, is to grow your resource. Now, obviously, you have to be capital efficient, and obviously you have to be able to execute. If you don't have the right real estate, you're finished right there. What differentiates Hess is we have a growing resource when shale companies don't have a growing resource, and that's led by, you know, the fantastic exploratory results that we've had in Guyana. There's still multi-billion barrels of exploration potential remaining. I guess I wanna try and spell this out for the audience to make sure we're not getting this wrong. It seems to us the scale of the resource has gotten so enormous. Yes. The pace of development so efficient that you're actually recovering, don't wanna put words in your mouth here, but you're recovering the cost of future phases before those phases hit production. Is that the right way to think about it? Yeah, we have what's called a production sharing contract. Production sharing contracts in the industry, you may all know, were really created in 1998 as oil prices were going down to $40 in that price downturn. Basically what it is where the producing countries share the risk of prices going up and down. At the end of the day, if oil prices go down $20 a barrel, you as the investor or contractor investing in the concession get more barrels. As prices go up, you get less barrels. In that way it's, you know, your revenue is fixed in any given year to go against your cost bank. Until that cost bank is depleted, the investor gets more money, and once the cost bank is depleted, then the country gets more money. It's a better risk-sharing agreement, especially for the mega investments. You know, each one of these developments is, you know, between $6 billion and $10 billion gross. That's the FPSO, it's the topsides, it's the drilling, it's the subsea infrastructure. Exxon's the best project manager for mega projects like this. They've done an outstanding job bringing these projects in really ahead of schedule and under budget. At the end of the day, there's a cost advantage because these are big reserves. It's a resource dense area. It's advantage because, you know, the first four ships we did at a low point in the cycle, but also the production sharing contract, 75% of the revenue goes against your cost each year. That's a very tax efficient and cash efficient way for you to recoup your investment. Actually then makes it incentivized to, as you find more resource, to develop more and more reserves. Currently we have four ships that we've authorized, two of which are producing. The combined rate of production on a gross basis there is 360,000 barrels a day or more that we're producing on a gross basis. Payara, which is the third ship, is on track to come on the end of 2023. That's 220,000 barrels a day. Yellowtail, which is the largest ship to date on production, is 250,000 barrels a day. That comes on in 2025, and we're currently going to the government. That's the fourth ship. The fifth ship will be Uaru. That's 250,000 barrels a day. We're putting a field development plan into the government this quarter. Hopefully, we get that approved in the first quarter, and that will come on in 2026. Overall, when you add this all up, we're looking at having the potential for at least six ships to produce over 1.2 million barrels a day production capacity by 2027. To Doug's point, each time a ship comes on for our own company, it's gonna add about at $65 Brent, $1 billion a year of new cash flow. That's one of the enablers of why our cash flow can compound at a growth rate of 25% a year at $65. That's at $65? At $65. You think oil is gonna be $80-$100? Yes. Okay. Just wanted to check. Yes. Well, let's talk about scale for a second then. I hope Francisco says that at lunch. Well, we're looking forward to that because Francisco has this great punch line. I don't put words in your mouth, Francisco. $80 is the new $60. We've kind of stolen that and adopted that as our base case. Let's talk about scale in Guyana. I'd love to get Francisco's perspective as to when you see the kind of growth we think is gonna come out of Guyana, what that does to his year oil balances. Because frankly, I think I'm gonna challenge you a little bit here. I think the numbers are as portrayed by Exxon, yourselves, appear grossly inconsistent with the resource base. 10+ ships seems to be the new base case. Yeah. Why am I wrong? Well, we have actually said it's going to take about 10 ships to develop the discovered resource of 11 billion barrels oil equivalent. With us. I'll take the over on the 11 billion. Right. Yeah, no, that definitely is potential there. In terms of what we can define today, we really have visibility, I think, probably to a seventh ship, potentially an eighth ship. It's just a question of, you know, when we get these projects. Right. Fully engineered and sanctioned where we can give more definition to investors. In terms of giving definition to investors, the six ships with a production capacity of at least 1.2 million barrels a day, 2027, I'd say that's got very low risk of not happening. Let's get to what I think is another whole issue here. Exxon, as Greg will tell us multiple times, they tend to focus on the big stuff, on the hubs. You guys, as I understand it, your partnership with Exxon, you tend to focus on what happens after the big stuff, the sustainability of the production. Why should we not think of these cumulative productions vessels or hubs as cumulative production volumes? In other words, the decline rates are much lower longer term, or at least the plateaus in the projects are much longer. Is that the right way to think about it? Yes. When, you know, we sanction these, you know, we are pretty conservative in our resource estimate to back the ship up. The smaller ships, you know, you need at least 600 million barrels of oil to back them up. The bigger ships, it's like closer to 900 million barrels for Yellowtail, for example. That doesn't include a lot of other exploration prospects that surround or are related to the development, but they're not in the base case. There's a lot, you know, people always talk about tieback to infrastructure in the Gulf of Mexico. There's a lot of tieback potential in Guyana because it's a very resource dense province. Right. Basically, where I'm going with this then is that the visibility doesn't stop at 2027. Yes, that's right. Okay. Can we talk about the deeper resource? The 11 billion barrels, I think there's been, forgive me if I get this wrong, five or so penetrations in the deeper zone. Yeah. Exxon has said that if the deeper zone works, it could potentially double. I think at the time they were saying 10 billion barrels, so that would be 20. Can you give us an update? Yeah, no. What's the confidence level? You know, everybody understands, the majority of production right now comes from the upper Campanian that's at about 15,000 ft of total vertical depth. These are massive sand channels that are very high-quality reservoirs in terms of permeability and porosity, and they're very oil dense, very hydrocarbon rich. What we have found, and actually the number, and fortunately Greg said this last night, is 15 penetrations going to the lower Campanian. They weren't optimally located. In other words, when we were drilling to the 15,000 ft, we could see on seismic there was something at 18, and we saw, oh, geez, you know, there's sand channels down there that very much mirror the sand channels that are 3,000 ft higher, and there's oil in it. We never optimally located that well to drill for the best 18,000 ft target as opposed to the best 15,000 ft target. Fangtooth, in the last 12 months, we drilled and that is at 18,000 ft. It's a little west of Liza, where a lot of the discoveries have been made to underpin the first phase of development and the second. What we found was a very prolific sand channel with oil that in and of itself, we're doing an appraisal well there now to the southeast that has the potential for underpinning a future FPSO. You know, we are finding very large sand channels on seismic that could be very prolific in and of themselves. A lot of our exploration appraisal program the next 18 months is going to try to drill the optimal prospects at 18,000 ft that we've been drilling for the last five years at 15,000 ft. We're very enthusiastic about it. Yes, Exxon in their Investor Day said, you know, Guyana has the potential to double its resource, meaning from the 10 or 11 billion barrels that was already announced. A lot of that is gonna be from deeper horizons. Some of it's gonna be from prospects that are further away. We're gonna be drilling a couple of those in the next six months. Some of them are inboard as well. We're just finding that the more we drill, the more we calibrate seismic, the more we have sophisticated seismic imaging, both we and Exxon, CNOOC, we're actually seeing more potential there. That's why we say even though we've already discovered 11 billion barrels of oil equivalent, there's multi-billion barrels less left, and at the end of the day, it actually has the potential to double. I guess I've got two last questions on Guyana, and then I'd like to ask a wrap-up question, if I may. The two last questions are, first of all, there's been a lot of more volatile oil discovered. I think you sometimes talk about a high-quality oil discovery, but sometimes you say a hydrocarbon discovery, which I think leads folks to think there's a gas story there to some extent. What is the gas development plan? Right. Where do the higher volatile oil developments sit in the queue? Yeah. Our focus in these 30 discoveries and five developments to date is to maximize value, go where the value is, and those are in the oil developments. We actually take the gas. This is very low carbon footprint development because the gas is reinjected. Take the gas that's produced and put it back in the reservoir. That actually increases the recoverability of the resource in place. That, you know, we're trying to go for oily developments first. There have been some discoveries to the southeast that are higher gas in content. We're formulating plans of how to make potentially a development out of that, but that's probably much later in the queue. Really looking at probably near the end of the decade when that would potentially be developed. We're working with the government on that, but it's all about bringing value forward, and that's the oily developments. We haven't really got a chance to go around the rest of the world, so I wanna just ask one big picture question, which is exploration in Guyana has been extraordinarily successful, but it's not the only place you've had success. Right. Gulf of Mexico, you've had a recent discovery, I guess, in Suriname, similar situation. How does the broader exploration portfolio fit with the extraordinary success that you've had in Guyana? Well, remember what I said, the key to our strategy and the key to the oil industry is to grow your resource. You only can do that by exploration. Obviously we have a wonderful opportunity ahead of us still in the Stabroek Block in Guyana, but we also have other blocks, one north in Guyana called Kaieteur, and then two blocks in Suriname called Block 42 and Block 59. 42 and 59, we have 33% interest in both. Shell operates the 42. We're there with Chevron. Exxon operates 59. We're there, Exxon, the operator, and Equinor. You know, we still wanna add to our resource. That's really gonna position the company for the second half of the decade. We just drilled the well in Suriname on Block 42. It's a working petroleum system. It's oil. There's gonna be more appraisal there in the next year. Is it potentially commercial? It needs more appraisal before we can go there. Okay. It's encouraging because the petroleum system's working and it's oil. Right. That differentiates from other discoveries in the area, so we're enthusiastic about that. 59, we're doing seismic work. There are actually some sand channels there that could be prospective again. You know, building on our technical knowledge, operating knowledge, financial knowledge, commercial knowledge of what we have in the Stabroek Block, we're expanding that to Suriname as well. Really on a gross basis, the number of Gulf of Mexico equivalent blocks that we have, you know, is nearly, I think, 2,300 Gulf of Mexico blocks. That's almost the amount of blocks that are licensed to oil companies in the entire Gulf of Mexico. The exposure, the real estate exposure we have is massive, so there's more running room and exploration. Remember what I said, key to growing the world's global endowment of resources for oil and gas is staying in the exploration business. Hess, you know, definitely has visibility of future opportunities both in Guyana and in Suriname. Another place is the Gulf of Mexico. We have four major hubs in the Gulf of Mexico producing. We have not been spending money there to explore, obviously, during low prices and during COVID. We're bringing a rig in theater in 2023, where we'll probably do two tiebacks to infrastructure and one well that Doug is referring to. We had a discovery in Huron. By the way, Chevron and Shell are our partners there. We have 40%. They each have 30%. We're gonna be drilling a offset well there on another structure that we think could be attractive. The seismic imaging, sophisticated technology really unearthed this opportunity, so we're gonna be drilling that hopefully in 2023. You know, when everybody was going to the Permian over the last six or seven years, we kept looking at things, and they really didn't compete for capital. Where we saw better opportunities to make our shareholders money was in exploration, not just in Guyana and Suriname, but also in the Gulf. I've got a follow-up in a second. Over a five-year period, we bought 60 blocks for about $120 million. Some of them are tieback blocks, some of them are Miocene blocks, some of them are Cretaceous blocks, so that gives us running room there. Next year, we're actually in Newfoundland offshore going to be drilling a very large exploration prospect with BP as the operator. Chevron's our partner. We're staying in the exploration business. It's very disciplined, but we do a lot of technological work. It's really focused on the western side of the Atlantic margin that's oil-prone, with fiscal regimes where you can make a return if you find something, and it's an area where we have operating capability to explore, develop, and produce. The problem is you've got too much in your portfolio to talk about in the time that we have allocated. John, thank you from me. Francisco has got one wrap-up question, I think. Yeah, I have one question. Obviously, we talked about it earlier, exploration's come down very hard for the industry. You guys have continued to explore and develop at Hess. As we look into 2030s and 2040, right? Demand for oil is still gonna be there. Yes, we're gonna decarbonize, but there's gonna be a decarbonization that includes, obviously, carbon capture and storage and other technologies. How does that fit in your mind, the build between supply and demand into the 2030s and 2040s, and how are you positioned for that? It's a great question. Look, we're informed, when you take a longer view, I think the best resource to give you a feel for what scenarios to look at are the International Energy Agency. They just came out with their World Energy Outlook that they come out with every fall. There's three scenarios there. Stated Policies, basically stay the course where we are. Announced Pledges, which are a lot of the pledges, both of countries and companies, to reduce their carbon footprint. Net Zero, which created a lot of controversy last year where everybody said, you know, no more developments in oil and gas. As Fatih Birol has made very clear, it's not a forecast, it's a scenario. I think, Francisco, when you do the analysis of those scenarios, I think, as Fatih Birol says, there's a very narrow pathway to get to net zero, which is his way of saying it's highly improbable. It's something that I think, you know, both government and business leaders need to get common ground on, that while we need to decarbonize, the world is gonna grow from 8 billion people currently to 9 billion people, it's projected, in 2040. Oil and gas are gonna be needed for decades to come. The biggest challenge, as I said before, is we need more investment in oil and gas. What we need in clean energies is to go from about $1.5 trillion a year to $3 trillion-$4 trillion a year. With higher real interest rates, how's that gonna happen? I think at the end of the day, both the United States and countries overall, you know, we just had Sharm el-Sheikh COP27, need to get a dose of reality that we need to invest more in oil and gas to have an affordable, just, and secure energy transition, but we also need to invest more in clean energies. It's not either/or, it's and. It's a balanced approach, but it's a huge mountain to climb. If we don't invest enough in oil and gas, we're gonna have a very expensive energy transition, and I think we need a dose of reality. I think in many ways, what's happened in Russia is shining a light on energy security and how we go about an orderly energy transition. John, it's been extraordinarily fun to watch the evolution of the business the last few years. Congratulations. Thank you for being here. Thanks for your support. Doug and Francisco, I have a lot of time for listening to you at lunch today. Thank you.