Good morning, welcome to day two of JP Morgan's Energy Conference, held virtually. My name is Arun Jayaram, I'm the E&P and Oilfield Service Analyst at JP Morgan. We're thrilled to have Hess lead off day two with a fireside chat with the senior executive management team led by CEO John Hess, COO Greg Hill, and CFO John Rielly. John has led the Fortune 500 company through a strategic transformation from an integrated oil company into a pure-play E&P company. This company has one of the best 10-year outlooks in our space, which could be a decade of production, cash flow, and free cash flow in a company that I think is on the cusp, perhaps sooner than you think, in terms of increasing its cash return to shareholders, given their world-class position in Guyana, as well as some of their cash engines in the Bakken, the Gulf of Mexico and Southeast Asia. With that, we'll go ahead and start this morning with a moderated fireside chat. John, how are you, sir? Very good, everyone. Thanks for that introduction. Really appreciate it. Great. Well, John, any discussion with you, I always like to start with the macro just because you have a unique lens having a global footprint and a lot of years in this, and obviously, you have a lot of interesting contacts in the Middle East, et cetera. I want to get your thoughts on the oil macro, including your thoughts on the supply-demand conditions and potential supply threats from Iran and U.S. shale. No, thank you. We really look at the oil market outlook through three lenses, obviously, demand, supply, and inventories. Demand we see as a V-shaped recovery, where demand for global oil was running at about 95 million barrels a day in early May. We think that number is closer to 97 million barrels a day right now, and we actually see it potentially touching 100 million barrels a day before the end of the year. Two major drivers, mobility data, be it driving or flying, is obviously accelerating. U.S., China, Europe not far behind as the economies open up this summer. I think there's just this underlying force that's a tailwind that really is helping us in terms of the global stimulus programs and accommodative monetary policies across the world that's turbocharging the consumer in spending, that's turbocharging GDP growth, probably exceeding initial expectations for this year and ultimately oil demand. The economy's running hotter than expected, and this is a good thing as we recover from COVID. On supply, it's a U-shaped recovery, a lot stickier. Shale, you talked about. I'd say a fairly tempered response by shale producers to the higher oil prices. The rig count is moderately going up, but in a very tempered manner at 470 right now in the United States. Even if that rig count got to 600 and shale growth started to accelerate, let's say, to 500,000 barrels a day, I don't think you'd get to the pre-COVID demand level or supply level in the U.S. of 13 million a day for the next four years. I think shale has got a very different role going forward. Instead of it being a growth industry, it's a harvest industry. It's going to have very moderate oil production growth as we see it going forward. A lot of that comes from the shale discipline exercised by investors and oil companies alike. OPEC, I think, has done a great job managing the oil market, definitely the drivers, led by Saudi Arabia, keeping an eye at how fast to accelerate their excess capacity in the market. Ultimately, what that means is inventories are well on their way to pre-COVID levels. Where there was a 1,100 million barrel overhang April a year ago, and 550 million barrels at the end of December, OECD itself, and those were global numbers I talked about, is already at pre-COVID levels, and the world will probably be at pre-COVID levels when you add China in as you get through the summer. I'd say it's a very constructive outlook in terms of the oil market as we go to the second half of the year. John, just a follow-up there. I did a fireside chat with the CEO of SLB, obviously a large integrated oil service company, with my new role. He believes, Olivier believes that we may be entering a super cycle for energy. I want to get your quick perspective on that. Yeah. Look, when you have a super cycle and you have inflation, it's very much led by demand. This is a demand-led recovery. I do think we are in a commodity bull market. I think the lack of investment that we've had for several years at not growing capacity, where demand is running very, very hot right now. I think this super cycle is going to stay with us for a couple of years, and we are in a new era. I think an interesting point, Arun, is a lot of controversies come out about the net zero scenario. You overlay that on a super cycle, and you almost have conflicting forces here. The IEA, I think was under a lot of pressure to come out with this net zero scenario with 70 countries making pledges to net zero and really wanted to show what the consequences of that would be and that there are 400 milestones that have to be met for us to get to net zero by 2050. I think there's a lot of misunderstanding about it because it's a scenario. They have a stated policy scenario, they have a sustainable development scenario, which is really to meet the Paris Agreement, and now they have a net zero scenario. A lot of people thought that was a forecast that no more investment on new oil fields and gas fields would be needed. It's just a scenario that if demand were destroyed, what would the consequences be on supply. I think a couple of interesting points. To make that scenario work, electric vehicles have to go from 5% today to 60% in 2030. In 2040, all the world's electric generation would have to be carbon free, obviously, including carbon capture and sequestration. One other key milestone, investment in energy globally has to go from $2 trillion to $5 trillion, and 90% of that has to be on clean energy. The point here is we have a very narrow pathway to get to net zero, and consumers, governments, businesses alike have to put that filter in how they think about it. At the end of the day, in any case, and we have a page on this in our presentation. When you look at the investment challenge ahead, and a lot of this is about the investment challenge, not just the demand that's leading the investment challenge to have supply to keep up with demand. If you looked at the sustainable development scenario, you would need to invest $450 billion a year to grow oil and gas supply globally to meet demand. If you had the net zero scenario, you'd have to invest $365 billion each year the next 10 years to meet global oil and gas demand. The point is, oil and gas are going to be here the next 10 years, the next 20 years. The question is, what's the demand going to be and what supply do you need to meet it? I think that's where our company's very, very well positioned because the key to this, if you're an E&P company or a major integrated, is to have a low cost of supply. Our low cost of supply, as we get to mid-decade, will be at $40 Brent. One of the lowest break evens in the industry. A lot of issues out there. The super cycle being one of them, and the short end on demand meeting supply. Longer term, what will demand be? We don't see peak oil demand for the next 10 years. A lot of people are saying five years. We'll see where that goes. A lot of it has to do with, do we have the breakthroughs in technology to meet the emission reduction target that some of the governments are asking for? A lot of uncertainties, but in all of that, when you look through it, we think there is still a very good outlook for oil, and oil is going to be needed 10 and 20 years from now. The key is having a low cost of supply, which we have. Great, John. Thanks. I wanted to switch gears and talk a little bit about capital allocation. How are you thinking about capital allocation over the back half of 2021 and as we get into 2022? Yeah, John Rielly. The strong commodity prices have obviously helped us this year with the kind of the investment period ending here for phase II on Guyana. We know we have phase II starting up in early 2022. For the back half of this year, what it really means is our strategy is unchanged, but the prices obviously have helped us. The first thing that we've always talked about that we want to do with our free cash is to pay down our billion-dollar term loan. What we are looking at now, we're giving strong consideration here to begin paying that term loan down here in the second half. That's something you can look forward to as we progress throughout the year. As far as the higher prices changing anything we're doing on capital, no real changes. The only thing again, that we're giving strong consideration to is adding a third rig in the Bakken as we move into the fourth quarter. There could be some capital allocated there. As we go into 2022, phase II starts up, and that's a 220,000 barrel a day ship. If I can just do approximations, with our working interest, you get approximately 60,000 barrels a day when it's fully up and running. On an annual basis, when it's up and running, you're getting 21.9 million barrels of production coming our way. People can put in different price points as they have, but if it's a $60 Brent and a $10 cash cost, you're looking at over $1 billion of additional cash flow coming into the portfolio under that scenario. What we would do in that case is be able to finish paying off our term loan during that year. What would happen is, we've always said we want that balance sheet to get under a 2x debt to EBITDAX. That would happen with phase II coming on and that term loan being paid off. The balance sheet would be in very good shape. From there, that's when the next thing with the excess cash flow would go to increasing the dividend. We want to begin to increase the dividend, have a dividend yield better than the S&P. From that standpoint, a little more risk in our industry. Guyana with our FPSO. I mentioned phase II but obviously you have Payara coming on in 2024. We're looking to hopefully sanction with the government, the Yellowtail, at the end of this year, that'd be 2025. You're getting, again, this $1 billion of cash flow under those scenarios with each one, with each boat coming in. With that, we'd increase the dividend first, and then as additional free cash flow comes in, we would then return. Again, we've always said we'll return the majority of that to shareholders through basically opportunistic share repurchase at that time or special dividends. Again, our capital allocation, our strategy is unchanged. We're going to be focused. About 80% of our capital is going to Guyana and Bakken. That's where our focus is going to be. At the end of 2022, if prices are still strong and Bakken's generating cash, we may add that fourth rig, again, probably in the fourth quarter of 2022. Everything else, though, is exactly as the strategy we've outlined. John, just a quick follow-up. This year, I believe you're spending $1.9. I know you don't have an approved board budget, but just can you maybe walk investors through kind of next year, you obviously have the program largely planned in Guyana, right? With that third rig, give me a ballpark on CapEx. Okay. All else being equal. Ballpark, I always say, Arun, please don't write this in permanent ink because we don't have the approval. We're still going through all the process stuff. We add a rig in the Bakken. That's going to add approximately $200 million to the budget when you add that rig for next year, that third rig. In Guyana, the development budget was at 1.9 was $780 million this year. We think that budget will be around $1 billion next year. Again, nothing exactly fixed yet, but somewhere in that billion-dollar level. You're going to get around for the Bakken $200, in Guyana. We do want to get back to work in the Gulf of Mexico. We had a very minimal program this year, $35 million of capital in it, and we do want to start doing some tiebacks and look at also at potential greenfield. That's something else that could add it. We've always said the Gulf of Mexico would be around $150 million, something like that when we get back up and running. You can see another $100 million going into the Gulf of Mexico as well. Great. My next topic, I want to talk a little bit about the balance sheet and get John Hess to talk a little bit about how him and the board are thinking about cash return. You outlined maybe potentially looking at the dividend next year, but I want to get his thoughts longer term. Let me start with the first one would be the free cash flow inflection point. At the bottom, we were thinking maybe 2024 when things were pre-vaccine, but obviously things have changed pretty materially since the vaccine announcement. Any ballpark timing in terms of free cash flow inflection point for the company? Well, obviously, Arun, that ties to the oil price. John has always said with where prices looked a year ago, that inflection to pay off the debt would probably be closer to 2023 or 2024. It's looking closer to 2022, and maybe even starting this year for some of it. Once we get the debt to EBITDAX down to under two, as well as the debt of the term loan of $1 billion paid off, it's just a function of where oil prices are and CapEx is. In the latter half of 2022, hopefully we'll be in a position to start thinking about cash returns to our shareholders. Again, the first, second, and third priority after the debt's paid off is to strengthen the base dividend. Great. John, just bigger picture, how are you thinking about when you get three, four, five phases of Guyana online, maybe a high-class problem, how are you thinking about different cash return mechanisms? As you know, the latest flavor has been variable dividends just given the cyclicality. I know you guys have historically bought back stock, where are you and the board, where's the puck moving in terms of cash returns? Yeah. We haven't made those decisions yet. The most important thing is we want to strengthen the base dividend. We've talked to a number of our shareholders. That's the greatest sign of confidence about the durability of our cash flow that we can give. When there are excesses on top of that, depending upon the stock price at the time, we may do opportunistic share repurchases, we may do variable dividends. We don't know where the tax regime in the United States is going to go for investors as well. It'll be a variable return for sure on top of that base going up, and market conditions at the time will determine do we do a share repurchase opportunistically, or do we do an increase in a special dividend, as John said. The point is, our cash flow growth is superior to any of our peers. We have a page 19 in our investor pack that shows using third-party estimates, including yours, out to 2023, our cash flow growth is 38% a year. I think our peers' median is about 21%. We're superior as well in cash flow growth up to 2023 to the S&P. I think the rate of change story for our cash flow is industry-leading, S&P leading. I also think the durability of our cash flow growth is something that differentiates us, where we have line of sight not to cash flow growth of 20% a year to 2025, 2026. We really have it extended out to the end of the decade because basically we're looking at a line of sight for 10 FPSOs in Guyana. We have the oil discovered resource to underpin that. We also have the definition for six or seven FPSOs already with our exploration and appraisal program. This cash flow growth of 20% a year, even though our production is growing 10% a year, and that's an output, the real point, our cash flow is growing at twice the rate of our top line. Any business that does that you want to have. The fact that we have line of sight to extend that into the end of the decade is something that I think should be attractive to all investors. Great. A good segue into our next topic to talk about the broader portfolio. Start with Guyana. Greg, let me start with you. A week or two ago, Exxon and the Hess Consortium came out with some updated drilling exploration appraisal results. Can you maybe provide an update on some of the key takeaways from that announcement? Yeah, you bet. Thanks, Arun, for the question. There was actually an update on three wells. It really kind of dovetails with our three objectives on the block this year in terms of exploration and appraisal. First and foremost, our first objective on the block this year was to appraise some existing discoveries such that we could define the cadence and the order of future development. Phase IV obviously going to be Yellowtail, fourth development on the block. The question is, what's five and what's six and potentially seven? We appraised Longtail with a well called Longtail-3, and basically what it confirmed was the large areal extent of Longtail and also the vertical extent of Longtail as well. This is a very large reservoir system. Static pressures tend to indicate good connectivity as well. We'll do a DST later in the year to confirm that, but basically confirms that this is a very large reservoir system at Longtail. Clearly that's going to be in the development queue. The second well that we announced was Mako-2, which also was appraising Mako. That's very significant because it showed that the Mako-Uaru complex. If you look on page 12 of our investor pack, we kind of zoom in on that, and you can see that the Uaru-Mako areas is tucked between Yellowtail and Liza. Very oily, very good area. That would tend to indicate that potentially Uaru-Mako is going to be vessel number five. It would probably jump the queue ahead of Longtail. We haven't made that decision yet, certainly based on the crude quality and the size of the reservoirs and all that, it's more likely to be boat number five. The third thing that we announced was a well called Koebi. It was sort of an outstep a little bit further out into the basin in the upper Campanian. It showed hydrocarbons through the well it wasn't in commercial quantity. Now as we go forward, the second objective that we have is two-fold. The second and third objective, really, the second objective is to continue to explore a number of Campanian prospects on the block, the third objective is to get some more penetrations in the Santonian. The first well, the next well that we're actually on right now is a well called Whiptail. Whiptail on seismic, very large channel system. It's east of Yellowtail and west of Uaru, again, in a very oily kind of province. Obviously, if that's successful that could potentially be boat six. It could, again, displace Longtail because it's got, we think, very similar kind of crude qualities. That's going to be a key well. Behind that is a well called Cataback, another Campanian prospect. There's a well called Pinktail this year that's another Campanian prospect. There's one called Fangtooth that's more of a deeper kind of play that's coming up in the queue this year. After all this, by the end of the year, not only will we have a lot of those Campanian prospects prosecuted, and there's more to come beyond that. I don't want to imply we're done. There's a lot more to come. We'll also have five more deep penetrations in the lower Campanian, upper Santonian as a result of that drilling program. Again, very active space. We'll define a lot of the future vessels this year. We'll get more Campanian prospects, and we'll get more penetrations in the deeper Santonian and upper Campanian. Great. Thanks for that. That's a great rundown. Before talking a little bit about some of the development work, John, I want to get your perspective on your thoughts on the regulatory and fiscal regime and stability in Guyana post the election. It's been some time now, but I just want to get your thoughts on that. Yeah, the PPP Party, the Indian Guyanese party, took over as the ruling government administration last August. I have met personally with President Ali, Vice President Jagdeo, and their cabinet actually in Georgetown in May. I would say very clear that they're very pro-business, very pro accelerating investment in the oil industry to build shared economic prosperity for each Guyanese citizen. Very clear that they will honor the production sharing contract, I'd say very encouraging about us moving forward with getting approval for the Yellowtail development before the end of the year. I'd say a very supportive government in terms of encouraging more investment, but also a government that wants to make sure they have environmental regulations as well to ensure a cleaner future for their country as well. Very pragmatic and an excellent working relationship with our joint venture. ExxonMobil is the operator, but Hess is obviously an active partner in that, and we're very encouraged by what we're hearing and what we're seeing from the current government. Great. I wanted to talk a little bit about development. John Rielly mentioned phase II looking like early next year. Can you give us, maybe Greg, is maybe the timeline for Payara, and then let's assume that you get a plan of development submitted at Yellowtail by year-end. What are your thoughts on the timeline beyond Liza phase II? Yeah. Payara, again, on track for 2024 startup. Payara running just slightly ahead of schedule right now. It's early in the project cycle, so I wouldn't necessarily count on that, but firmly on track for that 2024 startup. If you assume Yellowtail gets sanctioned by the end of the year, then you'd be on track for a mid, call it July 1st, 2025 startup for Yellowtail. Again, it will be on this cadence of one a year, as soon as Payara comes on, then Yellowtail's one year later, et cetera. Okay. Yeah. Okay. Again, more appraisal work, but sounds like Mako-Uaru could be the next phase beyond Yellowtail, we'll see. Phase VI, you'll see based on oil quality, all the other parameters that you look at. I know that the Hess Exxon consortium put out some numbers around the productive capacity. We're obviously at around 120 today. Greg, again, maybe you could kind of build up through the first six phases of this, how that will move. Sure. I think first of all, let's talk about phase I first. It's operating a nameplate right now, around 120,000 barrels a day. The flash gas compressor is on the vessel. It's being performance tested as we speak. When that comes on and is fully up, hopefully during the month of July, then you'll pick up another 10,000 barrels a day or so. Maybe 130 or so is what you'd be operating at at that point. The flash gas compressor is important because it allows you to get the flares out, right? The next key milestone for phase I is in November, we take a two-week shutdown to do two things, debottleneck some piping, et cetera, and then also install a brand new flash gas compressor. After that, you can expect the new nameplate to rise to somewhere between 140 and 150, in that range for phase I. As I look at future phases, which is what's pretty typical for these projects is you'll get a year's worth of operating data, and you'll figure out where are the pinch points, where can I get more out of this vessel. I would expect that every one of these would have an optimization project or a debottlenecking project designed and engineered a year after kind of some operating experience. That's really important, Arun, because you need the actual dynamic data of the vessel operating on the water before you can figure out how to debottleneck, right? I would expect that each one of these vessels will have some sort of optimization project associated with them. Kind of round numbers, you can usually always count on 10%-15%, just based on my experience. I think that's kind of a good number. 220 maybe goes to 240. Yellowtail, because it's such a very large resource, we're looking at the vessel coming out of design. Somewhere in the 220- 250 range coming out of the shipyard. Right? Okay. Decision hasn't been made, but there's a big enough resource there that you could upsize that vessel a little bit. We're looking at that range of 220 to 250. When you helicopter down, you can say five ships, 2025. Yeah. Producing in excess of 1 million barrels a day. That number used to be scoped at about 750,000 barrels a day. That gives you some feel about the quality of the reserves, but also the producibility of the wells. Yeah. Exxon has talked about that in their investor presentation. I think having capacity maybe even nearing 1,200,000 barrels a day. Let's say 1 million to 1,200,000 barrels a day for those five ships. Great. We're running out of time here, so I've just got two quick questions I want to get to. Just to pass, so you're at 120 today. You'll complete the repairs on the discharge silencer, so you could be at 130, call it in the third quarter, something like that. Yeah, sure. Deb ottlenecking project could get you potentially 140-150. Yeah, somewhere in that range. Yeah. Okay. I want to switch gears quickly to the Bakken. I don't want to forget about that as it's important to the portfolio. What does the third rig do for you, Greg, and potentially a fourth rig as John Rielly mentioned, late in 2022? Well, first of all, Arun, as you know, in our investor pack, we show the inventory at various oil prices for the Bakken. At $60, we've got 2,200 wells left in our inventory to drill in the Bakken that generate good returns. Part of the logic of adding the third rig was really, get after that inventory, right? Very good profitability, particularly at current prices, good returns. Let's go ahead and start going into that inventory. That'll get you to a new plateau level. We'll give the guidance in January like we always do as to what the Bakken will be next year. That, as John Rielly mentioned, that begins to set you up. You won't quite make it to 200,000 barrels a day with the third rig. You really need the fourth rig to get you to 200,000 barrels a day. Why is that an important milestone for the Bakken? Remember, we built infrastructure for 200,000 barrels a day before the downturn. What we'd like to do is eventually get back there. It'll be a function of crude price and corporate cash flow needs is when that is. We'd like to get back to that 200 to maximize utilization of that infrastructure. That's really the efficient frontier for the Bakken, if you will, to kind of be around that 200,000. I think significantly, Arun, at call it $60 WTI, when the Bakken's operating around 200,000 barrels a day, it generates somewhere between $850 million and $1 billion of free cash flow every year. With that inventory, we can hold that level for almost a decade. You see this Bakken becomes this massive cash generator for the company, pretty much an annuity, in that $850-$1 billion a year at $60. That's a nice attribute that we want to maintain for the Bakken, right? Great. Hey, John, we're out of time. Thank you for your team for supporting our conference. John, you've been here, I think since we started. Personal thanks to you and the team for being great supporters of the conference. I think it's all my questions. Again, I really appreciate getting us off to a great start on day two of the conference. Arun, thanks for hosting us. We're honored to be part of the conference, and thank you for your hard work and interest in our company as well. Thanks for the opportunity to speak to your investors. Thank you. Thank you.