Good afternoon, welcome to the next session of Citi's Global Energy Conference. It gives me great pleasure to introduce the management team from Hess, especially given Hess's truly differentiated story within the E&P sector. With us today we have John Hess, CEO. We have Greg Hill, COO. We have John Rielly, CFO. On the Citi side, I'm joined by my colleague, Oksana Khariv, who helps me on the large cap E&Ps. Hess team, thanks for being with us today. Thanks, Scott. Thanks for having us. Now, similar to previous sessions, if you'd like to ask a question of the team, you can submit those via the question submission box, which you can find in the top left of your viewer, or you can simply email me at scott.gruber@citi.com. With that, John, I think we begin. You always offer some very interesting and salient comments on the macro backdrop every time we get together. Given how in flux things are today, wanted to start on the macro, get your latest thoughts and how that influences the Hess strategies today. Sure. Thank you, Scott. Thanks for your interest and support of the company, and thanks for making the time for us today. On the macro, the market's been in a rebalancing or recovery mode really since last April. I think there are three major things to look at, three factors. One is demand, one supply, and obviously the third is inventories. On the demand side, we see a V-shaped recovery, about 95 million barrels a day right now. We have been in recovery since last April when we were down 25 million barrels a day. Now we're down 5 million barrels a day versus pre-COVID levels. Looking forward the next several months, while there are headwinds from India, the U.S. and China growth is accelerating as the vaccines roll out. More people are starting to fly. More people are starting to drive. The economy is reopening. Warmer weather does make a difference. Remember last year, really in November, oil was $40 a barrel for WTI, and now it's $64. On supply, we see a U-shaped recovery, a little different than demand. It's a lot stickier. If you just look at shale, the U.S. rig count now is about 448. While it's up 20% versus a year ago, it's still down versus 18 months ago, where it was in the 1,000 range. At these levels, we see U.S. crude maybe growing 100,000-200,000 barrels a day by the end of the year. U.S. crude production is currently 10.9 million barrels a day, down about 2 million barrels a day before pre-COVID levels in December 2019 of 12.9 million barrels a day. If you assume the rig count going up to, let's say, 500, maybe it grows 200,000-300,000 a day. If it went to 600, you're talking 500,000- 600,000 a day. I think the key point here, shale's role going forward is going to be very different. It's not going to be the swing producer. It's not going to be the marginal supplier. It's going to have a backseat to OPEC. Certainly will provide oil when the market calls for it. Shale, we think, has entered a new phase. Where it was a growth business, now it's a harvest business. While there's still more oil to exploit, it's going to be done in a much more financially disciplined manner. You see a lot of people that are in the shale play right now are talking about keeping production flat or low single-digit growth, really focus their cash flow going to debt paydown. I think that discipline's going to stay for the year. I think that bodes well for the market rebalancing. OPEC is back in the driver's seat. The market is being led by OPEC, led by Saudi Arabia. The fact that they're easing in another 2 million barrels a day in a phased manner, May, June, and July, I think that 2 million barrels a day between Saudi and the rest of OPEC/OPEC+ compares to demand growth probably about 3 million barrels a day in that period. We're going to continue to be in deficit where demand's greater than supply. Basically, that gets to the third factor, Scott, which is inventories. Inventories a year ago April had 1.1 million barrels of excess surplus. By the end of the year, that overhang was 550 million barrels. We think by the middle of this summer, the market gets back into balance in terms of inventory. What we see going forward are three major wild cards. I call them the three I's: inflation, investment, and Iran. On inflation, the stimulus programs across the world, but also in the U.S., the fiscal programs, the most recent one, the $1.9 trillion that the Biden administration pushed through, remains to be seen if there's another $4 trillion to follow on the American Jobs Act, American Family Act. The fact of the matter is, this is a major stimulus to the economy. The accommodative monetary policies from the central banks, including the Fed, all are underpinning, turbocharging the consumer, putting money in the consumer hands. GDP going up pretty robustly, oil demand being underpinned really going out into next year. We don't see peak oil coming, certainly for the next five years. We actually don't think it happens. Even though the rate of growth may temper, we don't see peak oil come until, let's say, 2030. I know some people think maybe it's 2025, but the point is, we still see demand for oil being pretty robust going out, even with the ESG and government pressures that are out there on climate change. Oil and gas is still a strategic industry, not only for the United States, but for the world to get the economy back on its feet. On the demand side, we see pretty strong support going into next year. On the second eye investment, last year, the world's oil and gas industry spent about $300 billion. The IEA makes pretty clear in their World Energy Outlook that they come out with every year, that the world, even with all the push on reducing the carbon footprint, oil and gas are needed to run the world's economy. Basically, you're talking about $500 billion-$600 billion needed to grow global oil and gas production to keep up with demand growth over the next several years. It's important to know that the last five years, we've actually undershot that number between $300 billion and $450 billion a year. We think the market now is getting rebalanced on inventory and more investment is going to be needed to grow global oil and gas supply to keep up with demand. Last but not least is Iran. Obviously this is a political issue. Iran has about 2 million barrels a day, a surplus, that could come on the market. We think about 750 of that already is leaking on the market. The key is going to be how the negotiation on the JCPOA goes between the U.S. and Iran. There are talks going on perpetually in Vienna. Right now, each country is asking the other to go first. It remains to be seen, does the U.S. drop the sanctions first? Does Iran stop increasing uranium enrichment first? That's the art of the deal, obviously. It remains to be seen what that does to the sanctions and what that does to Iran's ability to bring more oil on the market. Quite frankly, I think that oil, the further out in time we go, can be absorbed with rebalancing the market that I talked about. What does this all mean, Scott? I think it means a much more constructive environment, not only for this year, but next year in terms of oil price, which will work for consumers, but work for producers and hopefully incentivize more investment. I know that's contrary to what a lot of people have talked about the last five years, which is stop investment, stop making too much oil. Well, COVID brought the industry to its knees, and now with that rebalancing, I think the market now is going to elicit more supply, first from OPEC, then also from Shale, and then also from longer cycle projects such as what we have in Guyana. That's great, John. Very interesting and a great start to our conversation. Starting with your crown jewel down in Guyana, just some high-level thoughts. You mentioned not seeing peak demand in 2025 for oil products, potentially 2030, we'll see. Is there any impact on the strategy around how you develop the long-lived resources down in Guyana? It's a huge resource base, a lot of potential there, and you're still very active on the exploration side. Is there any impact, you know, from the discussion around energy transition? Or is this just such a low-cost resource, you'll plow ahead in the most efficient fashion? Yeah. I think you obviously have to have a longer-term macro view about oil. Another point, and I think a great resource, to try to reconcile the need for more oil and gas and more energy in the next 20 years, about 20% more, and yet we have to get to net zero in the next 30 years. How do you reconcile those two objectives? The IEA, the International Energy Agency, has a sustainable development scenario in their World Energy Outlook that assumes all the pledges of the Paris Agreement are met. We're totally supportive of the move to get to net zero and the global ambition to get there, as well as the aim of the Paris Agreement. Ultimately, it'll probably be the Glasgow Climate Pact. When you look at the sustainable development scenario that even if all the pledges of the Paris Agreement were met, oil and gas will still be 46% of the mix in 2040. The oil and gas is going to be needed 20 years from now. It may be less oil than what we're currently demanding or supplying, but there's still going to be a pretty good need for that oil. What's your strategy with that? To be a low-cost producer. Obviously we have built our investment profile to be a low cost of supply, where our break-even goes to $40 Brent by mid-decade. Other barrels are going to be pushed out before ours. It's also important, we're in a resource business, that we grow our resource in a capital discipline manner, investing only in high return, low cost, opportunities. In all of this, Scott, what we're trying to do is build a company and a portfolio that can deliver durable cash flow. I was at an investor conference as an investor not too long ago, and they said, "We want companies." They were talking about all the companies in the S&P. "We want companies that can provide durable cash flow." What does that mean? Sustainable cash flow growth, sustainable free cash flow growth. We're uniquely positioned, differentiated, as you were kind enough to point out, where we can deliver that cash flow growth. In page 19 of our investor pack, we actually talk about third-party estimates, whether it's on revenue, volumes, and/or costs and capital, what our cash flow growth is to 2023. It's 38% compounded. The median of our peers is about 18%, and also that 38% is industry-leading when you compare us to the various sectors of the S&P. That's what really differentiates us, that we can grow our resource, at the same time, we can grow our cash flow and free cash flow. Most major oil companies, Rystad did a story, are in liquidation because they're not growing their resource. The business isn't getting enough investment to do that. They can generate cash, but they can't really grow. A lot of the shale producers either can grow and not generate free cash, or generate free cash and not grow. We're the one company that can grow, and generate free cash. That's really what's differentiating for us. With that, we're very comfortable making our investment in Guyana, to get to your point. By the way, when we talk short cycle and long cycle, our long cycle investment in Guyana isn't so long. It's about three years before we get payout for each of our ships and each of our developments. That's getting your money and bringing value back very quickly. When you look at it, we feel very comfortable making our investments. Guyana goes from a cash user to a cash generator once we get that second ship on in 2022, where we're going to get about $1 billion a year more of cash flow to add to what we have. That's part of the catalyst for our cash flow compounding that I talked about. Guyana's the world-class investment. Largest oil and gas discovery in the last 20 years. Best returns in the business. We have a 30% interest there. ExxonMobil is our operator. We're also with CNOOC. 18 discoveries to date. Over nine billion barrels of oil equivalent discovered. Multi-billion barrels of exploration potential remaining. Most recently, Uaru-2 came on, showing a big aerial extent for a deposit that could be a future development, potentially the fifth ship. The fourth ship's already really spoken for with Yellowtail, that we hope to get sanctioned by the end of the year. That oil hopefully would come on in 2025, an active E&A exploration appraisal program this year, about 12 wells. Some with sidetracks currently drilling Longtail-3, Koebi-1, and Mako-2. In very good shape. The first ship's producing about 100- 110 a day, working out some kinks in the gas scrubber that we have there. At the end of the day, on track for it to be at capacity or higher by the end of the year. Liza-2 on track for 220,000 barrels a day. Remember, we got 30% of that. That's a major cash inflection point for us next year. That comes on. Payara coming on in 2024. Basically a ship a year coming on thereafter. That's what really gives us the edge in being able to provide durable or sustainable cash flow growth. We have line of sight now pretty much to underpin six ships. The drilling we're doing and appraisal with drilling really underpins that. We also have line of sight to ultimately 10 ships to support development of the discovered resource. We're on track. The oil's going to be needed, and it's going to be low cost. You got to remember, the first three ships that we've sanctioned and approved for development and production have a break-even between $25 and $35 dollar Brent. That's an awesome resource. You touched on it a little bit in your response, but I did want to ask about upcoming exploration wells. It's actually an active exploration year for you in Guyana. If you could just mention again, which wells should we be watching? What areas are being attacked in? If you discover commercial quantities of oil, how is that going to shape your development strategy going forward? Greg. I'd like Greg Hill to answer that, please. Greg, I think you're on mute. Sorry. I was on mute. Yep. Yeah, the exploration and appraisal program this year will get 12 wells down with three drill ships. There's three major objectives, Scott, of the program this year. First and foremost is do appraisal in and around existing discoveries so that we can begin to underpin vessels five, six, and beyond. As John mentioned, we drilled Uaru-2. Very large, nice discovery, confirmed that Uaru is a massive resource. Uaru-Mako could be a hub. For example, we're on Mako-2 right now to again begin to assess Mako. There's probably another ship in there. We're also appraising Longtail as we speak. Longtail has two objectives. One is to appraise existing Longtail accumulation, but secondly, it's to go down and tap into some deeper zones as well. First and foremost is begin to line out those developments. The second objective of this year's appraisal program is to continue to drill the Campanian prospects that really lie between Turbot and Liza. Again, with the interest of underpinning future vessels, but there'll be exploration. For example, we've got a well called Koebi-1 that we're on now, which is a Campanian exploration well, large accumulation. There's another one after that called Whiptail that is another potentially large accumulation as well. If Whiptail came in, potentially it could be a hub on its own right. Then the third objective that we have is really to go down and get some penetrations in the deeper zones which is lower Campanian, but upper Santonian, kind of that interval. Now recall, if you look at those intervals on seismic, the aerial extent, so the channel system, is as big or bigger than what exists in the Campanian, i.e., Liza style reservoirs at 15,000 ft. These deeper zones are 3,000 ft below that at around 18,000 ft. We want to get more penetrations in those to understand the potential. The potential, at least on an aerial extent, is it could be as big or bigger than the upper Campanian, which is where all the developments are currently focused. To summarize again, appraise existing discoveries, figure out the development potential. Drill Campanian exploration wells that could form hubs on their own right. Thirdly, drill either standalone or deep tails to begin to understand that deeper prospectivity. That's the three main objectives with the 12 wells that we will do this year. Got you. Just based upon what you know today, and obviously you'll learn a lot more through the appraisal program, but the prospective economics on a Yellowtail or a Uaru-Mako hub, do you think those will be as good or better than Payara? Greg? Look, we got to get the engineering done. That'll be all part of the field development plan, and there's a lot of optimization work currently being done right now. We think Yellowtail will be somewhere between Liza-2 and Payara. Somewhere in that range. Again, that nice $25-$35 breakeven, it will be somewhere in that range. Got you. Just, before we move on, quickly touch on any update around the operational issues on the gas compressor at Liza-1? Yeah, sure. The only remaining issue right now is the flash gas compressor. The vessel has been operating reliably in the 100,000-110,000 barrel a day range since we took the flash gas compressor down and shipped it to Houston for tear down. Now the plan is bring that flash gas compressor back out in June, install it on the platform or on the FPSO, then get back up to your nameplate of 120+, let's say. After that, continue to operate that until November, then we'll do a shutdown to do two things. One, the shutdown in November will be to install a newly designed flash gas compressor, so it'll be a replacement for the one that is on its way now. The second, probably most important objective, is to further debottleneck the vessel with an optimization project to then take that nameplate somewhere between 140 and 150. Think of it as July, old flash gas compressor comes on, operate around 120 plus, and then November, take the shutdown. Hopefully, by the end of the year, you'll be at some new nameplate that's between 140 and 150 for Liza phase I. All the learnings from all that have been incorporated in phase II, such that phase II has a completely different manufacturer and a completely different design for some of the gas compression. We don't anticipate the reliability problems that we saw on phase I as a result of the learnings on phase II as a result of learnings from phase I. Got you. I just want to remind everybody that if you have a question, please use that question submission box in the top left of your screen. Oksana, did you want to turn to the Bakken? Sure. Shifting geographies to your Bakken asset. Under what conditions would Hess continue expanding its current rig program and adding more rigs beyond the current two? Also, with the recent well optimizations and rig efficiency gains, how many rigs would you need to maintain your daily production at the 200 levels? Yeah. Go ahead, Greg. Okay. Let me first say, the role of the Bakken in the portfolio is to be a cash engine. It's not a growth engine. Its primary role in the portfolio is to be a cash engine. When we add rigs will be a function of corporate cash flow need. What we said on our conference call, if current prices hold around the $60 level, let's say $55-$60, we're giving strong consideration to adding a third rig going into next year. Let's say fourth quarter. We have not made that decision yet. We will again, if crude prices are strong, then we'll add that third rig. Ultimately, the most rigs we would ever be at in the Bakken would be four. Let's assume that prices would hold strongly again through 2022. We'd probably look to add that fourth rig at the back end of 2022, just like the third rig at the back end of 2021. Once you do that, then you can get the Bakken to around that 200,000 barrel a day mark. Why is that important? Well, first of all, because you utilize very efficiently all that infrastructure you built up there. It's kind of the sweet spot of a value. Also, by holding at 200,000 barrels a day, plus or minus, the Bakken can generate $1 billion a year of free cash flow at $60 WTI. We can hold that plateau for 8-10 years. The Bakken suddenly becomes like Malaysia times four, right? It becomes this massive cash engine for the company that's just a nice, very healthy flat annuity. Remember, we've got 2,200 well locations that generate great returns at $60 WTI. We want to prosecute that inventory because it's a good return inventory and reap the benefits of that cash firepower of the Bakken. Great. Speaking of the infrastructure, with the recent regulatory issues that the Dakota Access Pipeline has been facing, what incremental cost would Hess face if potentially you're not able to ship on the pipe? Yeah. John Rielly. Sure. If, yeah, they do shut down DAPL, we first, from our infrastructure standpoint and excess capacity that we have on other pipelines, one, we can move our oil out of the basin, no problem. With the excess capacity and the rail terminal that we could move up to 100,000 barrels of oil per day at the rail terminal. We've been moving about 55,000 barrels a day on DAPL, so we can easily move it to other outlets. Now, going from DAPL down to the Gulf Coast, though, to your question versus rail going to the Gulf Coast, that's going to be about a $2-$3 difference. Now, I can't tell you what will happen with netbacks should that change. If you take all those DAPL barrels out of the Gulf Coast, maybe netbacks get better. On a pure cost basis, it will cost us about $2-$3 more to move it on rail than on DAPL down to the Gulf Coast. Great. Speaking of the Gulf Coast, let's talk about your Gulf of Mexico exploration program, drilling program. When do you plan to restart that? When you do restart that, could you speak about the tiebacks opportunities and explorations, and where the focus would be more? Yeah. Greg? Let me talk about the Gulf of Mexico. Again, its role in the portfolio is to be primarily a cash engine, just like the Bakken is. We have an inventory of some 80 blocks of existing leases, so it's not subject to the Biden potential moratorium on new leases. We've got 80 blocks in the Gulf in our current inventory. Broadly, that's split between about a third tiebacks, about a third new Miocene hub class opportunities. Kind of half a million barrel kind of, or half a billion barrel type opportunities. About a third in the emerging Cretaceous play. Cretaceous/Norphlet play. As we look forward, again, a function of crude price, because remember, the primary role of the Bakken is a cash generator. As crude prices improve, as the corporate cash flow improves, as Guyana phase II comes on, for example, and phase I goes to the higher nameplate, we would look to go back to work in the Gulf of Mexico in 2022. We're talking to Shell right now about a It's really an ILX well. It's actually an infield additional well that we could start at the end of the fourth quarter. It's called Llano-6. We're also looking at a hub class opportunity called Huron. Very large Miocene prospect called Huron that we haven't made the decision on that yet either. That could feature in 2022 as well. Think of it as a tieback that would start in the fourth quarter, and then potentially a hub class well in the first half of 2022. As we move forward, obviously, depending on technical results, we would like to, at a minimum, hold the Gulf of Mexico flat. If you get some hub class opportunities that come in, potentially you could grow it a bit. Again, the governor will always be corporate cash flow on the Gulf of Mexico. I think the other point, the Biden administration has put a moratorium on federal sales. We'll see where that comes out. It has really very little impact on us given that The last several years, we bought 60 blocks for $120 million. That's in the 80 blocks that Greg talks about. About a third of those blocks are these tie-backs, a third are Miocene, a third are Cretaceous. We have a healthy inventory of opportunities to invest in. Obviously, it's a function of cash flow, it's a function of returns, the opportunities we have in the Gulf of Mexico definitely can compete for returns in our portfolio. The Biden administration, so far, has been very supportive of continuing drilling operations and production operations on existing leases. Yep. That's great. Your other asset in your portfolio, cash generation, Gulf of Thailand. Could you speak a little bit about the strategy there, what the plans are? Are you seeing the demand recovering? Also the production sharing agreement that is nearing expiration day or year in 2029 in JDA. Yeah. Go ahead, Greg. Yeah. Again, the role of Asia in our portfolio is to be a cash generator. It's PSC, so it does give you some downside protection, which is also why we like to have it in the portfolio, right? The gas prices are oil linked. You're right, our first expiry is 2029 in JDA, and we're currently in negotiations right now, with both Thailand and Malaysia to extend that PSC. That's going to take 18 months, 24 months to try to get resolved. We're currently in negotiations to extend that. The other one that we have is North Malay Basin, and that goes to 2033. It also has some extension potential as well. These are great assets. They don't require extreme technical, I call it Bakken on the sea. It's just simply design one, build many. Simple four-well jackets in shallow water. We've continued to drive efficiencies there. That's what we'll do. We'll put $250 million a year and get $250 million-$300 million of free cash flow out. It's a hold in the portfolio. It plays a very important role. Regarding current levels of production, pretty much back to pre-COVID. Demand's increasing in that part of the world. Great. Scott, do you want to see if there are questions from the audience? Yes. If anyone has a question, please submit that now. We've got seven minutes remaining. I do have one question that came in here on usage of cash. John, you mentioned the free cash inflection with the startup of Liza-2. The question here is on usage of that cash and how do you think about deployment across the debt paydown and/or incremental returns to shareholders, and what you'd be looking for to start giving more cash back to shareholders? Absolutely. John Rielly. Yeah. Our strategy has been that the first use of available cash of our free cash is going to pay down debt, the $1 billion term loan that we took out last year. We had a very strong first quarter. We ended the quarter $1.86 billion of cash. We did close our Bakken sale already, the $312 million sale. That happened at the end of April. We're in a nice cash position from there. Our Denmark sale, we expect to close in the third quarter. If you remember, that was $150 million. With prices where they are and our strong cash position, we are clearly looking at potentially paying down some of that debt this year, which would have been much earlier than we were expecting coming into the year, with the way oil prices have been. We'll just continue to monitor the oil markets, and as we get more of this cash in, we'll potentially pay down some of the debt this year. As phase II comes on, we get free cash flow, and it's a significant amount bump of free cash flow when phase II comes online. Again, we'll continue to pay off that term loan, get that $1 billion paid off. The next use of the free cash then will be to increase the dividend. We're focused on getting that dividend up. We want to make sure we're basically more than competitive with the S&P 500. Then what happens is you get Payara, then you get Yellowtail, and you get the fifth FPSO. We're going to keep getting significant amount of cash flow added in with each FPSO. That's when you can expect us to do opportunistic type share repurchases. Could be special dividends. The thing we are saying is that the majority of our free cash flow will go back to shareholders. Got it. Another question from me, obviously, the right discussion points for the business are largely around cash. Cash usage, cash generation, cash deployment, as you just talked about, John. Not too many people in the E&P industry talk about corporate level returns, right? For obvious reasons, the industry has struggled with producing returns that are consistently in excess of WACC. You guys have a unique kind of return enhancement generator with the incremental ships coming on in Guyana. Could you just speak to that return profile that Hess is going to post. Are you guys on a path to sustainable excess returns? The answer is yes, but John, go ahead. Yeah. I knew the answer. The details. The details would be great. With the breakevens, as we've talked about on the first three, between $25 and $35 Brent, as Greg was saying, with the Yellowtail being expected between Payara and phase II. We see these FPSOs come on. One, our F&D costs. F&D is going down, which obviously is going to drive our DD&A down, let alone that it's a low cost from the development standpoint, the operating cost. While we are still leasing the vessels, phase I is about a $12 cash cost per barrel. Phase II will be about a $10 cash cost. When we buy the FPSOs, phase I is going to go between $8 and $9, and phase II is going to go between $7 and $8. These are low cost on the operating side and low cost on the development. It is really each time an FPSO comes on, we're just let alone going to obviously have production growth, cash flow growth, free cash flow growth, but increasing returns. Our rate of change, again, on the return side, I think is going to be, as you said, Scott, before, really unique in our industry. Got it. Oksana, what else do you have? You could touch on the ESG since it's a hot topic these days. Can you speak about your collaboration with the Salk Institute and path forward? Sure. I think a couple points. Look, you nicely pointed out. Our company is committed to superior, in fact, industry-leading ESG performance. We've been doing a sustainability report for 23 years. We support the aim of the Paris Agreement, as well as the global ambition to net zero by 2050. We have set very aggressive targets on GHG emission intensity, flaring intensity, going down the last five years, 40% on the greenhouse gas intensity, 60% on the flaring intensity. We just put new targets out to 2025. Greenhouse gas intensity down 44%, as well as methane reduction intensity 50%. By the way, these are superior targets, better targets than the OGCI has put out. So we want to stay an industry leader. That's obviously on scope one and scope two, where we're working, to your point on scope three, is looking to nature to play a key role in getting carbon emissions down. Most people don't realize that there's more carbon in the soil than there is in the atmosphere. Who better than Mother Nature to capture CO2 and store that carbon in the ground? That's where the Salk Institute comes out. Many people are looking at industry solutions for dealing with carbon capture and sequestration. We're actually looking to nature. We've been supporting research there that is, we think, going to be one of the game breakers that Bill Gates talks about in his book, about how to avoid a climate disaster. It's really where you are able to grow crops that'll have wider roots, longer roots, and more absorptive capacity through an element called suberin, to save gigatons a year of carbon from going in the atmosphere and keeping it in the soil. We're in the early stages. It's going to take some time. It's nice that Jeff Bezos has also made a grant to support this research at the Salk Institute. This is something that could make a major change in scope three emissions, and we're proud to be investing, helping the Salk Institute in this groundbreaking research. Great. Well, with that, we've run out of time. A good note to end on. John, Greg, and John, thank you very much for your time and insights today. Great conversation. Thanks, Scott. Thanks for your support. Real pleasure to be with you. Thank you. Thank you. Not a problem.