Okay. We'll get started now. We're joined by Mark Lashier, President and CEO of Phillips 66. Mark took over the CEO role about a year ago after being in the COO seat for about a year. Prior to that, Mark ran the CPChem business. We also have Jeff Dietert, Vice President of Investor Relations. Jeff joined the company in 2017 after a long career, doing what I do on the sales side, and had some additional energy experience, I think, prior to that. Mark and Jeff, thank you very much for joining us today. Glad to be here, John. Why don't we start with the balance sheet? You've, you've set out a guide of 25% to 30% net debt to capital. You were at the bottom end in the end of Q1, but you've recently closed DCP, and presumably have moved up that scale a bit. Where would you like to be positioned within that range today, particularly given some of the uncertainty in the environment? Sure, John. Yeah, we've been consistent in our messaging around where we want to be in our balance sheet. We set out the 25% to 30% net debt to capital in our Investor Day discussions last November. We, you know, if there's one thing we took out of COVID, is that it's good to have a resilient balance sheet, particularly when there's potential headwinds. We are going forward with that same perspective, that we have kind of a minimum perspective of $2 billion to $3 billion to keep on the balance sheet, in addition to the 25% to 30% net debt to capital, and we're above that cash level even after that, the transaction. We took about $3.8 billion of cash off our balance sheet. Some of it was pre-funded with bonds we put in place and a credit facility we put in place, so we're comfortable there. We've got the opportunity to continue to bring that debt back down below that 30% level, but we'll do it when we see debt maturities come in, and do it pretty pragmatically over the next year or so. Maybe we can move on to capital allocation. You laid out a target of $10 billion to $12 billion return to shareholders through 2024 at your Investor Day last year. If 2023 and 2024 finish below mid-cycle, is it possible you could come in below that guide? Do you expect to execute on that guidance regardless of the direction of the cycle? Yeah, I think we've got. All those plans were premised on mid-cycle, we actually had some cushion in that mid-cycle number. We're well above mid-cycle. Halfway through 2023, we're above mid-cycle, you know, our commitments, our capital allocation commitments really start with our sustaining capital, and we're at about the billion-dollar level. The dividend, we are committed to a secure, growing, competitive dividend. We've increased our dividend every year, including the COVID years, when others backed away from dividends. you know, that's a promise, that's a commitment that we've made. Today, our commitment level is about $2 billion in aggregate, we will continue to grow that dividend every year. If you look at that commitment, the $10 billion to $12 billion over the 10 quarters from July of 2022 to the end of 2024, dividends will cover about $5 billion of the $10 billion to $12 billion. We don't see that aggregate dividend growing, but as we take shares out of play through our share repurchases, we'll be able to grow the per share dividend and stay within kind of that $2 billion range. That leaves another $5 billion to $7 billion in share repurchases. Through the Q1, we were above the pace we would need to be at to hit the high end of that. As we continue to see our share price below its intrinsic value, we're gonna continue to be on that pace. One of your big initiatives since taking over, Mark, has been cost reductions. I think the most recent number you've given is that you've achieved $600 million to date, or over $600 million. I know you plan to give us a bit more on the Q2 call, but can you give us some details on the progress made so far on your cost save program, and maybe some of the key sources, the final pieces to get to your $1 billion dollar target? Sure. We believe that our business transformation is really critical to setting the stage for our future at Phillips 66. The high-level view is that we're targeting $1 billion in cost. If you think of the breakout of that, about $800 million is actual cost that you'd see flow through to the bottom line. About $200 million is becoming more efficient in how we address our sustaining capital needs. This has been a tough process. With last year, at the end of the year, we hit about $500 million. About half of that was in organization design. That's a nice way of saying we eliminated 1,100 positions. About half of that $500 million shows up in refining. While this is an across-the-board exercise, every part of the company is being touched by this, the major impact is in our refining organization. Cost is one thing, but really, underlying that is we're changing the way we work, the way we're organized. We're centralizing a lot of functions to support our refinery functions. We used to have every refinery as its own entity, its own island. Now we're providing expertise and guidance from a more centralized perspective. We created a value chain organization several years ago, we've enhanced its ability to really be a strong bridge between our commercial organization and our refineries. We've got people embedded in our refineries that report into Value Chain Organization. They sit on the refinery leadership team, and then we've got people from our Value Chain Organization sitting with our commercial group. There's this direct line that allows us to optimize across the whole fleet every day, every minute. We're looking for value creation opportunities. In refining, we're focused on a couple of things. The cost piece is there. It translates to about $0.75 a barrel in cost reduction. You know, key to that is making sure that we've got those assets available when the market is there. We're focusing on increasing the availability of our refining assets, and then we're focusing on capturing as much from the market as we can. We've got a series of small capital projects that increase our flexibility on the cruise we process, that enhance our ability to produce the higher value products, and to enhance our ability around processing crude at higher rates. All those things are accreted to the value of our refining kit. Above and beyond the cold, hard cash, the cost numbers are changing the ways we're working and creating a more competitive mindset across the organization. We, you know, a year ago, when I would go into refineries to talk about business transformation, I'd see cold, stony faces out in the audience. Now, we're engaging with employees about it, and they've bought into the process. They see the fruits of their labor starting to show up in the cost numbers, in the way we execute turnarounds, in the way we're creating value. They now recognize that they own the future of the success or failure of our refining system and across our entire organization. We've gone from a mindset where the world is not wanting hydrocarbons. They want us to go away. There's no residual value in our refining assets to one where we recognize refining is gonna be not only around for a long time, it's gonna be needed, and it's gonna be valued for a very long period of time. We've got to get better at it every day. We've got to lower our carbon footprint. We've got to do it in a way that generates returns, and everybody in our refining organization, everybody across the enterprise, is committed to that and energized by that. It's really been this virtuous cycle, both in the raw cost control, but also the competitive mindset of everybody in the organization. On the refining side of the business, there's been some news flow about the closure of an FCC at Bayway. Mm-hmm. Are these reports true, how should we think about the impact on Q2 throughputs and captures, if so? Just a general update there. Yeah, John, the, we had an issue with the flue gas offtake line coming out of our FCC in Bayway. We did work on that. It was in turnaround several weeks ago. Shortly after coming out of turnaround, this particular pipe had a failure in some refractory that was critical to its operation, so we had to take the FCC down. We did not have to take Bayway down in its entirety. It's still operating, the crude unit's still operating, and we'll be able to operate in this mode while we make that repair over the next few weeks, get it back online. Then we'll be able to process the intermediates that we're producing today through the FCC. It's created some headwinds. Clearly, we're looking at utilization rates. Our guidance originally was mid-nineties, and we'll probably be in the mid to low nineties. There is a modest impact on our aggregate utilization, I mean, I'm sorry, for the Q2. Great. Then, next one's on renewable diesel and the Rodeo conversion. How do you view the attractiveness of the RD market today and the returns in today's market relative to your initial expectations, and maybe particularly in light of the news that's come out about the RVO? Sure. John, we've, you know, we're well underway with the execution of our project in what we call Rodeo Renewed, where we will make the step of taking a refinery that's north of San Francisco, on the Bay. We'll take it off of crude oil processing, and it'll go to 100% renewable processing to produce about 50,000 barrels a day of renewable products. Today, or since 2021, we've been operating a smaller hydrotreater that we did enough work to make it flexible and give it the ability to produce renewable diesel. We believe that that has greatly de-risked the larger project that's coming on. We call it Unit 250. Unit 250 has been running at about 30% higher rates than we premised. It's running at a higher selectivity to renewable diesel, and it's outperformed our expectations operationally and commercially. We're seeing higher returns than we expected, so we're able to also process a broader array of feedstocks through this unit that has no pretreatment capability. When we're done with Rodeo Renewed, we'll have a very large pretreatment capacity, so we'll be able to process an even broader range of low CI materials through this facility. We've already got CI pathways established, and we know that process in California. We know how to do that. We've got a high degree of confidence in our ability to process the feedstocks and to deal with the regulatory environment around that. Finally, you know, one of our keys to success there is we've converted 600 of our retail outlets in California to for direct sale to consumers of renewable diesel. We're controlling the value of that product all the way out to the consumer, so we're not leaking any of the benefit to third parties. You can go into one of our 76 stations, big orange logo, you'll see a green logo on the renewable diesel pump. If you had a diesel truck out there, you can fill it up with this, and it's a direct drop-in for diesel, and you can buy it today. We're seeing great uptake of the product there, and it really has whet our appetite for this additional increment. Rodeo will be one of the largest renewable diesel facilities on the planet. It's well situated logistically on the water in San Francisco Bay. We can bring in feedstocks from Asia. We can bring feedstocks from by rail. Our commercial team has been accessing feedstocks today, they've seen the volume upside come into reality. They're seeing about 3x the volume of renewables coming into the country versus last year. They've secured what we need to start up and operate this facility, and in fact, they're actively selling to other consumers what we're not consuming today, and then we'll bring that into our own facility when it comes online early next year. We are in good shape. I think with respect to the RVO announcement today, it's, I think it's been described as bearish. It's bearish compared to what people were hoping for. I think what the early analysis from our team is that it will keep the RIN Bank. It's kind of this esoteric thing that not a lot of people understand, but the RIN Bank will still be very tight, which means the excess ability to buy RINs when you need RINs, is still gonna be very thin. That says that if there isn't enough RIN generation, if there's not enough incentive to produce renewable diesel, very quickly, the bank will dry up, and there will be an incentive to run more renewables. They've created a very fine edge to that. What we've seen with our Unit 250 operation is you've got so many different incentives in play. You've got LCFS in California, you've got LCF in Washington, you've got the ability to capture similar incentives from Canada. You've got RINs that come into play, RIN obligation, RIN values. You've got blender's tax credits that have been re-implemented in the Inflation Reduction Act. All of these things come to bear to incent us to produce renewable diesel, and we've seen them all act in concert to incentivize renewable diesel production. If RINs come off a bit, like we're seeing them this morning, you tend to have other incentives that kick in, that encourage renewable diesel production. We continue to be very, very bullish on this facility. It's got strong returns, probably the strongest return project in our portfolio today, particularly for this size of an investment. We're ready to get it on and bring it into the market. I would say the economics that we assumed in the FID are continuing to hold. We've seen volatility in the LCFS, and the RIN, and the feedstock cost, and the, and the diesel values, but they've all worked in concert to sustain the profitability that we had. Yeah. in the FID. I think, one other important thing to mention is that, we expect our emerging energy projects to compete competitively with, other segments of our portfolio on returns. Right. I think, and I, you know, I mentioned the blender's tax credit. We didn't have any benefit in our economic analysis for blender's tax credit, so that adds $1 a gallon in value to this project literally overnight. We didn't have any benefit for sustainable aviation fuel production. With some modest capital, we can produce some renewable aviation fuel that can be then blended up to make sustainable aviation fuel. There's additional upsides there. The IRA made sustainable aviation fuel more competitive with renewable diesel production, so it's a benefit longer term to that project as well. That's a good segue. Maybe we can stick with sustainable aviation fuel. I know you're producing that SAF at Humber. Mm-hmm. Are there learnings from being a producer at Humber that can be applied to Rodeo? You can just maybe elaborate a little bit more on the opportunities set for SAF at Rodeo? Sure. It's there are different regulatory regimes. In the U.K., you can co-process renewables in the refinery, we don't have to have a separate facility like what we're doing at Rodeo. The regulations in the U.S. require you to have a separate facility to be able to account for these productions and get the incentives. In the U.K., we're producing, we're processing things like used cooking oil through the FCC, along with traditional crude feedstocks and some other renewable feedstocks to produce sustainable aviation fuel. If you put in a barrel of renewables, you can count a barrel of sustainable aviation fuel coming out the other end. It's at high level, that's how it works, and we're providing that to British Airways today. It's being consumed, and it's working great. We know that the demand for it is strong. You look at the commitments the airlines have made out there, it's gonna take a tremendous amount of sustainable aviation fuel to meet that demand. There's, you know, the government is setting out lots of aspirational targets for sustainable aviation fuel. We believe long-term, sustainable aviation fuel's got legs because decarbonizing aviation is really, really tough. It's gonna be tough to see long-haul aircraft that run off of batteries or even run off. There's aspirations to run aircraft off of hydrogen, but you just don't have the density of energy that you need for long hauls. We believe sustainable aviation fuel is gonna be key to that. We're looking at other pathways, in addition to, co-producing it in renewable diesel facilities, that, are there pathways that we can go down, to more intentionally produce SAF to meet that demand that's out there? I have one more on Rodeo, which I think you've answered, but I'll ask anyway, just to be sure. If in the hypothetical, where we kind of come to year-end, and West Coast refining, you know, feels very strong, and RD maybe looks less attractive kind of during that time period, is there a chance the project gets delayed, and the facility continues to run as a refinery just to maximize near-term cash flow? Yeah, I think that we are totally committed. We're making progress, and we're at the point of no return on that. We will back out crude by the end of this year. If you look at our projections, we'll produce, we'll generate about $700 million a year in EBITDA from this facility. I think we're bullish that it's the right time to do it and incentive to do it. Also, once we make that conversion, it will no longer be considered a refinery under California's regulations. It's under a different regulatory regime, so there's substantial benefits there as well, and substantial reduction in the carbon footprint of the facility. We think about it, we're actually pulling gasoline and diesel out of that market and then just putting diesel back into the market. I think that actually, just the ability to provide CARB diesel, whether it's traditional diesel or renewable diesel, there's gonna be a strong demand pull for that diesel gallon, diesel barrel. We've, we're converting the terminal assets there to be able to move gasoline into that market from other refineries and other locations, to make sure that Northern California has access to the gasoline that they need to supply that market. Just back to traditional refining, just thinking about the gasoline crack now, we're in the beginning part of summer driving season. How are you thinking about gasoline cracks right now, and how do you think about expectations for summer driving season? It seems like things are off to a decent start coming off kind of a tough year last year. I think we're seeing strong demand in gasoline. I think we're seeing demand for gasoline up versus last year. Globally, we're seeing it up in North America. Jeff's great at going into the details of the numbers, but yeah, we're seeing strong consumer behavior across the economy. I think diesel, you're seeing, you know, a little bit of a contraction, because of, I think, recessionary pressures. It almost seems like the consumer is out there buying, maybe buying less stuff, but buying more experiences, and those experiences require you to move, and so they require you to drive or to fly. We're seeing that in gasoline and jet fuel demand increase, and you've got very low inventories in gasoline similar to last year. You actually have low inventories in diesel, but the relative demand isn't there. This time last year, diesel demand was just blowing right through the summer driving season, and gasoline margins were strong, too. We were getting called to the White House to talk about pain at the pump last year. Of course, it was an election year, and you had all those dynamics. This year, you also have much lower crude price, the flat price of gasoline is going to be lower, but with strong crack spreads. There's gonna be it's kind of a win-win, where we're seeing good margins for gasoline, but the consumer is not seeing ominously high prices that could impact demand for gasoline. We're bullish around gasoline demand and gasoline crack spreads for, you know, for the summer driving season. John, I might add a couple of comments there. I think with the 4.5 million barrels a day that was rationalized globally out of the system, the supply and demand balance for refined products has tightened. We see about a million barrels a day of capacity additions on a net basis for 2023, 2024, and 2025. In a normal economic environment, we would expect that much demand growth, so a continuation of tight markets. The second thing I would mention is we view the European refinery as being the marginal refinery in the world. Last year, with European natural gas prices spiking, we saw cracks go up to cover the higher European cash operating costs. We've recently seen European natural gas prices bump up again. I think that's been supportive of gasoline cracks in this particular, but also diesel cracks. That'll be important to watch with, I think, a tight natural gas market in Europe. Maybe onto a business that Mark Lashier has spent a lot of time in, the chemicals business. Ethane-based ethylene margins have recovered modestly off of bottoms. In Q1, it would seem, you know, relatively flat for most of the year. What are your expectations for margins in the second half? Can margins show a strong recovery in the events of a less robust reopening in China? Thanks, John. We have seen margins recover from Q4 last year, not really from polyethylene price recovery, but more of the ethane price coming off, and that puts CPChem in a relatively strong position, both from accessing low-cost ethane in the U.S. as well as their position in the Middle East. They've been able to run at high rates and capture the demand that's out there, though, the margins are, of course, well below mid-cycle, though recovered a bit from last year. I think that really China demand is kind of the missing link out there for a catalyst for recovery. It's their performance of the Chinese economy, I think, is disappointed on a number of fronts. If their recent announcement of more stimulus for the economy kicks in gear, that would be, I think, beneficial, to petrochemical, and particularly polyethylene demand. I think our view is, we'll wait and see. We're not gonna call that and say that they're on the road to recovery because it's a bit of a black box, I think, for all of us right now. I would just add that, the IHS indicator margin for high-density polyethylene increased from $0.08 in the Q4 to $0.17 in the Q1. So far, it's averaged about $0.20 in the Q2, but we expect that to kind of be choppy in the back half of the year as opposed to. Mm-hmm. run higher. Okay. We have about four minutes remaining. Do we have any questions from the audience? No? Okay. Mark, we're finishing up the Q2 here, and Jeff, we've gone from cracks looking pretty weak in April to a nice recovery in May and June, particularly on the gasoline side, which we discussed. Any early expectations you can give us going into the Q2? Going into? In the Q2. The, the print, the Q2 print. I think you're right. We saw it weakening in the first half of the quarter, and then strengthening in the back half, and a lot of that was tied with the response to higher natural gas prices in Europe. I think from a market capture perspective, we have talked internally about the things we control and a number of low capital, high return projects that Rich Harbison and his team are implementing to improve our market capture. We had a number of projects last year that will improve it by 1% to 1.5%, similar for 2023. There are issues that we don't control on commodity prices that are gonna have an impact. We've seen weaker diesel cracks this quarter, and the Canadian heavy differential has narrowed substantially. Maya discount has narrowed some, and those will have a negative impact on market capture. We're focused on improving the things that we can control, and floating with the market, as far as cracks and diffs scale. Let's stick with crude differentials that you brought up, Jeff. What's your view on coastal light, heavy differentials for the remainder of the year? Mayas come in since the OPEC+ cuts were announced, but still feels, you know, relatively elevated relative to history. What are the key drivers there, and what should we look for in terms of coastal light, heavy diffs? Yeah, I think you're exactly right. They have narrowed in with, I think the OPEC cuts being a primary contributor there. The OPEC cuts have taken medium and heavy sour barrels off the market. I think a key factor for the back half of the year is, do we see the recovery in China that is projected both in the IEA and EIA statistics? When you look out in the back half of the year, it does look to tighten substantially, which would cause OPEC to likely put those heavy sour barrels back into the market. I think the other thing that we're seeing is Venezuelan barrels coming into the market, there could be some incremental volumes there. Probably, modest increments. We are seeing Venezuelan barrels into the market, and they're attractive, for our portfolio. We can, consume them both at Sweeny and at Lake Charles. I think those are gonna be kind of the key factors, for the back half of the year. I think I have time to squeeze one more in. You had a heavy, Q1, maintenance period that followed a heavy, 2022 maintenance year. Is your system fully caught up now in terms of the refining? Are you moving back to a more normalized schedule for turnarounds? Yeah, we, like a lot of the industry during COVID, we deferred turnarounds as much as we could to avoid the cost and to avoid opening up a refinery and then have an entire fleet of people out there get COVID and not be able to put things back together. It was the right thing to do, but that pushed a lot of our turnaround activity into 2022 for us. We had much higher than normal, almost 2x normal load. This year, we're back to a kind of a normal cycle. It's, we've got the opportunity to run really well the rest of the year, and we're gonna execute, and we're gonna do that, so. Well, we're right up against time here, so I just wanna thank Mark and Jeff for coming, and appreciate it, and have a good rest of your day. Very good. Thank you, John.