Welcome Mark Lashier, Chairman and CEO of Phillips 66. Mark has been CEO since 2022 and he has, I believe, been a lifer with the company back to Phillips Petroleum and inclusive of his time at CPChem, where he had several positions and ultimately ran CPChem prior to taking the helm of Phillips 66. Mark, thanks very much for joining us today. John, thanks for having us here. Let's start with probably the key topic, which is the annual meeting, if we can. You've had this, you know, highly public situation with an activist shareholder. Ultimately you had a split board vote with two of the four board members, two of your four nominees elected. Can you talk about how you view the outcome of the shareholder vote? Sure, John, thanks. I think the whole process gave us an opportunity to really dig in deeply with a broad array of shareholders, investors and to tell our story, to bring board members in front of them, to give them an inside view to the process around what we do around strategy. I think it was great, good, constructive feedback from shareholders. We really appreciated the time that they took to hear our story. I think it helped us sharpen our message and provide clarity and really double down on our commitment to improve our refining performance. We've been on that journey for some time. Employees responded incredibly well during this. I think that, and now that we're in the process, beyond the annual general meeting, we're onboarding three new board members and that's going well. That's live last week, this week. I think that now they're getting an inside view of all the things that we've been talking about, all the things that we're doing. I believe that across the whole spectrum of our board, we consistently have board members that constructively challenge us on our strategies to look at what we're doing. They know there's no sacred cows at Phillips 66, that everything is fair game. The numbers have to make sense. At the end of the day, we've got some very experienced investors, very experienced CEOs, very experienced executives on our board that are very independent and they do what they're supposed to do and that's challenge us on our strategy, make sure that we have the right people doing the right things and delivering long-term value for our shareholders. From that perspective, it was very constructive interaction with our shareholders. Great. My next question is on the balance sheet and kind of the push pull between the balance sheet and returns of capital. How do you think about the balance sheet between the leverage target and buybacks in 2025 and beyond? How much of the proceeds from the jet asset sales do you expect to allocate to debt paydown? John, we're absolutely committed to returning at least 50% of our net operating cash flow to investors. The first priority is our sustaining capital, that's less than $1 billion, and then ensure that we're taking good care of our assets so we can deliver safe, reliable operations over the long term. Our $2 billion in dividend. Beyond that, we've got opportunities for share repurchases and balance sheet. When you think about the balance there, we say that we're going to be zeroing in our capital budget $2 billion-$2.5 billion. You take $1 billion out, so we've got about $1 billion-$1.5 billion in growth CapEx. We think there's plenty of room for share repurchases and balance sheet. Getting our balance sheet in shape. Now from an ongoing operating cash flow perspective, we'd like to see refining margins be a little more robust to get to that $17 billion number. The proceeds from selling 65% interest in our JET assets in Germany and Austria, that'll close the second half of this year. After tax we should see about $1.5 billion come in from that. That's all going to debt pay down. That'll be a big step towards our goal of getting down to $17 billion. Really the way we think about debt, we like to think that, look, refining, I think that there's a lot of incentives for a refining business to be debt -free. We have a midstream business and a marketing business. When they're combined, they generate very consistent earnings of about $6 billion. When you put a conservative three multiple on that EBITDA, you've got capacity just from those two businesses to easily service about $18 billion in debt. So that's $17 billion target is coming from. We feel like that's a very conservative balance sheet and the right place to be for now. Great. My next question is on midstream. Can you talk a little bit about the organic expansion that's happening on the gas processing side with both Dos Picos and Iron Mesa? Do you need more gas plant capacity from here to achieve the level of integration you're looking for with the NGL value chain? Yeah. When you step back in a big picture since we rolled up DCP and if you look at what we have in flight, with Dos Picos II, Iron Mesa, we'll have added about 700 million cubic feet a day of gathering processing capacity. We believe that we can be on a pace of about one gas processing plant a year to ensure that we have the capacity to manage the acreage commitments that we have out there. We like to understand that we're going to be able to load these facilities up before we put them in place. It's a good combination with the contractual commitments we have out there from other people's gas gathering facilities. Dos Picos was an opportunity that came in with the Pinnacle acquisition. They had one operating gas plant here. This is a duplicate of that. Another 250 million standard cubic feet a day that will come online second half of this year. There is room for a third at that location, and there is the capacity for that that could come out later on, because we wanted to next address opportunities out in the Midland and Delaware basins. That is where Iron Mesa comes in. It'll be 300 million cubic feet a day. It's our largest gas gathering and processing facility. It'll be incredibly cost efficient. It addresses some reliability challenges. We at the Goldsmith plant that is in the same neighborhood, upstream producers, are thrilled to see this asset coming. It'll be on stream in 2027. Again beyond that, we have the ability to add about another gathering and processing unit per year for the foreseeable future. When you look at the Pinnacle acquisition, the EPIC acquisition in particular, it has opened up frontiers for us to add the gathering and processing assets in a very efficient way that we want to add, and we can take full advantage of the competitive advantage we have created with those assets. When you think about what we are doing in the NGL midstream, at every step that we have done, we have leveraged a competitive advantage, whether it is the fractionators that we built at Sweeny, the storage that we leverage at Sweeny, the pipelines that we brought in from DCP, the gathering processing assets that we have acquired have all been very synergistic with existing assets. The EPIC acquisition really opened up a whole new frontier that directly integrates, not only with the DCP assets in the basin, but down through Corpus Christi. We have this bidirectional freeway for NGL volumes from Corpus Christi to Sweeny up to Mont Belvieu, something that no other NGL producer can provide in terms of market access to their upstream customers. We are very pleased with that. If you look forward right now, we are oversubscribed on our capacity on Sandhills. We are having to move volumes on other people's pipes. The beauty of the EPIC transaction is there are volumes already moving through EPIC, but there are two stage expansions that are underway that we will be able to move either capacity that we will get from our own GMP assets or from third party GMP assets that are committed to our system. We are quite full. We have control of those volumes. At some point in time we believe we'll have an opportunity to add fractionation capacity either to the existing EPIC footprint down at Corpus Christi or in our Sweeny complex, whichever makes the most economic sense at the time. It really is a fantastic, you know, perfect fit for us from the perspective of creating and leveraging the competitive advantages that we have. Great. So my next question is on a business that I'm sure is near and dear to you, which is chemicals. Ethane- based ethylene margins are well below mid cycle today. They have been for some time. What are your expectations for margins for the second half of the year and what will it take for margins to show a recovery? Is China demand the key driver? Are there other drivers we should think about? Yeah, no, John. CPChem has been a great business for us. It's been around 25 years as a joint venture. It's been remarkably successful as a joint venture over the long term, it's our highest return on capital employed business and it's grown faster and more profitably than any of its competitors. It's been a success by any measure. Right now it's in one of the longest downturns. The industry is in one of the longest downturns that we've seen in 30 or 40 years. Certainly my career and maybe I'm an optimist, but those long downturns tend to be the preparation for a very good upswing. We believe that will happen because global demand continues to increase. A lot of capacity was added based on low -cost ethane in North America, low -cost ethane in the Middle East. We've participated in that because we believe we can be the low cost producers through CPChem. We've got these assets that we're building with QatarEnergy over in the Golden Triangle and one in Ras Laffan, Qatar that will be world class. And CPChem, even though it's a downturn, CPChem is generating on the order of $1 billion of EBITDA a year while assets in Europe and assets in the Far East are struggling or rationalizing shutting down. If they're not shutting down, they're bleeding cash. CPChem was built for this environment and there will be a shakeout. Really, I think that, you know, China aside, I think there are two things that are going to drive the recovery. Rationalization of non-competitive assets that need to go away and this continued march up and to the right of demand growth in the globe. Now we've had some turmoil around tariffs, we've had turmoil around geopolitics this year that maybe have complicated that a bit. Those long-term fundamentals still exist. We believe that the combination of the continued demand growth rationalization and, other than the assets that CPChem and QatarEnergy are adding, there's not a lot of new capacity coming over the horizon. We're constructive long term around the performance of CPChem and the ethane value chain. Would chemicals ever be on the table as part of an asset sale program? If it were, if you were to kind of get the right price for it and outside of your JV partner, are there potentially other buyers there or is there just the one natural buyer? As I said in response to the first question, there's no sacred cows at Phillips 66. We do a comprehensive review of all of our assets annually and think about what assets should be in our portfolio. What assets might have greater value in the hands of someone else. CPChem is no different. If you know, the challenge is in the current environment, I don't believe there's anyone interested in paying us full value for those assets. I think there's been even some sell side commentary out there about what the sell side view is, the key, the whole value of those assets from our perspective. I think that in this environment it would be tough for a seller to come up with that. It's probably a good time to buy petrochemical assets, but it's probably not a great time to sell petrochemical assets. You throw in the fact that CPChem has two mega projects coming online and there's earnings upside there as well as coming out of this long downturn, there's a lot of upside potential there. Having said that, like any asset we own, if there's a buyer out there that sees more value in these assets than we do and is willing to commit to the right kind of deal, we're all ears. Maybe moving on to refining, can you talk about what inning you're currently in, in terms of your reliability efforts, what improvements you've made so far and what's still ahead of you? Yeah, I think we're still in early -to -mid innings in refining. It's interesting. I think last year I was talking to you at this venue, John, and I quoted Rich Harbison said we need to focus in refining on the things that we can control. The first step was to get our costs down. Now we're focusing on opportunities to enhance margin, increase yields. You know, you fast forward now, we've had two years of utilization rates above industry average. One of our 2027 strategic priorities is to ensure that we're at least two full percentage points above industry average utilization. If you look at that, it contributes to lower cost per barrel. If you look at things like yields, the last three quarters we've increased our high value product yields and we've gone from 84% to 87%, almost a straight line up to the right. That didn't happen by accident. That happened because of very deliberate, small but very impactful capital investments that we made. We've made investments to enhance the flexibility of these assets. We're really focusing intentionally on the central corridor assets where we, I think we're leader in EBITDA per barrel production primarily because this is where our assets are integrated. We can move streams between refineries to optimize a stream that is in a refinery that's full. We can optimize it in another stream or another refinery that may have some room to maneuver. Across the board we've had a very intentional and major program to reduce costs not just in the refining, but support costs, SG&A costs, everything. I think initially in 2022 we came out with a $0.75 a barrel target. In 2023 we increased that to $1 per barrel. We've exceeded that aspiration and now we've pushed it from somewhere around $7 a barrel to below $6 a barrel. Now we're targeting $5.50 a barrel and beyond. Probably the biggest impact that you'll see this year is when we cease operations at our Los Angeles refinery in the fourth quarter. That's a very high cost refinery, low -to -no earnings. We will be able to not only reduce the controllable costs in our entire refining fleet by, say, $0.20-$0.25 a barrel, but we will also free up all the sustaining capital that was going into that asset to keep it viable, to make it available for other uses. When you move beyond that impact, the remainder of that $0.20-$0.25 cents is just the continuous focus across the board on reducing costs, enhancing efficiencies, driving consistent operations, and lowering our turnaround costs as well. It has been very gratifying to see our employees' response to the cost program. There is always resistance to change, but we have reached a tipping point, I think, in the last year where employees are coming forward and saying we were worried about these cost reductions, we were worried about you taking people out of the organization. Now we have fewer people, we're getting more done, our jobs are more enjoyable, let's keep on this path. There is a lot of ownership in that. I'll be honest with you, John, the whole situation around our proxy heightened employees' awareness. They realized that it's just not an exercise. This is something that we have to do every day to compete and stay competitive because people are watching and shareholders have expectations. It has been a very virtuous cycle that we're in around the cost control. By 2026 we should have baked in that $5.50 a barrel. It is out there consistent and we're going to have aspirations to move beyond that. That is just the next step. Great. Just a follow up on refining. There's a little bit of an issue with comparability with peers because you have some of your refining related income that sits in M & S. Are there any plans to kind of improve the transparency around that for people like me to get a better comparison? One thing we're committed to is ensuring that we've got a great narrative out there that investors, sell side, buy side, have as much clarity as possible on what we're doing. We are certainly looking at what we can do to make sure that our performance is compared on an apples to apples basis. It's not a simple thing to do, but we're looking at it. Kevin Mitchell, our CFO, and his team are certainly taking a hard look at how to do that to get as close. You can never get it perfectly because it's different businesses, but I think you can get it in a context where everyone can look at it and say, okay, that's an apples -to -apples comparison. Great. So my next question's on growth CapEx. W hat are some examples of growth projects that are still ahead of you on the refining side and what type of spend is necessary to achieve your goals for improving on the capture rate? Yeah. When you look at our overall capital budget, we've said that this year, the next several years, the capital budget will be between $2 billion-$2.5 billion a year in refining. This year I think we're around $800 million. About half of that is sustaining capital. About half of that is, I won't call it growth capital, I'll call it returns capital because we're not trying to grow our refining business, but we've got some very high -return, quick -return projects. There are things to enhance low -sulfur diesel production in Lake Charles. We just completed a significant project at Sweeny that will allow us to swing from 40,000 barrels of heavy sour crude to 40,000 barrels of light Permian crude. So we can have some flexibility when the economics dictate. I think as we look out into the future, with the volatility in the markets, the need to leverage domestic hydrocarbons to go out and compete in the world, that flexibility is important. We're moving more molecules in distillate up from diesel into jet. We're moving low, lower octane molecules into higher octane. Things like that just to continue to produce higher value products. Things that are worth less than a barrel of oil, we want them to be worth more than a barrel of oil. It is just small projects here and there that are very high return, quick payout projects. We've got a healthy appetite so that most of that $400 million every year is associated with projects like that. We've got a long list of opportunities. Most of that will be focused in our central corridor where we see our long term competitive advantage and a lot of integration value there. Maybe we can step back and go back to some more macro type questions. My next question is on crude differentials. Where do you think the WCS will settle now post TMX and how long do you think it'll take before supply kind of grows into takeaway in Alberta? Sure. Yeah. No, I think that you've seen a lot of things come into play. First half of this year, of course, TMX taking barrels out to the West Coast. We do still have barrels coming down to the Gulf Coast, but there's a number of headwinds right now. You've got producers in Alberta doing a lot of maintenance this time of year. You've had a lot of wildfires up there and all of that has come together to tighten up the diffs. So we're in, call it, $7-$8. I think where we are today we see that turnaround work being done. If the fires are mitigated second half of this year, we may see diffs widening back out to $12-$14. There's a lot of heavier OPEC crude, Saudi crude, Middle East crude coming into the market. That's constructive for those diffs as well. Let's stay with that maybe, and follow up on coastal light -heavy diffs. What's your view on coastal light -heavy diffs for the remainder of the year? Obviously, a lot of moving pieces around OPEC bringing back barrels and all the geopolitical things that are going on right now. What's your view on just the coastal light -heavy diffs? Yeah, there's some headwinds there as well. The Mayan crudes are declining and more of that is being shifted as Dos Picos refinery comes up there. You've got sanctions on Venezuelan crude. There are headwinds there as well. It's related also to the tailwind of OPEC coming in, but then the headwind of more Canadian crudes moving to Asia. It's all interconnected, I think, at the end of the day. I would say just from the coastal crude specifically, there's probably more headwinds than tailwinds to those diffs. My next question is on refining in California. You've announced the closure of your operations at Wilmington. What were the key drivers in that decision? Is there anything that could lead you to postpone or reverse the decision before the end of the year? It's always a tough decision to shut down an asset. You know, like 600 people are looking for jobs elsewhere. Frankly, in California, a lot of them are finding jobs very quickly. It's a robust job market. When you look at all the elements that you need to be competitive in refining. Crude advantage. California's lost its crude advantage. These refineries were configured to run California crude. California crude production is down 75%. These refineries. This refinery is actually two old refineries that are interconnected. Its configuration isn't particularly competitive. You have to make CARB gasoline, which adds to cost. Just the base, call it the base cost of operating a refinery in California is probably 2x what it is on the Gulf Coast. There were just a lot of headwinds against this refinery. It was one of our highest cost refineries. Very low contribution to the bottom line. All those things conspired to lead us to the conclusion that we needed to cease operations this year and start a process to redevelop the land for a higher value use. I'll tell you that we've had great cooperation with the California administration, Governor Newsom, the California Energy Council. They have been very helpful in helping us identify the best ways to resupply California, to getting permits to import refined products from offshore. Our Ferndale asset in Washington is shifting over to be able to produce CARB gasoline to bring both into Northern California and Southern California. By the way, we've done the whole resupply thing already in Northern California. When we converted Rodeo to renewable diesel, we stopped producing gasoline up there. It works, the economics work, and I think it's a. Frankly, it's even more stable for the state of California when once there's a consistent supply of refined products coming in versus relying primarily on refineries in California that go up and down, and then you have to wait maybe a couple weeks for refined products to gear up and come in from Asia. This will be kind of a consistent flow, much like we see in the Northeast. The Northeast is short refining capacity. Most people don't realize that most of the refined products come from offshore, from Europe, from Africa, from the Middle East. No one feels that in the marketplace here. It's a very competitive market because California can have a similar situation over the long term where they can have stability with existing assets in California, with imports. We're going to be part of that import. We have retail outlets in California. All of them have been converted to provide renewable diesel. We've got to supply the gasoline to those. We've got other customers in California that we're going to make sure they're supplied. We are committed to resupplying what we're taking out of the California market. My next question's on your outlook. Just on RINs. There have been a lot of moving pieces. Obviously the PTC switch has been a positive for RINs. You've also had the preliminary RFS has come out, but we don't really know which way small refinery exemptions are going to go. Can you just, how do you sort of put it all together and think about RIN prices? Yeah, it's complicated. There's a lot going on, whether it's the 45Z elements in the Big Beautiful Bill, the way the EPA is interpreting things. The farm lobby's been active in protecting their interests. In general, we see from a renewables perspective, RINs being constructive, though from an imported molecule perspective, not as much, but we think it's directionally moving the right way. From a small refinery exemption perspective, it's a little controversial because there's the potential that large refiners would have to cover the small refineries exemption. I think that as most of our portfolio is considered large refineries, we would be covering that, most large refineries would. It's not clear if that would actually be done though. I think in the first Trump administration, same rules were in place. Small refineries got exemptions and they did not reallocate those exemptions to large refineries. There is some flexibility in how the rules get implemented. It is getting clearer. There are still a lot of elements out there, John, that we are watching very carefully. Great. We are at about a minute, so why do we not wrap there. Mark, thank you very much for your time. Really appreciate it. Thank you, John.