Folks, we're going to try and get back on schedule. I'm sorry we're running just a few minutes late. So, save the best for last, I guess, right? So, don't tell Mariana I said that. I'm kidding. Now, joking aside, thanks very much indeed for being here, guys. So, Jeff Dietert, of course, head of investor relations, shouldn't be as dangerous for any of you. A worthy competitor some years ago, went to the dark side and has been a big supporter of our conference for all the years we've been doing. So, Jeff, thanks very much for being here. Rich Harbison, who, of course, runs the refining business, probably the topic du jour, as it relates to a lot of things that have happened in the last year or so. I guess we, you know, we don't want to mention the Elliott situation, but I think that was certainly a factor. But you guys got well in front of that with the targets that you laid out. So I want to get into some of those things. We'll give the audience a chance to ask some questions as well, but I wonder if I could just ask you guys. Your microphone looking. Go on, Brian. I think you're good. I think I heard what that was. Yeah. Okay. So, maybe I just want to ask you guys to give you a little bit of a state of the union, but I want to set it up a little bit for you. And Jeff and I had a chance to sit down in Houston a couple of weeks ago, so it shouldn't surprise him at all. But the theme of our conference this year is that two years ago we published a report called The Regional Golden Age of Refining, and it was anchored on cost advantage and capacity closures in the U.S. This year what we're trying to figure out is, are we entering a period where we've got elevated volatility as a new normal with higher highs, higher lows, and therefore another step up in a higher mid-cycle? And how are you positioned to navigate that? So that's kind of the high-level theme. But why don't we do a state of the union first on Phillips, and then we'll get into some of those questions. Okay, Doug, thanks. Thanks for the invite here. Is the sound check okay? Okay, good. Thanks. So for those of you that, maybe aren't as familiar with Phillips 66, we're, we're a diversified and integrated downstream company, and that's, that's what we, we like to, label ourselves as and really, frame up how we operate the business. That diversification and then that integration are key to our strategies to, increase, shareholder value. Then, in 2025, we've set some pretty aggressive goals out there, and what we're, what we're working towards is a, a EBITDA of, of, $14 billion. And that's, that's an improvement of $4 billion over historic, historical levels, with a cash flow from operations sitting at around $10 billion. So that, that those are our two big stated objectives here in the short term that we're working towards on that. And we're doing that through our diversification businesses. So we have four key businesses that we operate. One is refining, which I operate, and we've laid out a number of objectives to improve the refining performance here over time. We also operate a midstream business, which we have done a lot of activity on recently with mergers and roll-ups of MLPs and also a roll-up of the DCP operation under our umbrella. And then we have a very robust marketing and specialties organization, and then we're joint ventures in the chemicals operation with Chevron, and that's a big part of our portfolio as well. So as we work through our objectives, it's really hitting that EBITDA number is our core mission. This is a year of what we call execution. We've laid out a number of goals, and we'll probably work through those here as we work through the conference or this conversation. This year of execution is exactly the focus of our business. And you, Doug, you mentioned a little bit about Elliott's. We're most accountable toward that. We hold ourselves accountable to that as well. And that's exactly what we're working towards this year to achieve these goals. So, Jeff, anything to add to that? Yeah. I think, Rich highlighted the $14 billion of EBITDA over $10 billion of free cash flow or cash flow from operations, and we've committed to returning 50% of that to shareholders through dividends and share repurchases. Part of our initial commitment was returning $13 billion-$15 billion to shareholders through dividends and share repurchases, and we're on track to accomplish that by the end of this year. Okay. So, Rich, the focus, obviously, at least to begin with, we'll get into the refining business. And I want to, I want to get right into the weeds on a question that Jeff and I have gone backwards and forwards on, to try and understand a little bit about the step change in the targets for your mid-cycle refining business. What has been the legacy contribution of the two refineries that are no longer in your system, Rodeo and Alliance? So, good question, Doug. You know, that's always the question when you change your asset base and you divest or change the structure of those assets. But honestly, there's a reason we changed that structure for those two particular assets. So we did not reinvest in Alliance after the hurricane damage that we suffered there, and a better option for that facility was to convert it to a terminal operations, which we eventually sold to another outfit. What I will say for both of these assets is that the EBITDA, the earnings contribution, was not material to the mid-cycle basis for both of these assets. And that's why both of these assets have been on our radar, I'll call it, to understand how we can improve the earnings potential for the asset. Alliance, we decided to divest. Rodeo, we decided to do the conversion to renewable diesel and renewable, renewable production, both on renewable diesel and potentially sustainable aviation fuel. That conversion has transitioned that asset to be much more material to the earnings potential that the previous asset had lost its competitive advantage, primarily driven by the loss of domestic crude oil production in the state of California. That facility was built in 1896, and it was built to pro to run on that California domestic crude. And as the decline on that California domestic crude occurred over time, the crude advantage went away with that, and therefore the basic fundamentals, fundamentals underlying that facility, were no longer there. So we needed to do something to convert it into a, a, a higher earnings potential asset. I don't think we can beat up too much on the idea that TMX is now obviously going to change the crude dynamics a little bit, but because that decision was made a long time before. But, but I, I, I want to just spell out for everybody why I'm asking this question. Because when we look at your mid-cycle profitability, we think about everything on a per-barrel basis. And if you're basically saying that the EBITDA contribution from those two facilities was negligible, it means the per-barrel contribution from everything else was quite a bit higher. And I'm, I'm not sure that's well understood by the market. What would you say to that? I think that's a fair assessment. You know, if you layered in TMX with that, right, as part of that, so it was a very layered question here. But that's, you know, the fundamentals were there for, or have been there and historically have been there for these two sites. And the question about the TMX, does that change the crude advantage dynamics for the West Coast in a material way? And from our perspective, it certainly changes the product flows or the crude oil flows. It adds another dimension to the West Coast. But what was really setting that price for crude advantage was the California domestic crude production. And that'll set the baseline for crude advantage for the California facilities. And I don't see that changing. Matter of fact, I see that continuing to decline because the permitting capacity in the state has essentially gone to zero. So the producers are struggling to continue to produce at any level of material production and sustain existing production for that matter. So it's continually a challenge unless the political environment changes there materially that allows them to regain some of the lost barrels in that. So I do see that California crude setting the base for it. And then, the TMX, allowing an alternative crude supply into the West Coast, that will offset some other imported crude that comes to the West Coast. We're heading into a period of time what I'm going to call is uncertain. I think it'll be a little bit volatile, as the TMX pipeline opens up, as these changes in natural crude supply routes change. Then it's going to take a bit for the market to adjust to that. So I think we're going to head into a short period of time here, months, of uncertainty as we work through that change in dynamics. It'll be interesting to see how the market adjusts to it, honestly. That's a fair point. I want to hit the WCS. I mean, you're one of the biggest buyers of, obviously, of Canadian crude, so I'd like to hit that in a second. But again, I want to just make sure I spell this out. A lot of people are trying to figure out how you get to that $5+ billion mid-cycle refining number. And what I'm really saying is what I think the street has done is taken your historical, call it, six, seven, eight year EBITDA and looked at it on the capacity you had during that period and assumed that when you lose Rodeo and Alliance, that the proportionate profitability would be lower in absolute terms. But if you keep the EBITDA the same and you divide through by a lower denominator, profitability starts to close the gap with that $5.1 billion. So, that is, do you think I'm thinking about it the right way? I think you're thinking of it the exactly right way. Otherwise, we wouldn't be making moves on those assets. Okay. So that closes a big part of that gap. Now, the other part of the gap, of course, is you've got some growth projects. You've talked about a 5% increase in capture rate. It's very hard for us to see where that comes from, but you've also said a large number of those are already complete. So give us a status update. How do we benchmark it? How do we measure it? Okay. Just maybe start from the beginning on this. Back in November of 2022, one of the commitments that we made to improve the refining operation was improve our market capture by 5%. We said we were going to do that through a series of small-capital projects. Small capital is less than $50 million. That improve in targeting market capture. Then we've done it, for two years now. We've completed two years of that program, completed roughly 25 projects, I believe is the number, and captured a little over 3% of market capture improvement to the baseline, the mid-cycle pricing. So we bring everything back to mid-cycle pricing. Again, so what does that mean? It's basically broken into several categories. But the two primary categories that we're focused on for improving market capture are increasing the clean product yield coming out of our facilities. You're starting to see that flow to the bottom line, honestly, Doug, because in the fourth quarter, we reported an 87% clean product yield for our assets across the entire refining system. That is the highest clean product yield that we've experienced in our refining system by 1%. And 1% is a big number across all our barrels. So we're starting to see these projects come through and start to materially hit the bottom line. So product, clean product yield's one of those key components for us. The second component that we are really focused on is product value. So are we producing the product with the highest value? And another example that I can show you that it's actually flowing through the financials, and it's difficult to see these things. I wish it was easier, but it's a big system, and it's hard to see small-capital projects. It's fourth quarter. We had 40% distillate yield, and we also maintained high gasoline yield in the same period of time. So we did not sacrifice our gasoline yield, and we were able to maintain a 40% distillate yield across our system. That is the first time we've ever achieved that as well. And that was the highest distillate yield from a machine that is designed to produce distillate. So each of these little projects have allowed us to upgrade either into distillate or into gasoline. So everything's kind of trickling against each other, pushing up the value chain. And we're starting to see that flow through the numbers. We saw those two good symbols or signs in the fourth quarter of last year in the earnings numbers that we reported. So basically, just to put that 40% diesel yield in or distillate yield in perspective, industry average in the U.S. is about 33%. So it's a substantial increase in distillate relative to the industry average. You've always been a heavier distillate producer anyway, right? I mean, a higher distillate producer. Don't use the word heavy with a refiner. It gets all messed up when you do that. But so basically, what would it be right then to say, Rich, rather than trying to focus on an incremental EBITDA number from that capture rate, what we should be looking at are the operational metrics, like the fact that your light product yield is up, your utilization is up, your distillate yield is up. Those are the kind of outputs? Those are the inherent signs that the programs are starting to work, right? Now, directionally, that should, over time, change the market capture number, which directly relates to the earnings potential of the assets, right? So now, market capture is another very difficult one to keep a close eye on. So you got to really watch the average over time is the best way to look at that metric. It's highly affected by the current market pricing. So that average over time is what I'm focused on in driving that average up, across the system. And the reason I stay focused on that I'm an engineer, but I like to give the organization something that they can focus on and do it in a way under things that they actually can control, right? We cannot control the marketplace. But what we can control is our Clean Product Yield. We can't control what products we're making. We can't control our asset availability. And are we ready to be in the market when the market's there? And when the market's not there, you know, you'll see, you'll see that market, not give and, and we'll adjust our utilization, whatever makes right sense for the marketplace. But, but being available to operate in that market and then making the right products is the key message that I'm giving the organization. I want to go to some of the cost-cutting targets in a minute. Thank you for that answer. But I want to finish off on the capture rate topic for a minute. What one of the things that's kind of seems to be coming up more frequently in discussions now is the quality of domestic U.S. crude. The fact that midstream companies, which you obviously know more better than others, are blending down the quality for pipes, pipe spec crude oil, such that your utilization rates are being impaired by, you know, essentially flooding your crude unit. Does that make any sense to you in what I'm trying to describe that? For example, the U.S. is producing so much NGLs that you're blending down to the minimum possible pipe spec, and what you're getting is not giving you the same product yield. Any truth to that? Well, honestly, Doug, that's nothing new. That's been going on for decades and decades and decades. What's important about that is to make sure you maintain your relative crude valuations to the type of crude that you're actually getting. You can't use an assay that you ran 10 years ago on a certain particular crude and then run your valuations based on your yield profile from that. You need to continually update that and continually look at it. And that's what we do. And then we continually evaluate that based on our yield structure that we see in the current crudes and then the, you know, the relative crude value that generates for us. So it's an important part of the process to stay optimized across the system. Yeah. I think the issue that was being brought up was that there's been so much NGL growth in the U.S. that it had stepped to a different type of. The problem had become bigger. Well, if you do, you see a lot more gasoline production across the system in that and, as well as, eventually those come out through the refining system as NGLs too, right, through into fuel gas systems or into butane production or propane production across the system. We have seen an increase in that, obviously. And I relate it primarily to the gas-to-oil ratios. If you watch those metrics closely, you'll see the gas-to-oil ratios are certainly picking up, especially in the Permian Basin area. So my expectation is that those ratios will also pick up in the actual crude that's delivered to the refinery as well. And you got to be prepared to handle those. So what's really nice for us is we're integrated with our NGL systems. That allows us to move those barrels into the NGL system through that integrated process. Then we also have the integration with our CP Chem facilities as well and allows us to move into petrochemical feedstocks, so. This is uniquely able to navigate this if it is in fact getting worse. So let's go back to the WCS system. Our question we touched on it for the West Coast, but as one of the biggest buyers of WCS, are you concerned about what TMX does to your lower 48 system as ex-West Coast? I'd say no to that. We believe that the incremental barrel for WCS will continue to clear through the Gulf. For those of you that don't know, we are the largest consumer, I guess, or purchaser of WCS crude oil. And a lot of that does flow through to our MidCon and our Gulf Coast assets. And we still see that as very competitive, with the alternative crudes that are potential to come into those areas. And we still see plenty of supply. Where we do think the TMX pipeline will impact is the amount of crude that's exported out of the Gulf Coast, that is currently at a pretty good clip, actually, that comes out of the West Coast. So we see that potential to export, maybe being diverted over to the West Coast. Or that's where we're going to need to understand how the market's going to adjust to this new supply outlet and how is that going to change the crude dynamics across the world, as alternatives are evaluated versus this new outlet on the West Coast. And it's going to be interesting to see how that works out. I, you know, we've only had a few years to think through this, and you'll think we've had it figured out by now. But I think, until it actually hits the market, you never really know how the market's going to react to it. So it'll be an interesting ride here over the next six months, in our opinion. And I think we're going to head into some period of volatility. But as far as our MidCon and our Gulf Coast assets, we still see WCS as quite attractive crude for that, for those facilities. We do see the forward curve consistent with the forward curve that's out there published around $14 a barrel differential, on WTI/WCS. That seems reasonable to us. And if you really think about why that is reasonable, it's really two key reasons. One is it's the transportation differential to get the WCS down to the WTI market. And it's the quality differential. So $8-$9 for transportation, $4-$5 for quality differential. Maybe talk about some of the benefits of getting crudes on our West Coast system. Yeah. So we talked a little bit about the West Coast and the California domestic crude supply, which a lot of the facilities on the West Coast are designed to run. But that crude, over the last 30 years, has gone from 1 million barrels a day down to 400,000 barrels a day. So it's been a 60% reduction in crude processing or production in the California market. That's cleared the crude advantage that historically had been there on that crude and made importing crude a little bit more obviously more reliable, I guess the pricing more competitive, for the worldwide crude markets. We do think that the TMX outlet and the crude that's going to come from that is really going to compete versus that alternative imported crude that generally comes from South America. Some of it may come from the Middle East, but most of it comes from South America. And it's going to really compete against that. And where it settles out on crude prices is probably the uncertainty in all this, in that delivered price into that market. So, a sour crude. California's typically heavy sweet. Do you guys have the capability to run that? Or because, you know, some of your competitors have said there's going to be some facilities on the West Coast that can't run it. We're still trying to figure out who it is because everybody seems to be able to run it. Not us. I mean, we can run it. I mean, our facilities were built on California domestic crude, which is San Joaquin Valley heavy, which is 13 gravity and, you know, 2% sulfur. So i t'll be a blend, probably, coming down as well. So, I guess staying given that we're on the West Coast, let's just kind of stick there just for a minute and maybe jump over to renewable diesel. We've had a lot of discussion today about what's driving down renewable diesel margins, the whole, you know, the BOHO spread and all the things that are behind that. How do you feel today, sitting here today, about your $700 million mid-cycle EBITDA forecast for Rodeo? Okay. So, let me, I'll start back here a little bit farther on that and then build, build to your answer, Doug. So when we decided to convert the Rodeo facility, as it was for reasons that I talked about earlier, it wasn't a competitive site. But it was uniquely positioned in a couple of things. One, it's geographically located. So it's in the California market. Two, if a refinery has a hydrocracker, which is the key conversion unit for renewable diesel, they have one. This facility actually has two hydrocracking facilities. So the capital conversion was going to be very efficient for this. And three, it's in the right market. We have a healthy presence in the marketplace. And we control that market. Don't control the market, but we control the barrel all the way to the marketplace. So, we're not leaking value as it moves through the different various chains, to get to the retail customer or the commercial customer, whoever that is. So, we felt we had the right project in the right location to do this. And now you think about the feedstock side of this thing. So in 2021, we actually started in the renewable diesel business, production business. We started this on a unit we call Unit 250. That unit primarily runs on treated feedstock and allowed us to do two things. One, learn about the processing requirements. And we've learned a lot technically, but probably more importantly, more about the market, and especially on the renewable diesel side. So that's after being in that for just a short period of time, we learned very quickly that you need to own the last mile of delivery to the retail stations. That way, you don't have the leakage of value. So we've been growing out that retail presence in California to control that last bit. On the feedstock side is the other most important part of this. We own, or we operate four trading facilities or trading centers for us across the world. One in Houston, one in Calgary, one in London, and one in Singapore. All four of those sites over the last two years have been actively trading in the renewable feedstocks. So we've honestly been very long in that market as we developed our market intelligence, developed aggregation facilities across the world, and developed a relationship with suppliers. What we learned very quickly, Doug, was that the relationship of the price of the feed is very relatable to the LCFS credit and the RINs credits. So the credit markets and the feedstocks are having this loose relationship as we develop it. So when you go now into the full economics of the project and how we feel about where we're at today, we feel. I feel very bullish about it, honestly. We have this clear understanding of feedstock, feedstock pricing as it relates to our credit market. So we feel very good that we get feedstock at a competitive purchase price. And we have the ability to treat that raw feedstock at the facility that's part of the project, which is a pretreatment facility. That relationship is very, very tight. The other relationship, understanding you need to own the barrel all the way to the retail market or the commercial market, we built that out too. So we built out both sides of this equation as we've been developing the project in order to preserve value of the when we originally did the economics for the project, we only based it off of the two state programs, LCFS, Low Carbon Fuel Standard, and the Cap and Trade Program that's in California, and the RINs program federally. What we did not include in our economics was the Blender's Tax Credit or the IRA contribution. Just globally, right? Yeah. But replaced with the IRA, right? So, that now has layered into our economics since Congress has actually passed that rule. So there's more certainty into the outcome of that. And, that's given us a level of economic incentive now that we feel very, very strong that the project's going to perform at or very near its original intention. So the current weakness, I mean, current weakness in renewable diesel margins is obviously presumably that's not the base case for the $700 million. No, it's not. But neither was that Blender's Tax Credit. So that's now added into that base case. And the other thing that you got to keep in mind is just the pure diesel price on the West Coast as well, which is strong in the market there. So is it going to be all the way to the top? It's always hard to tell, forecast those things. But it's not through the floor either. It's probably somewhere well above the middle towards the top in our current view of this project. So, I want to go to the cost, the progress on cost reductions and then go back to the mid-cycle target and talk about the margin environment. Would that be okay? I'll let Jeff answer that mid-cycle. Yeah. So, well, it's really—it's really more about how you define the $5.1 billion. Was it defined on an average of the profitability of your portfolio, or was it defined benchmarked on a crack spread? But like I say, I'll give you some time to think about that while we talk about cost cutting. So the $1.4 billion for the corporation, where are you today? I know you've made extraordinary progress, which leads me to think that there's got to be an upside, another upside to that target, which you've already raised. Well, as you go along this journey, it gets more and more difficult. So through last year, we achieved the $1 billion run rate on cost reductions out of our system. And this is part refining and part marketing, part midstream, and, you know, the corporate structure around it. So we feel, you know, 100% confident that we have that run rate in the bank. Now we're watching it very closely, making sure we're executing that so it flows through the financials, right? That's the real answer, right? When we all can see it in the financials, we'll raise our hand and declare that we've made success on that. But we are, as I sit here today and the executive leadership team, very confident that we have hit our goal, and it's working its way through the financials. We have raised that goal for this year, up to $1.4 billion, as Doug indicated in his question. What's our certainty on hitting that? I feel very strongly that we will hit that. I think you said you're 85% of the way there, right? Yeah. That's why I feel very strongly. Yeah. Yeah. We have an organization that has really embraced this process. I think we unleashed some energy in the organization that we didn't all understand was really pent up. Most of the time when you think about these cost reductions, extra funds, you think of them as a cost reduction, which is a resource-constraining exercise from the folks in the field, right? That's generally how they would think about this. Instead, we unleash them to say, "Hey, where are we spending money where we should not be spending money? And let's get rid of that." It actually makes your job a little bit easier. It actually takes work away from the job and simplifies the day-to-day process. It's taken us a while to get the organization to realize that, but now they've realized that. They've embraced that process. We continue with this very good momentum in the organization on reducing things that we should not be doing, essentially. People have realized that. So we had great momentum rolling into the end of the year. We had a pretty good line of sight that, "Hey, this thing's going to carry on" is under self-momentum almost for a bit more. So we saw that with the 85% complete already. Let's add a little bit more to it to be aggressive but achievable, was our expectation for this. That $1.4 billion target is very, very achievable, in my opinion. I don't want to put you on the spot, but it seems that there is the body language, the listening to Mark and Kevin talking about it. It seems that you're headed towards another upward reset in that number. Why would I be wrong on that? Is that too presumptuous? Well, it's a little presumptuous. Yeah. You know, is there a potential? There's certainly a potential for that. We'll announce that when we think it's right, both for the market and for the organization. But we also want to make sure that we're keeping the organization motivated. There's really two things you need to think about inside a business, when you're thinking about it internally. One is cost. That's important, right? But the other is earnings. And are we really capturing the amount of earnings, the value of our assets to the highest optimal position? So I think there's a balance between, you know, getting the organization too focused on costs and losing sight of the value proposition as well. So, you'll see us transitioning towards this value proposition approach, as we work through this cost reduction process. Sometimes there's good costs, right? Yes. Yeah. So it may, right. You may actually see increase in cost, if the right value's associated with it. So, Doug, I think to your point, there's a change in culture associated with this business transformation that we're going through and really a focus on continuous improvement, which is intended to carry on for an extended period of time. And so I think that speaks to future opportunities. Just so I understand, sometimes it can be too simplistic to say cost reduction, but sometimes cost increase, which has a multiplier effect on profitability, is. Cost optimization. Right. Right. So we've only got a few minutes left, guys. So I want to go to Jeff on the mid-cycle question, but I'm going to come back to you, Rich, for the last question. I just want to give you a heads-up what the question is, right? Phillips went through a period where reliability was a problem. It was perceived to be an issue. It's long since I think you're a year and a half in now that you've had tremendous, you know, recovery in that metric, if you like. And the question really is around the portfolio. Are you happy with the portfolio today? And that includes buying and selling. And of course, I've got CITGO in the back of my mind. So I'd like maybe just think about that for a second while I go to Jeff on the mid-cycle. That's kind of where I wanted to finish. Jeff, are we in a higher mid-cycle in your view? I'm asking you to put your sell-side hat on here. I think, as we look out on new capacity additions with the capital discipline that we've seen across the sector with the concern about energy transition, the industry is not announcing new capacity additions in near as meaningful a way as it has historically. When we look at net capacity additions, we've got about 1.5 million barrels a day this year. We've kind of got Dangote and Dos Bocas. We're assuming about 50% of it comes on this year, 50% comes on next year. I think as we look at what's happening, particularly at Dangote, is it's running the crude unit initially and testing crudes, not likely to run the downstream units in any meaningful way until later in the year. So it's putting kind of low-quality intermediates into the market, which for high-complexity refining is a positive. The actual performance of those two facilities, I think, is a big question mark. I think it's going to be challenging for them to run these types of assets. But, but we'll see how, how that plays out. But as we look at 2025, 2026, 2027, 2028, there's 1 million barrels a day or less per annum of new capacity planned. And so a very light program. It's about a 5+ year lead time for construction of a new facility. And so we've got pretty good visibility on capacity adds. And as you think about demand for this year, the IEA is at 1.3 million barrels a day. They've now increased their expectations four months in a row. So, despite, I think, significant concerns about the U.S. and global economies, the economies are holding up reasonably well. We've seen port activity start to trend higher at the Port of Long Beach and Port of LA, which are signs for new product coming into the West Coast that will then need to be transferred by rail or ship across the country. So it's a good leading indicator of diesel demand. We've seen trucking activity pick up a bit. Cargo activity on airlines is strong. And so it looks as though the economic outlook and the oil demand outlook have been trending back in a more favorable direction. So demand looks healthy. Oil prices are relatively low, which will certainly not discourage demand at this level. And not a lot of new capacity coming into the market. So I think. We don't know what the closures are going to be either on the other side of the thought if we're coming to the end. Yeah. You know, we're continuing to see closures. You know, one domestically scheduled for next year, one in Asia. We've got three now in Europe scheduled to come down next year. What are the three? Grangemouth or what are the other two? There's one in Italy and Germany and, Grangemouth. Yeah. The U.K. Yeah. So those three. Are we in a higher mid-cycle? At least a more volatile mid-cycle. I think that argues for a constructive environment going forward. Yeah. Why hasn't Phillips taken up its mid-cycle assumption? I tell you, we looked historically, and we really designed our mid-cycle methodology around the 2012 to 2019 time frame. You had cycles of strong margins and weak margins during that period of time. You come to 2020, and, you know, once every 100-year kind of a pandemic event. So that's a really unusual year. 2022 was unusual with the Russia-Ukraine involvement and the loss of natural gas into Europe and the spike of prices there. So we've had some really unusual years. So I think we're kind of battling around how do we factor all this in to how we look forward. In your norm. Yeah. I think as we talk about mid-cycle, we've got that 2012 to 2019 period. We generated about $4 billion a year of EBITDA during that period. With Rich's efforts on cost, on market capture, on commercial, we're adding $1 billion of incremental capability with that. So that's kind of how we get to the $5 billion. Right. That makes a lot of sense. I appreciate the answer. I know we've gone a little bit over time, Rich, but just I do want to give you a chance to answer the portfolio question very quickly. Well, for all the reasons that he just laid out, and I won't go through those again, we're bullish on refining, right? So, so we see. As are we. Yeah. I might have figured that out. Yeah. So, you know, when you think about portfolio management, all assets are always under evaluation, right? And that's what good stewards of the assets do. Our strategy is this integration where I started off with, an integration strategy. So, the closer we are and the more highly integrated we are with our assets, the higher that valuation will be in order to, you know, if there's third-party interest in that particular asset. And also, would I exclude interest from our part? If we see an asset that could highly integrate into our existing structure, we would certainly evaluate that as well. So, I'm going to play both sides of this one, Doug, and say that, you know, if the right deal comes through, you know, we're always open for luck. So let me put you on the spot. I thought we were out of time. Oh, we are. All right. Real, real quick. So Tom Nimbley sat there and said we asked for the data book on CITGO. Did Phillips ask for the data book on CITGO? I haven't seen the data book on Citgo. Okay. Guys, thanks very much indeed. I appreciate the time. Thanks.