Phillips 66 (PSX) Earnings Call Transcript & Summary

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? Don't tell [ Marianna ] I said that. I'm kidding. Joking aside, thanks very much, indeed, for being here guys. So Jeff Dietert, Head of Investor Relations, shouldn't be a stranger to 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 I've been doing this. So Jeff, thanks very much for being here. Rich Harbison who, of course, runs the refining business. Probably the topic de jure as it relates to a lot of things that have happened in the last year or so, I guess, 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. So maybe just ask you guys to give you a little bit of a state of the union, but I want to set up it 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 2 years ago, we published a report called the regional gold major 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, higher highs, higher lows and therefore, another step up in the 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 for the invite here. Sound check, okay? Okay. Good. So for those of you that maybe aren't as familiar with Phillips 66. We're a diversified and integrated downstream company, and that's what 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. In 2025, we've set some pretty aggressive goals out there. And what we're working towards is an EBITDA of $14 billion and that's an improvement of $4 billion over historical levels with a cash flow from operations sitting around $10 billion. So those are our 2 big stated objectives here in the short term that we're working towards on that. And we're doing that through our diversification of businesses. We have 4 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 roll-up of the DCP operation under our umbrella. And 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. And best year of execution is exactly the focus of our business. And Doug, you mentioned a little bit about Elliott almost 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?

Yes. 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 to $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 get right into the weeds on a question that Jeff and I have gone backwards and forwards on. So trying to 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 2 refineries that are no longer in your system, Rodeo and Alliance?

So good question, Doug. And 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 change that structure for those 2 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. The -- so what I will say for both of these assets, 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 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 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 underlying that facility were no longer there. So we needed to do something to convert it into 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 that decision was made a long time before. But 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 2 facilities was negligible, it means the per barrel contribution from everything else was quite a bit higher. And I'm not sure that's well understood by the market. What would you say to that?

I think that's a fair assessment. If you layered in TMX with that, right, as part of that, so a very layered question here, but that's -- the fundamentals were there for -- or have been there and historically have been there for these 2 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, 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 will set the baseline for crude advantage for the California facilities. And I don't see that changing. A 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 continuing to 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 will be a little bit volatile as the TMX pipeline opens up, as these change in natural crude supply routes change, 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. And it will be interesting to see how the market adjusts to it, honestly.

It'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-plus billion mid-cycle refining number. And what I'm really saying is what I think The Street has done is taking your historical, call it, 6, 7, 8-year EBITDA and looked at it on the capacity you had during that period and assume 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 is that -- you think I'm thinking about it the right way?

I think you're thinking of it exactly the right way. Otherwise, we wouldn't be making moves on those assets.

Okay. So that closes a big part of that, yes. 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 on how do we benchmark it, how do we measure it?

Okay. Just maybe start from the beginning on this. Back in November of '22, 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 improved and targeting market capture. We've done it for 2 years now. We've completed 2 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 2 primary categories that we're focused on for improving market capture are increasing the clean product yield coming out of our facilities. And 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 is 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 distillates. So each of these little projects have allowed us to upgrade either into distillate or into gasoline. So everything is kind of trickling against each other, pushing up the value chain. And we're starting to see that flow through the numbers. And we saw those 2 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 -- our distillate yield in prospective 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, the higher distillate producer that [ don't use it ] but were heavy with the refinery, [ your own messed up EBITDA ]. But so basically, 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've 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 control what products we're making. We can control our asset availability and are we ready to be in the market when the market is there. And when the market is not there, you'll see that market not give, and we'll adjust our utilization whatever makes right sense for the marketplace. But being available to operate in that market and then making the right products is the key message that I've given the organization.

I want to go to some of the cost-cutting targets in a minute. Thank you for that answer, but I wanted to finish off on the capture rate topic for a minute. One of the things that's kind of seems to be coming up and more frequently in discussions now is the quality of domestic U.S. crude, fact that midstream companies, which you obviously know better than others, are blending down the quality for pipe spec for the oil such that your utilization rates are being impaired by essentially flooding your crude unit. Does that make any sense to you 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 to 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 relative crude value that generates for us. So it's an important part of the process to stay optimized across the system.

Yes. I think the issue that has been brought up was that there's been so much NGL growth in the U.S. that it had stepped to a different type of [ enrollment become bigger ]?

Well, if you do, you see a lot more gasoline production across the system and as well -- and 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. I -- 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. 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. And then we also have the integration with our CPChem facilities as well and allows us to move into petrochemical feedstocks.

This is you uniquely able to navigate this if it is, in fact, getting worse. So let's go back to the WCS system or 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 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 Mid-Con and our Gulf Coast assets, and we still see that as very competitive with the alternatives 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 is 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. We've only had a few years to think through this. And you'll think we had it figured out by now. But I think until it actually hits the market, you never really know how the market is going to react to it. So it will be an interesting ride here over the next 6 months in our -- in my opinion, in our opinion, and I think we're going to head into some period of volatility. But as far as our Mid-Con 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 is that reasonable, it's really 2 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 $9 -- $8, $9 for transportation, $4, $5 for quality differential.

Maybe talk about some of the benefits [ it created on ] West Coast.

Yes. 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 -- up 400,000 barrels a day. So it's been a 60% reduction in crude processing and 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, more -- 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. And 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 and that delivered price into that market.

So crude, California is typically heavy suite. You guys are -- do you have the capability to run that? Or -- because 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 is used 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 [indiscernible] Valley heavy, which is 13 gravity and 2% sulfur. So it's -- we'll probably cover that as well.

So I guess, this thing, given that we're on the West Coast, let's 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 [ 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 -- I mean I'll start back here a little bit further on that and then build to your answer, Doug. So when we decided to convert the Rodeo facility 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, 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 2 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 2 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 4 trading facilities or trading centers for us across the world, one in Houston, one in Calgary, one in London, and one in Singapore. All 4 of those sites over the last 2 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 we go now into the full economics of the project and how we feel about where we're at today, and 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've 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 2 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 blenders tax credit or the IRA contribution...

[indiscernible], right?

Yes, 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 is going to perform at or very near its original intention.

So the current weakness and -- the 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've 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. And 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? So...

I'll let Jeff answer that mid cycle.

So that -- well, 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 just a defined benchmark on a crack spread? But like I said, I'll give you some time to think about that when 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 going 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 -- but -- so through last year, we achieved a $1 billion run rate on cost reductions out of our system. And this is part refining, but part marketing, part midstream and the corporate structure around it. So we feel 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. And -- but we are, as I sit here today and the executive leadership team, are 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. And what's our certainty on hitting that? And I feel very strongly that we will hit that.

I think you said you were 85% of the way there, right?

Yes. That's why I feel very strongly, yes. We have an organization that has really embraced this process. And 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 [ form ], you think about it as a cost reduction, which is a resource-constraining exercise from the folks that are 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 and where we should not be spending money. And let's get rid of that, and 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 and we continue with this very good momentum in the organization on reducing things that we should not be doing essentially. And people have realized that. And so we had great momentum rolling into the end of the year. We had a pretty good line of sight that, hey, this thing is going to carry on under self momentum almost for a bit more. So we saw that with the 85% complete already. And let's add a little bit more to it to be aggressive but achievable was our expectation for this. And that $1.4 billion target is very, very -- is 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. Why would I be wrong in that? Is that being presumptuous?

It's a little presumptuous, yes. 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 2 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 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.

Sometimes there's good costs, right?

Yes. Yes. So it may, yes, right. You may actually see increase in cost if the right value is associated with it.

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 and -- which is intended to carry on for an extended period of time. And so I think that speaks to future opportunities.

I understand sometimes it can be too simplistic to say cost reduction, but sometimes cost increase, which has a multiplier effect on profitability...

Cost optimization.

Right. Right. So we've only got a few minutes left, guys. So I want to do -- 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 think 1.5 years in now that you've had tremendous 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 a segment 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, but that's kind of what I wanted to finish. Jeff, are we in a higher mid-cycle in your view, and I'm asking you put your sell side hat on.

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 years meaningful way as it has historically. And 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 2 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 we'll see how that plays out. But as we look at '25, '26, '27, '28, 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-plus 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 4 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 that.

Yes, we're continuing to see closures. One domestically scheduled for next year, one in Asia. We've got now 3 in Europe scheduled to come down next year.

What are the 3? Grangemouth? What are the other 2?

There's one in Italy and Germany and...

Grangemouth.

Yes. Yes. U.K. Yes. So those 3.

So are we in a higher mid-cycle, somewhat volatile mid-cycle?

I think that argues for a constructive environment going forward. Yes.

Why hasn't Phillips taken up its mid-cycle assumption?

I'd 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 a 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. I think as we talk about mid-cycle, we've got that '12 to '19 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. So I know we've gone a little bit over time, Rich, but just do you 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 we see...

As are we. I figured out.

Yes. So 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 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 -- if there's other 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 if the right deal comes through, we're always open for a [ lot ].

Let me put you on the spot.

I thought we were out of time?

Are we? Real quick. So Tom Nimbley sat there and said we asked the data book on CIDCO. Did Phillips ask for the data book on CIDCO?

I haven't seen the data book on CIDCO.

Guys, thanks very much indeed. I appreciate the time. Thanks.