PSX - Phillips 66 (PSX) Presents at Bank of America Securities 2023 Refining Conference (Transcript)
Phillips 66 (PSX)
Bank of America Securities 2023 Refining Conference
March 02, 2023 12:00 PM ET
Company Participants
Jeff Dietert - VP, IR
Rich Harbison - SVP, Refining
Conference Call Participants
Doug Leggate - Bank of America
Kalei Akamine - Bank of America
Presentation
Operator
[Operator Instructions] At this time, it is my pleasure to turn the program over to your host, Doug Leggate.
Doug Leggate
Well, thank you, Eric, and good afternoon, everyone, or good evening, if you’re in Europe. We really appreciate you joining us for our next session, which is with Phillips 66. And I mentioned earlier, this is our 20th year hosting this refining dedicated conference for the independent U.S. refiners. But we wouldn’t have a conference that it wasn’t for these guys participating.
So Jeff Dietert, our Vice President of Investor Relations. I’m sure he’s known to everyone very well. Prior respected sell-side competitor many years ago, has made the has made team available for us today. So thank you for that, Jeff. And we have, as our guest speaker, Senior Vice President of Refining, Rich Harbison.
I think, Rich, you may want to remind me just how long now you’ve been in that spot.
Question-and-Answer Session
Q - Doug Leggate
But I want to kind of kick off with a high-level question and ask you as a guy who’s been in this business for a very long time, how do you see this cycle versus what you’ve seen, let’s say, over the prior 10 years? Are there any notable differences? But thank you guys for being here.
Rich Harbison
Yes. Thanks, Doug, and I appreciate the opportunity to speak to the group. Maybe to answer your first question, I’ve been in the business for coming on 35 years now. So I’ve seen a bit over my years, but actually been in this particular role a little over 8 months now. So it’s been a quick 8 months, and it’s again, a pleasure to talk to the group here.
This cycle, when I think about it, and you really have to layer in really the effects of the COVID -- I’ll call it the COVID hangover almost. During that COVID period, we saw a lot of supply in production really drop offline, get rationalized off of it, would kind of accelerated that rationalization as demand dropped off and the high-cost producers were essentially forced to shut down. And that really accelerated a supply and demand rebalance then what has traditionally been in place during the cycle. As we think about it moving forward here and there’s always this, call it, concern of recession and which typically hits the energy markets on a supply and demand basis, we’ve kind of been prerationalized, I’m going to say, on this cycle with that reduction in supply and the demand kind of picked up and our relationship to that demand cycle is different than where maybe other cycles have started when you roll into a maybe a recessionary type cycle that may or may not occur here over the next 12 months or so.
So we see us starting in a bit of a different spot than what traditionally we have on a down cycle, if you presume it’s going to a down cycle. And that -- in this case, it would move us probably more to an imbalanced supply and demand scenario versus an oversupply and a reduced demand scenario. So it’s a little bit different way to think of it on a global basis. And so I think we start in a different spot there, and that then puts me, when I think about mid-cycle pricing, really kind of moves us to a mid-cycle pricing scenario or maybe even a slightly better mid-cycle pricing scenario, even moving through a potential slight recessionary period on this cycle. So that’s kind of the way I’m thinking about it right now, Doug.
Anything to add to that, Jeff?
Jeff Dietert
Yes. Just to put some numbers around it, we talk about mid-cycle being the average of 2012 to 2019, and the average RIN-adjusted 3:2:1crack was $12 a barrel during that period of time. And we just completed January and February, which are typically 2 of the weaker months of the year, and we’re over $20 a barrel on a RIN-adjusted crack, and so a very healthy environment to start the year. As we look at capacity additions, we see net additions at about 500,000 to 600,000 barrels a day, mainly Middle East, some China capacity coming on late in the year. We’ve got capacity being added in the U.S. this quarter. And -- but it’s not an overwhelming amount of capacity. And when you look at the IEA, they’re talking about 2 million barrels a day of demand growth in 2023. About 1 million barrels a day of that is in China. So we’re watching that carefully.
And the indications in China, I think, are better than we would have thought a few months ago with the PMI just came out. It’s the strongest PMI since 2012. When we look at demand in the major cities, they track road travel, and it’s ramped up above pre-pandemic levels. The flight schedules are very robust going forward. So the indications are pretty positive, I think, coming into this period in China.
And there is some excess capacity in China that probably runs, but I think we’re going to need it to run. So as we think about 2023, we believe we’re probably above mid-cycle for this year.
Doug Leggate
I have to pick up, Jeff, if you don’t mind, on those numbers. The 500,000 to 600,000 sounds a bit low on a net basis. What are you assuming in there, if you don’t mind me asking? I know this is a bit of a big picture question. But obviously, we know about Kuwait. We know about Nigeria. We know about Mexico. But it seems that there’s a lot of question marks over the timing of those start-ups. And then the utilization rate once they’ve cut the ribbon, so to speak. So what are you assuming in there?
Jeff Dietert
Yes, it’s a great question. Kuwait, we’ve got the first of 3 units is already operating. The second one is expected first 200,000 barrel a day operating now, next 200,000 barrel a day later in the first half of this year and then the third at the end of next -- end of this year. So we’ve got all that factored in. China, there are a couple of big facilities coming on late.
We believe that some of the other international projects get pushed out into 2024 and maybe even 2025. There’s some unique and challenging structures for one of those facilities in particular. So that’s our assumption on the timing there. We’ve got Mexico and Nigeria further out, not starting this year.
Doug Leggate
So when you guys think about planning your business, and Rich, you kind of jumped right into the higher mid-cycle. When you look about the role of refining within the portfolio, Phillips has been taking refining capacity offline with Alliance, obviously, had the storm, and this year, Rodeo. Does the portfolio stabilize after that into this higher mid-cycle?
Rich Harbison
It’s a portfolio question. It’s a good question, Doug. I think when we look at our portfolio, we like it. We have high complexity in our portfolio. We actually have the ability to run a variety of crudes from light to medium to heavy. We’re spread across the different pads. So we’re not subject to one regional differential in the U.S., and we have exposure in Europe as well to that. So -- and we have a very high distillate yield from our portfolio, which we’re very bullish on the long term. Now the question always is and always should be, are we getting the highest level of return on capital employed with our assets. And obviously, we made the decision for the San Francisco Refining system to convert to a different operating model there, which we’re quite excited about and I think it really positions the asset and the long-term viability of the asset as well as preserves the jobs for the organization in that area.
And we’re quite constructive on that business as it moves forward. I mean going in a little bit more detail here in a few minutes, I guess, on what the timing of that is and how that’s gone. But -- and then we think about the U.S. in general, right, versus worldwide competition, and we think the U.S. is positioned in a very strong advantage, actually, especially around the cost of energy, right?
Natural gas price is quite favorable for our operations as especially compared to Europe, right? Even though Europe price has come down quite a bit, we still have a nominal $4 a barrel advantage over that, which makes U.S. refineries quite competitive worldwide. And of course, we have the scale within our systems and this complexity issue. So if you ask me, are we happy with the portfolio?
Yes, I think we are happy with it. Are we always looking to continue to optimize it and increase earnings and reduce operating costs? Absolutely. That’s all part of being a competitive business that we’re in.
Doug Leggate
So one of the key -- I guess, before we get into the actual operations, we’ve got -- I was just looking at the screen there. If you saw me glancing down, we got $42 heat cracks and $34 gasoline cracks in March -- I was going to say, in January. How much lower in January?
Rich Harbison
But it’s already March, Doug.
Doug Leggate
How do you think that is?
Rich Harbison
Well, I think it goes back to what I was talking about earlier about the supply rationalization that has occurred from that COVID period, the 4.5-roughly-million barrels off the market worldwide, 1 million plus in the U.S. So that has kind of rebalanced the supply and demand. When we look at supply and consumption, we see the gasoline market year-over-year kind of recovering and being at par with each other. It’s flat, call it, not growing, but flat at a nice healthy level. We do see diesel coming down a little bit.
So there is, I think, continuing pressure on the inventory at diesel, but the demand we’re seeing to kind of come off a little bit with our forecast for the year. There are -- there is a scenario, honestly, Doug, that we think you could see gasoline flip to the lead indicator this year. And as the gasoline driving season kicks in and the maintenance periods are end up, we do see a potential scenario where that could play out. Since the COVID period, we essentially been in a strong distillate crack scenario, and we’re going to continue in that strong distillate crack scenario until we actually see that change over to gasoline. But there is a scenario that plays out in our numbers that could happen this year, as early as this year.
Doug Leggate
No. Not Consider...
Jeff Dietert
Jet’s leading right now and then diesel and then gasoline in the forward curve, but we’ll monitor that and adjust as those things change.
Doug Leggate
So just -- I don’t want to get too granular here, but so -- you obviously have a distillate advantage relative to many of your peers, as you pointed out. Are you still running a max distillate slate right now? Or when would you...
Rich Harbison
Yes. Yes. Yes. We have a max distillate signal. We have been for quite some time and will continue until we see that gasoline signal change. And one thing -- I’m glad you brought up the jet, Jeff. Jet is also part of that -- we consider that part of that distillate pool when we’re talking about distillate production, right? So jet production, we do see is kind of the leading indicator here as the market continues to recover. And especially when we see the long hauls going into China and coming out of China, we think that is quite constructive moving forward here.
Doug Leggate
Those robust margins are great, but you’ve got to have the reliability and the efficiency to be able to take advantage of that. I think there were probably some questions over what’s been happening to Phillips 66 towards the back half of last year. So maybe you could just address that right up front. I realize maintenance was a part of it, but how would you characterize your reliability and your efforts to ensure they have the mechanical availability of the plant?
Rich Harbison
Yes. Yes. Thanks. Thanks, Doug. Yes. Obviously, you’ve got 2 components to that, right? You’ve got the planned maintenance component. You got the unplanned maintenance component. During the Investor Day back in November, we talked a lot about the 3 key goals that we had laid out for the refining organization to improve the business. One of those key goals was mechanical availability.
We’ve got 2 big programs that we’re working on to drive that improvement, and they’ve actually been in place for a number of years, honestly Doug. So the first -- and we’re starting to see the fruits of these take place here for us. The first one is a -- it’s around the reliability of our rotating equipment and making sure that we are monitoring that equipment with the best available technology. And we’re really start taking advantage of wireless technology now inside our operating facilities. So we’re getting a lot more information coming back to the -- those responsible for overseeing that equipment, the engineers and the reliability engineers in that group.
And that group now has -- I get probably on a weekly basis, a positive save. We’ll call it a positive fine before the actual failure of a piece of equipment that they’ve been getting these early indications. We’re able to take care of that equipment, and you’ll see that in our mechanical availability, and ultimately, you’ll see that in our utilization number, Doug. The other part of that mechanical availability is the execution of our planned maintenance, that turnaround window. And what we’ve been working on in that front -- and these are the other half of this goal that I put out on this mechanical availability is more predictability on our turnaround execution.
Now one of the highlights that I haven’t really highlighted too much was last year. We actually gave guidance on $800 million to $900 million on turnarounds last year, which is a pretty heavy year for us, honestly. We came in below the low end of that guidance in the $700 million number. So we’re starting to see that predictability improve on our execution of our turnarounds. Now the other part of that is to reduce the time that you’re doing to execute those turnarounds. And you do that by scope control of the turnarounds, making sure you’re only looking at the equipment you need to look at, you’re only fixing the stuff you need to be fixed. And we’re doing that by converting our inspection systems over from a time-based inspection program to a condition-based inspection program. That takes a lot of data to get you there, right? Because there’s no room for error on this, right? You have to be accurate on everything that you’re doing in this business.
And so we are now at the point where we have that data in place, and now we can start taking advantage of that as we execute these planned turnarounds moving forward. And so I’m pretty excited about that. I think that’s going to be a real good program for us. That’s going to reduce the amount of time it takes to do the planned part of the turnarounds. And with this unplanned condition monitoring program that’s in place now, I am quite hopeful that you’ll start seeing those utilization numbers go up from where they have been in the recent past. And we will return to historical numbers that you’ve seen from our assets and our operations.
Jeff Dietert
You might just talk about 2023 because we’re approaching the end of this heavy turnaround activity.
Rich Harbison
Yes. So 2023 first quarter for us is kind of the end of the heavy maintenance cycle for us, right? We gave guidance this year of $500 million to $600 million turnaround expense for the year. 40% of that is in the first quarter here. So we’re really getting over the hump on this heavy maintenance period. That’s, again, a little bit of a hangover from the COVID cycle that we went through, and you’ll see us kind of move out of that, and we’ll be in a much lighter planned maintenance cycle over the next several quarters.
Doug Leggate
And that reliability you talked about, that’s not 98% target you’re talking about, right?
Rich Harbison
That’s right, yes. We consider that world-class operation, Doug, and that’s what we’re shooting for. Our mission as an organization is to be a world-class operator. And the other part of that is to compete in any market environment, right? So that’s the market capture side of the business and you’ve got a number of initiatives that we’re working on that market capture side so that we can improve our resilience, I’ll say, in the market environment.
Doug Leggate
Well, maybe just talk a little bit about that because the cost side of the equation is the other big focus that you guys have had on the end. Can you give us an update on where the progress is there? And if I can elaborate on the question a little bit, Rich, to the extent we can, and Jeff will be able to relate to this. We don’t get access to the Solomon Associate Benchmarking data presumably you guys participate. Can you characterize where you are and where you want to be and the steps you might take together?
Rich Harbison
Yes, yes. So you may be happy you don’t have access to it.
Doug Leggate
I used to when I was in Chevron many years ago...
Rich Harbison
There’s a lot to unpack. There’s a lot to unpack in the Solomon numbers. But if I was to characterize our position in the Solomon, there are many metrics we are leading performers in, many matrice, many metrics across that Solomon portfolio. And there are some that we have opportunities to improve on, and those are ones that we use the Solomon for. We use it a little bit to reinforce what we’re doing is right, but then it helps us identify opportunities to focus on, right, within our business.
And I’ll then bridge back to some of these Investor Day commitments that we made. We’ve talked about the mechanical availability. The market capture number is one that we are focused on. And part of that comes out of the Solomon, but more importantly, probably comes out of the public informed data out there, right? We need to improve where we’re at on that process, and we’re working hard to do that.
And we’ve got really 2 programs that we’re working to make those improvements. One is small capital high-return investments. We have not really -- our focus as a company has really been focused on investing in the midstream part of the business and growing that part of the business, and we did it for a lot of good reasons, and we’re actually garnering the benefits of that now. But we do need to return back to some small-cap, high-return opportunities within refining to, again, improve that market capture because our competitors honestly have been doing that, right? And we need to keep up with our competitors.
So we’re focused on a handful of projects. Those will occur over a 3-year period here with essentially 1/3 of those projects will be completed this year, and that will essentially take up 1/3 of that 5% improvement that I laid out in November timeframe, and when we’ll do a third and a third, right? The other component of this is really on the market capture side is improving the operations around the assets, I’ll call it, the commercial operations. We have been -- there’s opportunities for us to improve that, and we do that by reoptimizing our plans. We put in plans, and we go execute those plans, and we’re very good at executing those plans. But what -- the market will move a lot faster than our plans move. So what we’re doing is looking to improve our response to the market conditions much faster through these operating plans than we have traditionally done. We do think that there’s good market capture opportunity there as well, and the cost -- you brought up the cost is another big component of that, and we’ve committed to saving $500 million of operating cost out of the refining organization. That equates to roughly $0.75 a barrel of earnings improvement, and we are well on that journey right now. There’s 2 components to that as well.
One component is our staff support organizations and how they are providing a service to the refining organization and are we doing that with the right level of cost model associated with that. So we’ve gone through a lot of optimization on that staff support side, but more importantly, and what I’m even more excited about is how the -- each business unit, each refinery has adopted this process, and we’re really getting a value mindset built into the organization here. We’ve activated all 11 facilities to really come up with a bottoms-up approach on how to be more efficient in our business. That process, I was actually a little skeptical of it from the beginning, but I am -- the more I see the ideas coming through and the engagement from the organizations and the benefit actually dropping to the bottom line of those ideas. I’m actually very excited about that progress, and I’m actually very hopeful that we will actually exceed our expectations on that cost reduction model that we’ve already put out there publicly as a target.
So...
Jeff Dietert
And that’s embedded in the targets were late last year.
Rich Harbison
That’s correct. Yes, that’s correct. So we had the 3 targets, if you remember. Mechanical availability improved that to 98%, market capture improved that by 5%, reduce operating costs by $0.75 a barrel.
Doug Leggate
Yes. Just real quick on the reliability, not to weigh too much on this, but what’s the trajectory? What’s the trajectory between now and 2025? Is it kind of a step change function? Or given you don’t have a lot of maintenance left after this year? Or is it more gradual?
Rich Harbison
I think you’ll see a bit of a step change here coming second, third quarter on this front, and then you’ll see a steady increase from that point forward. Some of these programs, you have to get them embedded into your operations, and they do take a bit of time. But there are -- with -- as I mentioned, we’re coming out of this heavy planned turnaround maintenance cycle. So you’ll see that step change, right? On availability and a utilization standpoint.
Presumably, the market is there, right? Utilization always has a component of market to it, but -- if presumably, the markets there, which we think were above mid-cycle, so we think the market will be there. You’ll see a step change up on that utilization number through that less planned maintenance activity.
Doug Leggate
I know I’m really laboring on this topic, but when you look at the relative performance of the portfolio, is there a big disparity between the best and the worst in your portfolio?
Rich Harbison
With terms of what, Doug?
Doug Leggate
Well, in terms of those metrics you were talking about, whether it be operating costs, reliability, safety performance, things are lot different....
Rich Harbison
Yes, yes. I think in any portfolio, it’s like any population, Doug, you’ve got kind of that normal curve, right? We’ve got some plants that are world-class leaders out there in their profile. We’ve got some that are our second quartile. We’ve got some that are third, and we don’t have any that are fourth quartile. So it’s just moving them all up to that first quartile performance is what we’re targeting.
Doug Leggate
Where did the joint venture refinery sit?
Rich Harbison
The WRB?
Doug Leggate
Yes.
Rich Harbison
Yes. So what do you -- what’s your question now? Where do they sit?
Doug Leggate
Where do they sit in terms of relative to competitors? It’s actually a question that came in from the audience on our webcast. we can [indiscernible] into this topic. But I guess you can elaborate that question to say we’re all quite interested to know if there’s ever a future where you could own 100% of those, but how competitive they are sitting relative to the rest of the portfolio?
Rich Harbison
Yes. No, we’re happy with the joint venture. It’s 2 very solid assets. We’ve got the Wood River facility up in Illinois and then the Morgan facility there in Northern Texas. And they fit well with our partner Synovus. Are we ever exploring opportunities? We always explore all opportunities, right, on that. But this joint venture has been a healthy one over the last years, and at this point in time, we don’t see any change in that right now, Doug.
Doug Leggate
Is there some integration with Ponca as well between those facilities?
Rich Harbison
Well, Ponca kind of stuck in the middle of the 2, right? So they do play in some of the same market a little bit, but it’s not integrated into the joint venture at all.
Doug Leggate
That’s why I was wondering, is there -- I was just curious if there was -- how do you separate the potential to improve efficiency by integrating those 3 with the fact that you only own 50% of 2?
Rich Harbison
Yes. Yes. Well, we’re the operator so what we’re always looking to do is to maximize their earnings potential, right, of those facilities. And we also operate the commercial side outside of the joint venture, right? So when we maximize the earnings potential of the WRB joint venture, and we will always work to optimize the earnings potential of the Ponca City independent of that.
Jeff Dietert
Those facilities are integrated with our marketing activities and their multiple distribution channels. And we can shift to -- if you have -- if the Denver market gets substantially stronger, we’ll ship product into that market. If Chicago gets tight, we’ll ship there. So there is flexibility and optionality that we take advantage of from a marketing perspective for products coming out of those refineries.
Doug Leggate
Is there any physical integration between them, Jeff?
Jeff Dietert
We have pipeline access to different markets, and we utilize third-party pipelines as well.
Doug Leggate
Between the refinery, I mean?
Rich Harbison
No, there is no.
Doug Leggate
No?
Rich Harbison
No. I mean...
Jeff Dietert
It’s more market related.
Rich Harbison
Its more market related there. You could ship intermediates through barging activity or rail activity or something like that, but there’s no pipeline interconnection that allows that to occur.
Doug Leggate
So I just got one last kind of big question on this topic of reliability and mechanical availability and maintenance. One of the things that one of your competitors has started to talk a lot more about is the commercial planning around things like turnarounds. The reason I bring it up is because -- and I think, Jeff, you were -- you gave us a pretty good steer on the last quarter as to what was happening with planned downtime given that margins collapsed at the end of last year. So it seemed that your downtime was in the best margin environment and your uptime was in the worst margin environment. So if you see what I mean. So it’s kind of unfortunate [indiscernible].
Jeff Dietert
Thanks for reminding us that, Doug.
Doug Leggate
But my point is that it seemed that there was more of a kind of if you build the inventory, when you know you’re going to have a planned turnaround, you can avoid those kind of swings as the message that seems to be coming from one of your competitors. How do you plan your commercial organization or your plans around turnarounds?
Rich Harbison
Yes. We -- they’re very integrated, Doug. I mean, obviously, the turnarounds are planned events, right? And we know the production impacts internally, what’s going to happen with those planned events. That information is handed over to our commercial organization, and they use that to prepare for continued supply into the marketplace. So that’s a very integrated process for us. That’s up and been running for years and years as part of our process, right? Now it’s a little bit harder to predict what the margins are going to end up being during those periods of time and what’s going to happen with the differentials. But from a pure liquid barrel supply standpoint, those -- that information is heavily integrated within our refining and commercial organizations.
Jeff Dietert
And with the value chain optimization group, we’ve really centered all the commercial activity for all the refineries.
Rich Harbison
Yes. So a couple of years ago, we initiated an organization called value chain optimization. That chain or that group is responsible for the communication between the refining organization and the commercial organization. And often, refiners speak a different language than commercial folks do, and they’re the interpreter, right? And they do a really good job. We’ve got actually experienced refiners embedded into that organization. So they understand how refineries work. And we also have experienced commercial people embedded in that organization. So their mission and their vision is to optimize our position in the marketplace and refine -- optimize our barrels as well as our commercial position in each of the markets. And they are the conduit of information that both planned and unplanned events flow through in order to get that optimized with our commercial group.
Doug Leggate
Okay. I’m going to turn it to Kalei in a minute because you’ve had a couple of audience questions come in, Jeff. But before I do that, I just want to close out on a couple of things in the portfolio. Europe versus the U.S., you obviously have an insight as to what’s going on in the European market firsthand. You mentioned this $4 per barrel margin advantage. What are you seeing in your own facilities? Is that a generic comment? Or is that what you’re seeing in your own facilities?
Jeff Dietert
That’s a generic comment that we’re looking across the European refining portfolio for the industry versus the U.S. And you call last summer when natural gas prices in Europe blew out, that increased to a $12 to $14 a barrel advantage and at a $15 natural gas price in Europe and a $3 in the U.S., you’re kind of $4 a barrel today. So that was a broad generic comment. Every refineries you make in different -- at Humber, we generate some of our own fuel, right?
Rich Harbison
Yes. So our insight, really, Doug, is the Humber facility on this. And you talked about that portfolio of where our performers on Humber on a top quartile performer when it comes to operating expense and energy for England -- for the U.K. area. So we are positioned quite well there. We do have insight. Does it increase our natural gas purchases for Humber? No, it doesn’t because we are very self-contained when it comes to production of fuel gas inside that plant. Where it does impact that plant, we see it as on the electrical supply side of the business. A lot of the electricity is generated from natural gas. So we do see an increase in that cost a little bit, but it’s all relative to the peers in the area as well.
Doug Leggate
So as Jeff knows well, that was the core thesis of our whole regional golden age thing that you can relate to this comparison. So my -- MiRO, you have insight into Russian flows as well. What’s physically going on in the ground as you relate to the Russian situation, whether it be the crude supply constraints or indeed the distillate product constraints? And I guess your insight from Europe, guessing up the current...
Jeff Dietert
Yes, we’re very active in that market. I think from a Russian crude perspective, they actually had record crude exports last month. So those barrels are finding their way into India and China and continue to find their way into the market. The product market is more recent with the February 5th implementation of the sanctions and the cap. What we’ve seen initially is that those barrels continue to get listed, and Europe imported aggressively in January on the diesel front. But in February, we saw the barrels being lifted. We’re seeing some move into North Africa, some into Turkey. It does appear some are floating. And so we’re still kind of figuring out what markets are those going to move into. They’re further away.
They’re going to require more tankage, longer routes. And so we’ve seen an impact on tanker rates. I think it’s too early to call where all those barrels are going to find a home. Our view is, they probably get discounted, but there’s a lot of room to discount them and move them into other markets. So our guess is that they’re going to continue to flow, but we have seen some floating that it’s not clear where they’re going yet.
Doug Leggate
So just to be clear -- I appreciate those insights. You’re still taking Russian crude into that refinery then?
Jeff Dietert
So each of the owners at MiRO brings its own crude in, and -- so I think some of those barrels have been replaced. The German government has kind of moved in, correct?
Rich Harbison
Yes, they’ve moved in and taken those out, yes. So the objective is to move the Russian barrels out of the MiRO refinery. They’ve actually taken over as representatives of the Russian component -- ownership component of that and -- so they’ll provide no overview of that.
Doug Leggate
Okay. Thank you guys. Kalei, do you want to go from there?
KaleiAkamine
Yes. A couple of days ago, maybe it was last week, saw a headline that suggested that Germany was trying to replace Russian barrels that are moving through the Druzhba pipeline with Kazakh oil. Is that something that you guys are seeing?
Jeff Dietert
I don’t have insight on that.
Rich Harbison
Yes, I don’t either. Sorry.
KaleiAkamine
Okay. We’ll keep our feel for that. The question I got thought in from the line is on needle coke markets. So apparently, the OEMs are buying direct. Are you in those negotiations?
And do you guys have a view on the medium to longer-term prices for needle coke? And I suppose, for context, you can put that in terms of some kind of differential versus Brent or maybe a heavy barrel.
Jeff Dietert
Yes, it’s tough to equate those 2 oil. But needle coke -- just maybe for background a little bit. So needle coke has really 2 primary markets for us when we think about that product. One is the traditional graphite electrode market, which is generally the steel production arc furnaces and very large electrodes in that market. And then the next market in the emerging market and the way, I think, it’s the one you’re referencing here is really the battery anode market and really the electrification of the economy and the transportation fleet for that matter.
So we are actively working on number of fronts on for our needle coke, which is really a synthetic carbon substitute inside of the battery anode, and it’s very effective. And it’s very, very efficient actually, but it’s also very expensive. So there is a concerted effort with a lot of the battery manufacturers to figure out a recipe that has various synthetic carbons in it to drive the cost of the battery down. And we are working with a number of folks on that front to develop recipes for battery anodes that meet the cost objectives, but also meet the safety and reliability objectives of a battery. And that’s -- honestly, it’s still quite an emerging market, and it’s -- there’s a lot of activity on that front.
There is a lot of interest in it. Of course, the Inflation Reduction Act has also inspired a lot more conversation on North America and the U.S. on that front. So we see that as a continued opportunity -- marketing opportunity for the placement of this needle coke into that market. But that process is quite extensive and quite long, as you can imagine, because there are safety implications and reliability implications.
So the actual certification process to get into a battery recipe takes a couple of years, and it takes a lot of bench testing and a lot of commitments to do that. And we are working through those on a number of fronts right now.
Rich Harbison
And there’s really an interest in both in Europe and in the U.S. of establishing those full value chains within the domestic market as opposed to heavy dependence on China for the global market.
Jeff Dietert
Yes. Right now, a lot of that needle coke does go to China for production of batteries in the Chinese markets.
Rich Harbison
Yes. And we produced at Humber in the U.K. and Lake Charles in the U.S.
Kalei Akamine
Got it. I appreciate that, guys. For this next line of questions, I wanted to circle back to the discussion on refinery balances. Jeff, in particular, does a great job of assessing the net additions, but there’s 2 wrinkles that we want to get your opinion on. The first one is Russia, where they announced a 500,000 barrel cut for March. I want to get your opinion on whether that’s a crude cut or a products cut? And the next area is China. Obviously, they’re adding a lot of refining capacity, but the debate there is, whether they ramp up to supply their own domestic demand or they ramp up to support export markets? How do you guys see it?
Jeff Dietert
Yes. I think within Russia, we’ve seen the 500,000 barrel a day cut. It happens to coincide with typically when they do their refinery maintenance in the April, May timeframe. So we wonder if those 2 might be associated with one another. And is this a long-lasting cut or is this a temporary cut? And then once the maintenance is completed, does it come back into the market. So those are unknowns at this point. So we’ll continue to track that. In China, China is adding new refining capacity. Much of it is really focused on chemical back-ends, and so they’re fully integrated back into the chemical business.
The fuel yields are relatively low, 8% for diesel, for example. And so there are less fuels refineries and more chemical refineries. They have an optimistic view as well on chemical demand longer term, and so those refineries are unique from capacity that gets added in the U.S. or in the Middle East, which is more fuels-based. I think the other thing is the -- a lot of the [indiscernible] capacity is coming out of that market and reducing capacity. And we’ve seen that in 2022 and more expected for 2023. Does that answer your question?
Kalei Akamine
Yes. I think, yes, it has. There was another question that we received on the last panel, and this relates to light-heavy differentials. There’s a lot of new refining capacity coming online and it’s very, very complex. So the question is, where you think heavy -- light/heavy differential settle over time? Assuming that the refinery slate becomes more complex, it can destroy the heavy sulfur material that no longer has a place in many markets.
Jeff Dietert
Yes. I think that’s a fair point in complexity. Some of that complexity is going through towards chemicals rather than fuels, but that complexity does create an incremental demand for heavy sours. I think we also see, as we look medium and longer term, an increase in heavy and medium crudes coming into the market. Middle East crudes providing some of the growth, UAE, Saudi Arabia.
We see U.S. light sweet crude production growth moderating in the years ahead. And so I think there’s a good argument on the supply side that most of the incremental crudes are going to be heavier, medium and sour grades. And so I think those balance out. And then finally, on the demand side of the equation, a steady increase in the demand for cleaner fuels, a push towards cleaner fuels in the international markets.
We’ve already seen a lot of that in the OECD countries, but I think that’s a factor as well with the marine fuels shifting to low sulfur diesel and low sulfur fuel oils. The demand side of the equation is going to go lean towards cleaner fuels as well. Anything you want to add?
Rich Harbison
No. No, I think you covered it well there, yes.
Kalei Akamine
Maybe focusing on the supply side of that question later this year or maybe it’s early 2024, the [indiscernible] and expansion comes online. What are your views of what happens to heavy sour differentials on the West Coast what happens to the benchmark that we all typically follow, which is WTI, WCS.
Jeff Dietert
Yes. 2 good questions. I might hit the Canadian heavy component and then let Rich hit TMX. When you look historically at the Canadian heavy differential, it’s been heavily influenced by the location differentials and the lack of pipeline capacity. And when pipeline capacity fills and you move to rail economics, you see that jump from $13 a barrel to $18 or $20 a barrel. And with TMX the location differential is going to be more focused on the pipeline differential and less on shifting into rail economics, I think, when TMX brings on 560,000 barrels a day. And so it really is 2 components, one that location that’s going to narrow, and we think that’s maybe $8, $9 a barrel on location. The other piece is quality differential. And as we see high-sulfur fuel oil and ULSD and very low-sulfur fuel oil prices as we see that differential kind of hanging wider, that will be a bigger piece of the volatility in Canadian heavy differentials and that piece will be incremental. So if you’re $8 or $9 a barrel on transport and you’re another $5 to $10 a barrel on quality differential, that’s where we see WTI, WCS kind of falling as we look forward.
Rich Harbison
Yes. When we think the barrels coming down TMX, PADD 5 makes a nice landing spot for them. With the California crude continued decline in production coming out of the Central Valley and the South area there, these barrels actually make a nice fit into the PADD 5. They fit the refinery profiles quite well on the West Coast of the PADD 5 area. So we think most of that production will end up into that California market in that northwest -- Pacific Northwest area.
Jeff Dietert
Ultimately, the marginal pricing point stays at the Gulf Coast. And so that -- the Gulf Coast differential is going to be the marginal factor we think.
Rich Harbison
That will be the competition between the Gulf Coast and the PADD 5.
Doug Leggate
So guys, I’ve tried to keep the bulk of our questions dedicated to refining. But I do want to hit a couple of other things very quickly before we let you go. We only got a couple of minutes. So we’ll go bullet point fashion. And I’m going to put you on the spot, bespoken the bullet point one. When you guys put out targets for the broader company to get to $13 billion of EBITDA by 2025, presumably, you have risked those numbers. Can you characterize how your risk then?
Jeff Dietert
Yes. So I might hit that from a high level and let Rich come at it as well. So we’re going from $10 billion of mid-cycle EBITDA to $13 billion. The big projects in there are business transformation, about $1 billion of cost, $1.3 billion of EBITDA from the DCP consolidation, including $300 million of that is synergies. And then the Rodeo Renewed, which is about $700 million of EBITDA. So that’s the bridge that gets us there.
Rich Harbison
Yes. So when you talk about risk, the synergies were $300 million, and that -- we’re hopeful that we can exceed that, but that’s kind of where we’re at right now. And then on the Rodeo Renewed the earnings potential is tied a lot to those incentive programs, right, that move around. Yes, LCFS, the RINs, the blender tax credit. The IRA has helped kind of add some certainty now to the blenders tax credit and how that works and how that fades into the 45Z component of it...
Jeff Dietert
Which was not included in our -- economic.
Rich Harbison
And that was not included in our basic. That’s exactly where I was going to go with that. It’s not part of the base economics of that...
Doug Leggate
I want to go right back to the beginning of this discussion. This would be my last question because we’re out of time. So Jeff, you said your view of mid-cycle is 2012 through 2019 at $12 a barrel. What are you assuming in the $13 billion number?
Jeff Dietert
That’s what we’re assuming 2012 to 2019 average.
Rich Harbison
Mid-cycle.
Jeff Dietert
Mid-cycle.
Doug Leggate
By which -- as we believe mid-cycle will be higher.
Jeff Dietert
We do believe it will be higher, but that’s the baseline that you can utilize. And every dollar per barrel on gasoline is $320 million of EBITDA a year. Every dollar diesel is $280 million a year. Every dollar on Canadian heavy is $100 million a year. So you can kind of take that ‘12 to ‘19 average and put your own estimates in and tweak to a level that you would view as mid-cycle going forward.
Doug Leggate
So it would be fair to assume then -- you’re going to hit me for this. If you believe that the mid-cycle is higher than $12 that there is upside risk to the $13 billion mid-cycle.
Jeff Dietert
Yes, sir.
Doug Leggate
That’s a great place to finish off. Guys, thanks for [indiscernible] I really appreciate you being here, Rich and Jeff. Thanks a lot, and Enjoy the rest of your day. Thanks so much for being part of our event.
Jeff Dietert
All right. Thank you, Doug.
Rich Harbison
Thanks.
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Phillips 66 (PSX) Presents at Bank of America Securities 2023 Refining Conference (Transcript)