Ladies and gentlemen, the program is about to begin. Reminder that you can submit questions at any time via the Ask Questions tab on the webcast page. At this time, it is my pleasure to turn the program over to your host, Doug Leggate.
Well, thank you, Eric, 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. I mentioned earlier, this is our 20th year hosting this refining dedicated conference for the independent US refiners. We wouldn't have a conference if it wasn't for these guys participating. Jeff Dietert, 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 team available for us today. Thank you for that, Jeff. We have as our guest speaker, Senior Vice President of Refining, Rich Harbison, who I think, you might wanna remind me just how long now you've been in that spot.
I wanna kinda 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? Thank you guys for being here.
Thanks, Doug, 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. I've seen a bit over my years, but actually been in this particular role a little over eight months now. It's been a quick eight months, and it's again a pleasure to talk to the group here. You know, 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. You know, during that COVID period, we saw a lot of supply and production really drop offline, you know, get rationalized off of...
What kinda accelerated that rationalization, as demand dropped off and the high cost producers were essentially forced to shut down. That really accelerated a supply and demand rebalance than what has traditionally been in place during a cycle. You know, and we think about it moving forward here, and, you know, 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 pre-rationalized, I'm gonna say, on this cycle with that reduction in supply and the demand kind of picked up and, you know, 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, you know, may or may not occur here over the next 12 months or so. We see, 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. That in this case, it would move us probably more to an imbalance supply and demand scenario versus an oversupply and a reduced demand scenario.
It's a little bit different way to think of it, on a, on a global basis. I think we start in a different spot there. That, that then puts me when I think about mid-cycle pricing, you know, 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. That's kind of way I'm thinking about it right now, Doug. Anything to add to that, Jeff?
Yeah. Just to put some numbers around it, we talk about mid-cycle being the average of 2012-2019, and the average RIN-adjusted three-two-one crack was $12 a barrel during that period of time. We just completed January and February, which are typically two of the weaker months of the year, and we're over $20 a barrel on a RIN-adjusted crack. A very healthy environment to start the year. As we look at capacity additions, we see net additions at about 500,000-600,000 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. It's not an overwhelming amount of capacity.
When you look at the IEA, they're talking about two million barrel a day of demand growth in 2023. About one million barrels a day of that is in China. We're watching that carefully. The indications in China, I think, are better than we would have thought a few months ago. 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. The indications are pretty positive, I think, coming in, to this period in China. There is some excess capacity in China that probably runs, but I think we're gonna need it to run.
As we think about 2023, we believe we're probably above mid-cycle for this year.
You know, I have to pick up, Jeff, if you don't mind, on those numbers. The 500-600 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. It seems that there's a lot of question marks over the timing of those startups and then the utilization rate once they've cut the ribbon, so to speak. What are you assuming in there?
Yeah, it's a great question. Kuwait, we've got the first of three units is already operating. The second one is expected, first 200,000 barrel a day operating now. Next 200,000 barrel a day in later the first half of this year, and then the third at the end of this year. 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. you know, there's some unique and challenging structures for one of those facilities in particular. That's our assumption on the timing there.
We've got Mexico and Nigeria further out, not starting this year.
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 refinery capacity offline with Alliance, obviously it had the storm, and this year, Rodeo. Does the portfolio stabilize after that into this higher mid-cycle?
You know, it's a portfolio question. It's a good question, Doug. You know, I think when we look at our portfolio, we like it. You know, we have high complexity in our portfolio. We actually have the ability to run, you know, a variety of crudes from light to medium to heavy. We're spread across the different paths, so we're not subject to one regional differential in the U.S., and we have exposure in Europe as well to that. 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, you know, are we getting the highest level return on capital employed with our assets?
obviously, we made the decision for the San Francisco Refinery to convert to a different operating model there, which we're quite excited about and think it's really positions the asset and the long-term viability of the asset, as well as, you know, preserves the jobs for the organization in that area. We're quite constructive on that business as it moves forward. We can go into a little bit more detail here in a few minutes, I guess, on what the timing of that is and how that's going.
Sure.
Then we think about the U.S. in general, right, versus worldwide competition. You know, we think the U.S. is positioned in a very strong advantage, actually, especially around the cost of energy, right?
Mm-hmm.
Natural gas price is quite favorable for our operations, especially compared to Europe, right?
Right.
Even though Europe's price has come down quite a bit, we still have a, you know, nominal $4 a barrel advantage over that, which makes U.S. refineries quite competitive worldwide. You know, of course, we have the scale within our systems and this complexity issue. You know, if you ask me if are we happy with the portfolio? Yeah, 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.
I guess before we get into the actual operations, I was just looking at the screen there, if you saw me glancing down. We got $42 heat cracks and $34 gasoline cracks.
Yeah.
In March. I was gonna say in January. They weren't that much lower in January.
It's already March, Doug.
Why do you think that is?
Well, I think it goes back to what I was talking about earlier about the supply rationalization that has occurred from this, you know, from that COVID period there. The, you know, 4.5 million barrels off the market worldwide, one million plus in the U.S.
Mm-hmm.
That has kind of rebalanced the supply and demand. You know, when we look at supply and consumption, you know, 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 of diesel, but the demand we're seeing to kind of come off a little bit with our forecast for the year. There is a scenario, honestly, Doug, that we think, you could see gasoline flip to the lead indicator this year.
As the gasoline driving season kicks in and the maintenance periods end up, we do see a potential scenario where that could play out. You know, since the COVID period, we've essentially been in a strong distillate crack scenario. We, you know, we're gonna continue in that strong distillate crack scenario until we actually see that change. Over to gasoline. There is a scenario that plays out in our numbers that could happen this year, as early as this year.
No.
Jeff's leading right now.
Yeah. Jeff.
Diesel and then gasoline in the forward curve.
Yeah.
We'll monitor that and adjust.
Sure.
As those things change.
Yeah.
Okay. Just to... I don't wanna 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-?
Yes. Yeah.
Go on.
Yes, we are. We have a max distillate signal. We have been for quite some time, and we'll continue until we see that gasoline signal change. One thing that... 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.
Right.
When we're talking about distillate production, right? Jet production, we do see as kind of the leading indicator here as the market continues to recover.
Sure.
Especially when we see the long hauls going into China and coming out of China.
Right.
We think that's quite constructive moving forward here.
Those robust margins are great, but you've got to have the reliability and the, you know, efficiency to be able to take advantage of that.
Yeah.
I think there were probably some questions over what had been happening to Phillips 66 towards the back half of last year. 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 the mechanical availability of the plant?
Yeah. Yeah. Thanks. Thanks, Doug. Obviously you got two components of that, right? You've got the planned maintenance component, and you got the unplanned maintenance component. During the investor day back in November, we talked a lot about the three key goals that I had laid out for the refining organization to improve the business. One of those key goals was mechanical availability. We've got two big programs that we're working on to drive that improvement. They've actually been in place for a number of years, honestly. The first, and we're starting to see the fruits of these take place here for us. The first one is a, 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. We're really taking advantage of wireless technology now inside our operating facilities. 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. That group now has I get probably on a weekly basis, a positive save. We'll call it a positive find 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. You'll see that in our mechanical availability. 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. 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. One of the highlights that I haven't really highlighted too much was last year. We actually gave guidance on $800 million-$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 700s number. We're starting to see that predictability improve on our execution of our turnarounds. The other part of that is to reduce the time that you're doing to execute those turnarounds.
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 fixing. 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?
Mm-hmm.
There's no room for error on this, right? You have to be accurate on everything that you're doing in this, in this business. 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. I'm pretty excited about that. I think that's gonna 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. 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.
We will, we'll return to historical numbers that you've seen from our assets and our operations.
You might just talk about 2023 because we're approaching the end of this heavy turnaround activity.
Yeah.
Right.
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-$600 million turnaround expense for the year. 40% of that is in the first quarter here. 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. 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.
Thank you for that. That reliability you talked about, that's that 98% target you're talking about, right?
That's right. Yeah, 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? That's the market capture side of the business, and we've got a number of initiatives that we're working on that market capture side.
Mm-hmm.
That we can improve our resilience, I'll say, in the, in the market environment.
Well, let 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.
Right.
Can you give us an update on where the progress is there? If I can elaborate on the question a little bit, Rich, to the extent you can, and Jeff will be able to relate to this. We don't get access to the Solomon Associates benchmarking data. Presumably, you guys participate. Can you characterize where you are and where you want to be and the steps you might take to get there?
Yeah. Yeah. You may be happy you don't have access to it, Doug.
Well, I used to when I was in Chevron.
There's a lot to unpack. There's a lot to unpack in the Solomon numbers.
Yep.
You know, if I was to characterize our position in the Solomon, there are many metrics we are leading performers in. Many, many metrics across that Solomon portfolio. There are some that we have opportunities to improve on. Those are ones that we use the Solomon for. You know, 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. Then I'll bridge back to some of these investor day commitments that we made. You know, we've talked about the mechanical availability. The market capture number is one that we are focused on.
Part of that comes out of the Solomon, but more importantly, it probably comes out of the public info-informed data out there, right? We need to improve where we're at on that process, and we're working hard to do that. We've got really two 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. We did it for a lot of good reasons, and we're actually garnering the benefits of that now. We do need to return back to some small cap, high return opportunities within refining to again improve that market capture. 'Cause our competitors, honestly, have been doing that, right?
We need to keep up with our competitors. We're focused on a handful of projects. Those will occur over a three-year period here. Essentially a third of those projects will be completed this year, and that'll essentially take a third of that 5% improvement that I laid out in November timeframe. We'll do a third and a third, right? The other component of this on the market capture side is improving, you know, the operations around the assets. I'll call it the commercial operations. You know, 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.
The market will move a lot faster than our plans move. 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. The cost, you brought up the cost as another big component of that. You know, we've committed to shaving $500 million of operating costs out of the refining organization. That equates to roughly $0.75 a barrel of earnings improvement. We are well on that journey right now. There's two 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. We've gone through a lot of optimization on that staff support side. More importantly, and what I'm even more excited about, is how each business unit, each refinery has adopted this process. 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. 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.
That's embedded in the targets that were laid out late last year.
That's correct. Yeah, that's correct. We had the three targets, if you remember. Mechanical availability, improve that to 98%. Market capture, improve that by 5%. Reduce operating costs by $0.75 a barrel.
Yep. Just real quick on the reliability, not to weigh too much on this. What's the trajectory between now and 2025? Is it kind of a step change function or given that you don't have a lot of maintenance left after this year, or is it more gradual?
I think you'll see a bit of a step change here come in second, third quarter on this front, and then you'll see a steady increase from that point forward. Some of these programs, you know, you have to get them embedded into your operations, and they do take a bit of time. There are, you know, as I mentioned, we're coming out of this heavy planned turnaround maintenance cycle. You'll see that step change, right? On an availability and a utilization standpoint. Presumably, the market's there, right? Utilization always has a component of market to it. If presumably the market's there, which we think we're 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.
I know I'm really laboring on this topic, but when you look at the relative performance of the portfolio, is it a big disparity between the best and the worst in your portfolio?
With terms of what, Doug?
Well, in terms of those metrics you were talking about, whether it be operating costs, reliability, safety, performance, things of that nature.
Yeah. Yeah.
All those factors.
Well, I, you know, I think in any portfolio, it's like any population, Doug. You've got, you know, kind of that normal curve, right?
Right.
We've got some plants that are you know, world-class leaders out there in their profile. We've got some that are second quartile. We've got some that are third. We don't have any that are fourth quartile.
Mm-hmm.
It's just moving them all up to that first quartile performance is what we're targeting.
Where did the joint venture refinery sit?
The WRB?
Yeah.
Yeah. What's your question now? Where do they sit?
Where do they sit in terms of relative competitiveness? It's actually a question that came in from the audience on our Veracast. We can link into this topic, I guess you can elaborate that question to say we're all quite interested to know if there is ever a future where you could own 100% of those. How competitive they are sitting relative to the rest of the portfolio.
Yeah. No, we're happy with the, with the joint venture. You know, it's two very solid assets. We've got the Wood River facility up in Illinois and then, the Borger facility there in northern Texas. You know, they fit well with our partner, Cenovus. You know, are we ever exploring opportunities? We always explore all opportunities right, on that. You know, 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.
Is there some integration with Ponca as well between those facilities?
Ponca's kind of stuck in the middle of the two, right? They do play in some of the same market a little bit, but it's not integrated into the joint venture at all.
That's what I was wondering. How do you separate the potential to improve efficiency by integrating those three with the fact that you only own 50% of 2?
Yeah. Yeah. Well, we're the operator, so what we're always looking to do is to maximize the earnings potential, right, of those facilities. We also operate the commercial side outside of the joint venture, right?
Mm-hmm.
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.
Sure. Thank you.
You know, those facilities are integrated with our marketing activities, and there are multiple distribution channels, and we can shift to, you know, if you have if the Denver market gets substantially stronger, we'll ship product into that market.
Right.
If Chicago gets tight, we'll ship there. There is flexibility and optionality that we take advantage of from a marketing perspective for products coming out of those refineries.
Is there any physical integration between them, Jeff?
We have pipelines, pipeline access to different markets, and we utilize third-party pipelines, as well.
Between the refineries, I mean.
No, there is no.
No.
No. I mean.
It's more market related.
It's more market related. You know, you could ship intermediates through, you know, barging activity or rail activity or something like that.
Right.
There's no pipeline interconnection that allows that to occur.
I've 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, I think, Jeff, 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. It seemed that your downtime was in the best margin environment and your uptime was in the worst margin environment. If you see what I mean. It's kind of unfortunate serendipity or, you know, a bit of luck, I suppose.
Thanks for reminding us that, Doug.
My point is that it seemed that there was more of a kind of, if you build the inventory when you know you're gonna have a planned turnaround, you can avoid those kind of swings is the message that seemed to be coming from one of your competitors. How do you plan your commercial organization or your, you know, your plans around turnarounds?
They're very integrated, Doug. I mean, obviously the turnarounds are planned events, right? We know the production impacts internally, what's gonna happen with those planned events. That information is handed over to our commercial organization, They use that to prepare for continued supply into the marketplace. That's a very integrated process for us. That's up and been running for years and years.
Right.
as part of our process, right? Now, it's a little bit harder to predict what the margins are gonna end up being during those periods of time, and, you know, what's gonna happen with the differentials. From a pure liquid barrel supply standpoint, that information is heavily integrated within our refining and commercial organizations.
With Value Chain Optimization.
Yeah.
We've really centered all the commercial activity for all the refineries.
Yeah. A couple 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. Often refiners speak a different language than commercial folks do.
Right.
They're the interpreter, right? They do a really good job for it. We've got actually experienced refiners embedded into that organization, so they understand how refineries work. We also have experienced commercial people embedded in that organization. Their mission and their vision is to optimize our position in the marketplace and refine, you know, optimize our barrels as well as our commercial position in each of the markets. They are the conduit of information that both planned and unplanned events flow through in order to get that optimized with our commercial group.
Okay. Thank you. I'm gonna turn it to Clay in a minute because you had a couple of audience questions come in, Jeff. Before I do that, I just wanna close out on a couple of things in the portfolio. Europe versus the US, you obviously have an insight as to what's going on in 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?
That's a generic comment that we're looking across the European refining portfolio for the industry versus the US. You call last last summer when natural gas prices in Europe blew out, you know, that increased to a $12-$14 a barrel advantage.
Right.
At a $15 natural gas price in Europe and a $3 in the U.S., you're kind of $4 a barrel today. That was a broad generic comment. Every refinery is unique and different. you know
Yeah.
At Humber, we generate some of our own fuel, right?
Yeah. Our insight really, Doug, is the Humber facility on this. When you talked about that portfolio of where are our performers, well, Humber's on a top quartile performer when it comes to operating expense and energy for England, for the UK area.
Sure.
We are positioned quite well there. We do have insight. Does it increase our natural gas purchases for Humber? No, it doesn't, 'cause 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 is in on the electrical supply side of the business. A lot of the electricity is, you know, generated from natural gas. We do.
Right.
see an increase in that cost a little bit, but it's all relative to the peers in the area as well.
As Jeff knows well, that was the core thesis of our whole regional golden age thing that you can relay to Mr. Terrason. Miro, you have insight into Russian flows as well. What's physically going on on the ground as you relate to the Russian situation, whether it be the crude supply constraints or indeed the distillate product constraints? I guess from your insights from Miro, I'm guessing of the current.
We're very active in that market. I think from a Russia crude perspective, they actually had record crude exports last month. Those barrels are finding their way into India and China, and continuing 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 lifted. Europe imported aggressively in January.
Mm-hmm.
On the diesel front. 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. We're still kind of figuring out what markets are those going to move into. They're further away. They're gonna 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 gonna 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 guesstimate is that they're gonna continue to flow, but we have seen some floating that it's not clear where they're going yet.
just to be clear, you well, I appreciate those insights. You're still taking Russian crude into that refinery then?
Each of the owners at Miro brings its own crude in.
Okay.
I think some of those barrels have been replaced. The German government has kinda moved in, correct?
Yeah. They've moved in and taken those out. Yeah.
Yeah.
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.
Ownership component of that, yeah.
Right.
They're providing a overview of that.
Okay, thank you. Jeff, Clay do you wanna go from there?
Yeah. A couple of days ago, maybe it was last week, I 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?
I don't, I don't have insight on that.
Yeah, I don't either.
Yeah.
Sorry.
Okay. We'll keep our ears peeled for that. The question that we got in from the line is on needle coke markets. Apparently the auto OEMs are buying direct. Are you in those negotiations? Do you guys have a view on the medium to longer term prices for needle coke? I suppose for context, you can put that in terms of some kind of differential versus Brent or maybe a heavy barrel.
Yeah. It's tough to equate those to oil. You know, needle coke, just maybe for background a little bit. needle coke has really two 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. Next market and the emerging market, and the one I think is 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.
We are actively working a number of fronts on for our needle coke, which is a really a synthetic carbon substitute inside of the battery anode. It's very effective, and it's very efficient, actually. It's also very expensive. 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. 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. 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. We see that as a continued opportunity, marketing opportunity for the placement of this needle coke into that market. That process is quite extensive and quite long, as you can imagine, 'cause there is safety implications and reliability implications. The actual certification process to get into a battery recipe takes two years, and it takes a lot of bench testing and a lot of commitments to do that. We are working through those on a number of fronts right now.
There's really an interest in, both in Europe and in the U.S., of establishing those full value chains within the domestic market.
Right.
As opposed to heavy dependence on China
Right.
For the global market.
Right now, a lot of that needle coke does go to China for production of batteries in the, in the Chinese markets.
Yeah. We produce at Humber in the U.K. and Lake Charles in the U.S.
Okay. I appreciate that, guys. For this next line of questions, I wanna circle back to the discussion on refinery balances. Jeff in particular does a great job of assessing the net additions, but there's two wrinkles that we wanna get your opinion on. The first one is Russia, where they announced a 500,000 barrel cut for March. I wanna get your opinion on whether that's a crude cut or a products cut? 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?
I think with 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. We wonder if those two 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? Those are unknowns at this point. We'll continue to track that. In 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, you know, 8% for diesel, for example.
They're less fuels refineries and more chemical refineries. They have an optimistic view as well on chemical demand, longer term. 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 teapot capacity is coming out of that market, and reducing capacity. We've seen that in 2022 and more expected for 2023. Does that answer your question?
I think yes, it does.
All right.
There is another question that we received on the last panel. This relates to light heavy differentials. There's a lot of new refining capacity coming online, and it's very, very complex. The question is: Where you think heavy, light heavy differentials 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.
Yeah, I think that's a fair point. Some of that complexity is going through towards chemicals rather than fuels. 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 US light sweet crude production growth moderating in the years ahead. I think there's a good argument on the supply side that most of the incremental crudes are gonna be heavier, medium and sour grades. I think those balance out.
Finally, on the demand side of the equation, you know, 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. 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 gonna go lean towards cleaner fuels as well.
Maybe focusing.
And?
No, no. I think you covered it well there, Jeff.
Maybe focusing on the supply side of that question. Later this year or maybe it's early 2024, the Trans Mountain 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?
Yeah.
Yeah. Two 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. When pipeline capacity fills and you move to rail economics, you see that jump from, you know, $13 a barrel to $18 or $20 a barrel. With TMX, the location differential is gonna be more focused on the pipeline differential and less on shifting into rail economics, I think, when TMX brings on, you know, 560,000 barrels a day. So it really is two 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.
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. If you're $8 or $9 a barrel on transport and you're another, you know, $5-$10 a barrel on quality differential, that's where we see WTI, WCS kind of falling as we look forward.
We think the, you know, the barrels coming down TMX, PAD 5 makes a nice landing spot for them. You know, 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 PAD 5. They fit the refinery profiles quite well on the West Coast in the PAD 5 area. We think most of that production will end up into that, California market and, that Northwest, Pacific Northwest area.
Ultimately, the marginal pricing point stays at the Gulf Coast.
Right.
The Gulf Coast differential is gonna be the marginal factor we think.
That'll be the competition between the Gulf Coast and the PAD 5.
Guys, I've tried to keep the bulk of our questions dedicated to refining, I do wanna hit a couple of other things very quickly before we let you go. We've only got a couple of minutes. We'll go bullet point fashion, and I'm gonna put you on the spot. This probably be a 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 you risk them?
I might hit that from a high level and let Rich come at it as well. You know, we're going from $10 billion of mid-cycle EBITDA to $13 billion. The big projects in there are Our business transformation, about a billion dollars in cost. $1.3 billion of EBITDA from the DCP consolidation, including $300 million of that is synergies.
Right.
Then the Rodeo Renewed, which is about $700 million of EBITDA. That's the bridge that gets us there.
When you talk about risk, you know, you know, the synergies were $300 million and that, you know, we're hopeful that we can exceed that. That, that's kinda where we're at right now. Then on the Rodeo Renewed, the earnings potential's tied to lots of those incentive programs, right? That, that move around.
LCFS. Yep.
Yeah, LCFS, the RINs, the Blenders Tax Credit. You know, 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.
Which was not included in our economics.
That was not included in our basic. That's exactly where I was gonna go with that. That was not part of the base economics of that project.
I wanna go right back to the beginning of this discussion. This will be my last question 'cause I know we're out of time. 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?
That's what we're assuming, 2012-2019 average mid-cycle.
Rich, as you believe mid-cycle will be higher.
We do believe it will be higher, but that's the baseline that you can utilize, and, you know, every $1 per barrel on gasoline is $320 million of EBITDA a year. Every $1 of diesel is $280 million a year. Every $1 on Canadian heavy is $100 million a year. You can, you can kinda take that 12 into 19 average and put your own estimates in and tweak to a level that you would view as mid-cycle going forward.
It would be fair to assume then, you're gonna hate 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.
Yes, sir.
That's a great place to finish off. Guys, thanks very much indeed.
All right.
I really appreciate you being here, Rich. Jeff, thanks a lot. You know, enjoy the rest of your day. Thanks so much for being part of our event.
All right. Thank you, guys. Thanks, for the end.