Phillips 66 (NYSE:PSX) Q2 2024 Earnings Call Transcript

Phillips 66 (NYSE:PSX) Q2 2024 Earnings Call Transcript July 30, 2024

Phillips 66 beats earnings expectations. Reported EPS is $2.31, expectations were $1.98.

Operator: Welcome to the Second Quarter 2024 Phillips 66 Earnings Conference Call. My name is Emily, and I’ll be your operator for today’s call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded. I will now turn the call over to Jeff Dietert, Vice President, Investor Relations. Jeff, you may begin.

Jeff Dietert: Welcome to the Phillips 66 second quarter earnings conference call. Participants on today’s call will include Mark Lashier, Chairman and CEO; Kevin Mitchell, CFO; Don Baldridge, Midstream and Chemicals; Rich Harbison, Refining; and Brian Mandell, Marketing and Commercial. Today’s presentation can be found on the Investor Relations section of the Phillips 66 website, along with supplemental financial and operating information. Slide 2 contains our Safe-Harbor statement. We will be making forward-looking statements during today’s call. Actual results may differ materially from today’s comments. Factors that could cause actual results to differ are included here as well as in our SEC filings. With that, I’ll turn the call over to Mark.

Mark Lashier: Thanks, Jeff. Welcome, everyone, to our second quarter earnings call. First, I’d like to introduce Don Baldridge, our new EVP of Midstream and Chemicals. He previously served as the Interim CEO of DCP and brings a wealth of Midstream experience to Phillips 66. I also want to wish Tim Roberts the best in his retirement and thank him for his contributions to Phillips 66, including being instrumental in executing our NGL wellhead-to-market strategy. Let’s turn to our second quarter performance. We continue to systematically execute on our strategic priorities, focusing on what we control. The improvements are visible in our results. Since July 2022, we’ve returned over $11 billion to shareholders through share repurchases and dividends.

We expect to achieve our $13 billion to $15 billion target by the end of the year. Share repurchases will continue to be a priority in our capital allocation plan. We are committed to returning over 50% of our operating cash flows to shareholders. In refining, we’re enhancing performance and reducing our cost structure. Crude utilization during the quarter was our highest at over — in over five years at 98% and clean product yield was 86%. In addition, we’ve lowered our costs by nearly $1 per barrel. In Midstream, we continue to benefit from synergy capture as we execute on our NGL wellhead-to-market strategy. Earlier this month, we closed on our acquisition of Pinnacle Midstream. It was a bolt-on to our natural gas-gathering and processing business and grows our stable earnings with high-quality 100% fee-based long-term contracts.

The assets are strategically located near our existing Permian footprint in the liquids-rich Midland Basin. In the second quarter, we sold our 25% non-operated interest in the Rockies Express Pipeline for $685 million. We generated over $1 billion from asset dispositions toward our previously announced target of more than $3 billion. By the end of the second quarter, the Rodeo Renewable Energy Complex reached full rates with the startup of the second hydrocracker and both pre-treatment units. The complex is processing approximately 50,000 barrels per day of renewable feedstocks. On the next two slides, I’ll focus on the improvements we’ve made to our cost structure. We’re approaching our $1.4 billion run rate savings target and the results are hitting the bottom line.

Slide 4 provides cost detail at the total company level compared with the first half of 2022. We’ve supported growing our business while mitigating inflationary impacts through business transformation. We’ve realized approximately $400 million in cost reductions, including our share of WRB costs. Additionally, we’ve been successful in driving efficiencies in our logistics spend that flow-through margin, as well as lowering our sustaining capital spend. Slide 5 highlights how our business transformation efforts have translated into a lower refining cost per barrel. Adjusted controllable costs, excluding turnarounds were $5.93 per barrel. We’re closing in on our target to lower cost by $1 per barrel. We continue to increase shareholder value through strong operating performance and disciplined capital allocation as we deliver on our strategic priorities.

I want to recognize our employees for their hard work and dedication to driving value creation for shareholders. Kevin, over to you.

Kevin Mitchell: Thank you, Mark. Slide 6 covers the key financial metrics. Adjusted earnings were $984 million or $2.31 per share. We generated operating cash flow of $2.1 billion and returned $1.3 billion to shareholders. I will now move to Slide 7 to cover the segment results. In the second quarter, we made changes to our segment reporting, including a new segment for our renewable fuels business. The new segment includes the Rodeo Renewable Energy Complex, as well as contributions from the optimization of renewable feedstocks, fuel sales, and credits. We also moved our investment in NOVONIX from the Midstream segment to Corporate and Other. Our slides and other reporting materials reflect these changes and prior-period results have been recast for comparative purposes.

Adjusted earnings increased $162 million compared with the prior quarter. Midstream results were up mainly due to higher volumes, including record NGL pipeline and fractionation volumes. In addition, costs were lower reflecting DCP synergy capture. In chemicals, results increased from higher margins. Refining was slightly lower than last quarter. Higher volumes and reduced operating costs mostly offset the impact of lower crack spreads driven by weaker distillate prices. Marketing and Specialties results were higher mostly due to seasonally stronger margins and volumes. Slide 8 shows the change in cash flow. We had strong cash flow aided by working capital and proceeds from asset dispositions. Working capital was a benefit of $916 million, mainly reflecting changes in accounts receivables and payables that include the impact of falling commodity prices.

We received $685 million in cash proceeds from the sale of our 25% interest in REX pipeline. Looking ahead to the third quarter, in chemicals, we expect the Global O&P utilization rate to be in the mid-90%s. In refining, we expect the worldwide crude utilization rate to be in the low-90%s and turnaround expense to be between $140 million and $160 million. We anticipate Corporate and Other costs to come in between $330 million and $350 million. For the full year, we expect refining turnaround expense to be between $500 million and $530 million. This is a reduction from previous guidance. And finally, in early August, we will begin publishing a monthly refining market indicator on our Investor Relations website. Now we will open the line for questions, after which Mark will wrap up the call.

Operator: [Operator Instructions] Our first question comes from the line of Roger Read with Wells Fargo. Please go ahead. Your line is now open.

Q&A Session

Roger Read: Yes, thank you. Good morning. I guess I’d like to dive in on the cost-cutting — the cost-savings realizations. You kind of showed a $1 barrel in refining. I just wanted to understand as you look at it, how much of it is, you’re running better, which helps on a per barrel basis, and how much of it is structural and we should think about built-in for the long run here.

Mark Lashier: Yes, Roger, we really view it primarily as structural. Of course, there’s going to be the influence of our utilization rate. The denominator gets bigger, the number goes down. But we are focused on driving inefficiencies out of our business across the board. And so it’s not only sustainable, we are going to continue to improve on that as we go forward. We’re going to focus on controlling the things that we can control, drive cost, and efficiency out without impairing our reliability or our utilization. And so that confidence is based on the cost reductions you’re seeing. If we — as the utilization moves around, the numbers will move around, but over time, they will continue to trend down.

Rich Harbison: Yes, maybe I’ll just add a little bit more detail to that, Roger. This is Rich over — in the Refining group. The first half of the year, we reduced our adjusted controllable cost by $0.83 a barrel and maybe that’s best explained by the people that are doing it and maybe a couple of examples here of what we’re doing. So, we have over 1,000 employees that have engaged in this process with over 1,000 initiatives that have been driven into our ways of working and actually reducing inefficiencies from the business. And probably no better way to say that than maybe an example here. So, one of the examples is actually using our midstream experience. We do tank turnarounds in refining. We do a lot of tank turnarounds, but our costs were very high on that compared to our midstream part of our organization.

So we took the best practices out of the midstream organization, applied them to the refining organization, we were able to drive $5 million a year out of the tank turnaround process. That’s one concrete example of how we’re changing how we work. There’s also another example of our hydrogen plant operations. And we went through an engineering process and reviewed a lot of the engineering principles used to operate that piece of equipment and we changed the steam to carbon ratio through a detailed review. And that ultimately ends up reducing fuel usage, which drove $5.6 million a year of fuel usage out of our cost profile. You add all these thousands of initiatives up and they’re well over $600 million of structural costs that’s been removed from the system.

So I’m very confident that that money, that dollar, that spend has been removed from our cost profile. And it’s because of this fantastic work that’s been done by our employees. And as Mark indicated, this dollar per barrel will move around with utilization, but that structural change of that cost profile has been removed.

Mark Lashier: Yes, Roger and we’ve got this mindset now of relentless pursuit of cost efficiencies, but really relentless pursuit of value-creation across the board. And that’s what’s going to sustain this. We’re not — we’re going to transition from business transformation to business excellence as we go forward and you’re going to see a sustained focus on value-creation through lower costs and greater efficiencies.

Roger Read: I appreciate that. Maybe shifting gears a little bit since it’s now broken out separately, Rodeo Renewable diesel. Give us kind of an idea of how you think that progresses, right? First, you prove you can run it, which clearly you’re doing here at 50,000 barrels a day. Now I would have presume it’s about getting the advantaged feedstock through the system. Maybe just an idea of where you are with that in terms of the PTU and kind of the market dynamics there to get that business maybe to, let’s say, breakeven and then profitable?

Mark Lashier: Absolutely, Roger. Thanks for the question. First of all, I just want to congratulate the team at Rodeo. They did an incredible job of safely commissioning and ramping up the new facility ahead of schedule, working through all the typical challenges of commissioning. We’ve got everything online, including both the pre-treatment units. And like I said earlier, we’re processing 50,000 barrels a day of renewable feedstocks. And as we speak, we’re transitioning to lower CI materials as we optimize the economic performance of the assets. And so we’re well positioned on the West Coast to deliver those renewable fuels all the way out to the retail end-user and we’ll also be producing renewable jets that we can feed into sustainable aviation fuel.

So, the commercial team works globally to secure consistent supplies of a wide range of feedstocks to ensure that we can optimize on the most economic feedslate possible and we’ve got the pull through to our retail stations that we’ve built-out in our last-mile strategy around this asset. So we believe that we’re well-positioned with a very large-scale facility, has scale advantages, logistics advantages, and market access advantages, and we’re going to exploit all those going forward.

Rich Harbison: Yes. So maybe just a little bit more color here. This is Rich again. The pre-treatment unit provides the flexibility and ability to really look at the various feedstocks out there in the marketplace. So we will begin the transition to lower our CI feedstocks, our carbon intensity of our feedstocks. We’ve been running roughly the soybean in the 50, 55 range. And we’re going to work on lowering that here in the third quarter and that continues to lower in the fourth quarter. I wouldn’t want to make sure we caution everybody though, not to be overly focused on carbon intensity because value is really driven by multiple factors that include a deliver feedstock cost to the Rodeo facility, the yield structure through the pre-treatment and eventually through the hydrocracking process as well as the carbon intensity value.

So, those are all combined into the value proposition. We will also start the production of sustainable aviation fuel or renewable jet in the third quarter here and continue to offer that. We will offer that to the marketplace in the fourth quarter of this year. The facility will be able to blend up to 20,000 barrels a day of sustainable aviation fuel. The Rodeo Renewable Energy Complex, it’s open for business. We’re pretty excited about it. It’s been a journey to get here. And maybe I’ll pass it over to Brian a little bit and he can add some more color to the marketplace.

Brian Mandell: Well, some comments on the marketplace. Biofuels margins were positive in Q2, but they were kind of on the lower end of the range. Even though U.S. renewable diesel fuel consumption was up 10% versus Q1, and we even saw an open up to Europe. So, what I’d say is looking further in the future, we think RD margins will begin to improve, have a list of reasons. First, more renewable jet will be produced. As Rich said, we’re working on that in Q3 and Q4 at our own plant and that will reduce the supply of renewable diesel. We see more marginal biodiesel producers continuing to shut. Our RIN prices may increase to make up for the PTC impacts. Demand for distillates in general, we think will begin to firm and the basis will firm, West Coast basis has been very low.

Veg oils prices, we think are likely to fall with the addition of crushing plants in the U.S. and Canada. And finally, the PTC program could potentially back-out international imports of renewable diesel. So I would, I guess, end by saying with all that said, there still remains a lot of regulatory uncertainty for next year, including credit programs, potential tariffs, clean-energy policy, and policies aimed at protecting farmers.

Operator: Our next question comes from Neil Mehta with Goldman Sachs. Please go ahead. Your line is now open.

Neil Mehta: Good morning, Mark and team. Very solid set of results. One of the big deltas versus our model was in Midstream. And so I wanted to give you guys an opportunity to talk about the momentum you’re seeing there, particularly with the NGL price realizations and volumes. And any color about what we should carry forward here?

Mark Lashier: Thanks, Neil. Yes, the Midstream had a great quarter, strong volumes and they’re benefiting from the synergy capture and the business transformation cost reductions they’re experiencing as well. So I’ll turn it over to Don and he’ll get his first shot in the barrel here.

Don Baldridge: Hi, Neil, thanks for the question. Yes, when you look at our second quarter results, certainly the improved costs are a standout. I mean, I think that’s a testament to our continued focus on the DCP integration work. We completed the last major milestone of our DCP integration in Q1. So, that was really around our back office and our IT system. So that’s positioned us well for some organizational efficiencies and cost savings that give us a lot of confidence in hitting our synergy capture for the DCP transaction. But as you mentioned, our NGL volume performance was quite strong throughout the quarter. That’s really a testament to the team running quite well, all of our assets. We’ve got just a lot of positive momentum in the basins that we’re connected to and able to run that volume through our system.

So, it’s really great to see that. From a pricing standpoint, actually, pricing was a little off for the quarter compared to the previous one, but I think it’s really the throughput and the fee-based performance that’s driving the business. And I’d say as we pivot to Q3, there’s some seasonality in our Q2, some one-timers. But as you look at Q3, we’ll have some volume impact with the Hurricane Beryl, taken some power outages at some of the some of the systems that we’re connected to, so that would have a volume impact. But I think we are in a good spot and really feel like we’re executing well on our wellhead-to-market strategy.

Neil Mehta: Thanks, team. And then the follow-up is just on asset sales. Can you remind us where we stand around — specifically around the retail and marketing sale in Europe and how we’re tracking towards the $3 billion target broadly.

Mark Lashier: Yes, thanks, Neil. We are in active discussions around those assets. There’s been strong interest. We have got a number of players interested in those assets. And so we won’t really comment further, but it would be a significant step in our asset disposition program.

Operator: The next question comes from John Royall with JPMorgan. John, please go ahead.

John Royall: Hi, good morning. Thanks for taking my question. So my first question is on your path back to your leverage target. I think you’re sitting at 36% today and I think you’ve made clear the priority is return of capital in terms of hitting the return of capital target versus the leverage target of this year. But looking into next year, is there a path to get you back to target levels? Are the expected asset sales enough to get you there? Or is there a possibility you could see an adjustment down on returns of capital to get yourself back in that range? And I think Mark reiterated the 50% target in his comments on the return of capital, but just any commentary there would be helpful.

Kevin Mitchell: Yes, John, it’s Kevin. So as you alluded, we will hit the $13 billion to $15 billion target range this year. We’re well on our way to that. As we all know, the refining margin right now is a weaker environment than we’ve seen in a little while, but nonetheless, we’re still confident in our ability to return cash and meet targets. But that does mean the balance sheet may take a little impact in the near term. But when we look ahead to next year, we’re quite confident in the cash-generating capabilities of the business. We have EBITDA growth coming and we also expect to generate cash from asset dispositions. So when you put all that together, we feel quite confident that we can both return greater than operating cash flow to shareholders, which we have committed as a target.

And at the same time, manage the balance sheet to where we want it to be. We’re not giving absolute dollar cash return targets for next year. At this point, that will be something we’ll evaluate in the second half of the year. But we think by the time we get through next year, we’ll be in a good spot with regards to cash returns to shareholders and balance sheet.

John Royall: Great. Thanks, Kevin. And then my follow-up on the M&A side. The Pinnacle acquisition, I think, demonstrated that you’re looking at both the buy-side and the sell-side in terms of M&A. And can you talk more about the buy-side? Is there more to do maybe around the midstream business or what else might you look to bolt-on or maybe the Pinnacle was — acquisition was more of a one-off and we shouldn’t expect more acquisitions.

Mark Lashier: Yes. Thanks, John. We’ve laid out and built out this Wellhead-to-market midstream backbone, and we think that we have the ability to leverage into assets like Pinnacle. Pinnacle, I would say, instead of being a one off, it kind of epitomizes what we’re looking for there. Assets that connected to our system can generate more value than they would be standing alone with their existing owners. And Pinnacle was a great acquisition because we were able to pick up this asset that is immediately accretive, that’s backed by solid fee-based contracts, and it also affords us an opportunity to almost on a shovel-ready basis to add to that position organically. So it’s kind of an inorganic and organic play and we’re able to get it at good value and be accretive from the get-go. And so I think things like that in that ballpark are exactly the kinds of opportunities we’re looking for to enhance our wellhead-to-market position, particularly in the Permian Basin.

John Royall: Thank you.

Operator: The next question comes from Ryan Todd with Piper Sandler. Ryan, please go ahead.

Ryan Todd: Yes, thanks. Maybe the first one for me, as we think about, you’re a few months into operations now with the TMX pipeline. Can you maybe talk about what you’ve seen in terms of impact on Canadian crude availability, pricing, impacts on the West Coast dynamics at all? And then maybe more broadly, your outlook for heavy crude differentials over the back half of this year?

Brian Mandell: Yes. Hi, this is Brian. I’d say that so far the pipeline is running 650,000 to 675,000 barrels, heading to 700,000 barrels by end of the year. About two-thirds of the incremental TMX barrels have been going to Asia, which has been a bit of a surprise for us and about a third to the West Coast. We benefit from barrels to the West Coast in both our Ferndale and particularly in our L.A. refineries. I think as we think about going forward, we’ve seen additions of Canadian production of up to 200,000 barrels by the end of year we think. And so we think basically those barrels will continue to grow. And in 2, 2.5 years, 3 years, we think increased Canadian production will put more pressure on the pipelines. The pipelines will be full once again and that will widen out the differentials.

Ryan Todd: Great. Thanks for that detail. And then maybe just a question is, if we frame your refining utilization guidance for the third quarter, it’s a bit lower than what you were running during the second quarter. Is this primarily driven by turnaround activity or some commercial pullback in operations given margin headwinds? And maybe put that in the context of more broadly, what you’re seeing in terms of kind of the refining macro as you look over the next quarter or two?

Rich Harbison: No, I’ll start here with the third — this is Rich. I’ll start with the third quarter guidance there on utilization. We’re actually guiding down right now because we do see softening in the market, and particularly in some regions on the coast, both West and East Coast. But we’re also going to take this opportunity as well to do some discretionary maintenance as the market has softened a little bit. And that’s fully intended to ensure we remain in a position to be able to run strong when the market returns and conditions improve. But we do see a little bit of softening right now in the marketplace. On a more broader approach, I’ll probably — I’ll turn that over to Brian there to talk about the broader macro components.

Brian Mandell: Sure, So just thinking about a gasoline diesel jet, maybe start with gasoline. What we’re seeing is global gasoline demand up about 1%, but down about 1% in the U.S. Our gasoline margins in Q2 were about where they were in Q1, but have been firming in the last few weeks with some larger refineries and extended outages. We’ve seen U.S. gasoline inventories fall now to below five-year averages and exports running about 900,000 barrels a day. But as Rich mentioned, we’ve been seeing economic run cuts, recent DOEs have shown a stronger implied gasoline and diesel demand. But week-to-week, the DOEs can be somewhat noisy. So we think with fall turnarounds and everything I’ve mentioned, this should help balance out the markets on gasoline.

On the diesel, global diesel demand has been down about 1% to 1.5%, but maybe slightly more in the U.S. and Europe of late. We’ve seen the U.S. truck tonnage recover some. It was off 2.7% in Jan through April, and in May, it was up 1.8%. So U.S. distillate stocks have also fallen a good bit under five-year average now. And then finally, the really bright spot is the global jet demand remains strong, 10% year-over-year, strong passenger throughput. In fact, in the U.S., throughput is now above 2019 levels, U.S. jet demand up about 4%. And I’d say, finally, although jet inventories are high in the U.S., U.S. jet cracks are generally leading gasoline and diesel in all regions.

Mark Lashier: Yes, at the 50,000-foot level, Ryan, I think that your refineries across the U.S. industry ran very well last quarter. And you think about what we’ve gone through in the last few years, the economics have been very strong for the U.S. refining fleet. Everybody’s had the cash flow to repair and clean up all of their equipment and it all came together, I think, last quarter, and then you have a little bit of the impact of some of the long-anticipated new volumes coming into market. But as we look out into the medium and long term, we see several things. U.S. remains advantaged versus much of the rest of the world. There’s limited capacity growth beyond 2025 and global demand continues to increase. So, when we look at the medium and long term, supply and demand will realign and we remain bullish on the medium, long-term refining fundamentals. So I think we’ve got even better days to come.

Ryan Todd: Thank you.

Operator: Next question comes from Matthew Blair with Tudor, Pickering, Holt. Please go ahead, Matthew.

Matthew Blair: Hi, good morning. Thanks for taking my question. So, on the refining side, your capture did move down in the second quarter, which seemed pretty understandable, just given some of the challenges on co-products, as well as narrowing crude diffs. Could you talk about the trends on capture so far in the third quarter? Do you expect things to improve here? And also, you mentioned in the midstream side a little bit of a headwind from the hurricane. Were any of your refining assets impacted in the third quarter?

Rich Harbison: Hi, Matt, this is Rich. Let me — I’ll start with the second question first. The hurricane impacts for our operation were minimal to none, I would characterize them. They — there was no substantial impact to any of the refining assets. There were some logistics — surrounding support logistics impacts, primarily on the electrical supply front, which were very short-term lived. And we were able to get those assets supplied up with some electricity and back online and back in the market very, very quickly. Third quarter, it’s off to a reasonable start. Certainly some carryover from the second quarter, but generally, we don’t provide that much level of guidance in the level of third quarter. As far as operationally, we don’t have any — other than our turnaround guidance that we’ve provided there and the outlooks, and our utilization where we think it will be is reflective of what we see the market.

Kevin here can provide a little bit more detail on that from his point of view.

Kevin Mitchell: Yes, Matt, I was just going to emphasize the point that I made earlier on that, next, we will start publishing our new refining indicator, which is a — it will be a closer reflection of our actual assets, geographies, yield structures, crude slates. And so, we’ll be — we’ll publish that for July next week. And so, we would expect our actual realized margin to track closer with that new indicator than our historic, more generic 3-2-1 crack. So you’ll get a little bit of a look next week when we get that out on our website.

Matthew Blair: Looking forward to it. Thanks. And then on the chem side, could you talk about your expectations for polyethylene pricing in the back half of the year? I’m seeing spot prices that are already up almost $0.02 a pound even since the start of Q3. And any sort of insights you have on just overall PE demand, and inventory levels would be helpful, too. Thanks.

Mark Lashier: Yes, absolutely, Matt. CPChem continues to operate really, really well, and they’re seeing strengthening demand in North America, as well as strengthening exports, which would certainly support the view that margins would continue to recover. European producers are struggling with the current cost environment, and Middle East producers face some export challenges because of the Red Sea-Suez Canal access; all on balance, favorable to CPChem. So we’re seeing those margins gradually improve and we continue to be constructive medium to long term as the value chain works out of that trough that we saw a few quarters ago. And I think we do see the inventory position improving, particularly domestically, which — also, since the U.S. is a large exporter now, lower domestic inventories indicates that the world markets are stronger, too.

Matthew Blair: Great. Thank you.

Mark Lashier: Thanks, Matt.

Operator: The next question comes from Jason Gabelman with TD Cowen. Please go ahead.

Jason Gabelman: Hi, thanks for taking my questions. The first one I wanted to ask is on the mid-cycle EBITDA guidance that you have previously spoken about at — I think it’s $13 billion to $14 billion, if I’m not mistaken. How is that trending so far? Do you still feel confident in that outlook? And where do you see some divergences between the outlook and the different segments? Thanks.

Mark Lashier: Yes. Thanks, Jason. We continue to believe that $14 billion is the EBITDA that we can generate at mid-cycle conditions and that we will be in position by 2025, given the mid-cycle conditions, to achieve that $14 billion. Now, I want to be clear that this isn’t guidance for 2025 that we believe that we will have the projects, the cost structure, the initiatives in place to achieve the $14 billion if we were at mid-cycle across the board. And whether or not we’ll be at mid-cycle in all of our operating units in 2025 is another discussion. I think you’ve seen the strong performance in midstream. We see midstream at or above mid-cycle. Strong performance in marketing and specialties. Chemicals is recovering, but not likely to be at mid-cycle.

We don’t believe — well, we haven’t really established a mid-cycle for renewable fuels, but we don’t believe that the renewable fuels segment will be at what we are inferring as a mid-cycle for that segment. And I think the big question is around refining. And we continue to execute projects to upgrade the value of the streams that we control, to enhance the market capture through our commercial operations. We continue to lower our costs, and we talked about how sustainable those cost improvements are. And that’s what gives us the confidence that we will that see refining able to contribute to that $14 billion of mid-cycle EBITDA.

Jason Gabelman: Great. Thanks. And my follow-up’s specifically on midstream. It’s been pretty volatile since the close of the DCP deal, $100 million-plus EBITDA swings quarter-to-quarter in a segment that we typically think of as being more stable quarter-to-quarter. Could you just give us a sense of why that volatility has been occurring and if you expect the segment to be this volatile moving forward? Thanks.

Don Baldridge: Yes, this is Don Baldridge. I think some of that volatility is really a reflection of the integration efforts and timing of the integration. And so, as I mentioned, we’re just finishing up the last major milestone in Q1 of our IT and back office systems. And I think that’s going to really help us kind of normalize and eliminate a lot of the variability that you may have seen through the timing and sequence of the integration efforts. So my expectation is that we’re on track to the $3.6 billion EBITDA guidance. If you look at our kind of trailing four quarters, we’re on that path, and I think you’re going to see us stabilize around that $675 million a quarter of IBT. So that’s how we see it, and I think we’re well positioned to start delivering on that.

Jason Gabelman: Great. Thanks a lot.

Operator: The next question comes from Doug Leggate with Wolfe Research. Please go ahead.

Doug Leggate: Thanks, guys. I apologize, my line dropped earlier, so I think I lost my place, but I appreciate you taking my questions. So, guys, I wanted to come back to the question of the medium-term refining outlook. I think you know where we’ve been historically on this. But our concern right now is that everybody, including yourself, is running really well. Whiting is back, for example. Utilization is on top of new capacity that’s been added both here and elsewhere. And I guess, my question is, when you talk about medium term, does it require another major turnaround cycle to clean up the capacity congestion we’re seeing? Because it seems that the U.S. can handle 95% utilization as a generic level.

Mark Lashier: I think as I talked about earlier, Doug, you’re seeing a number of positive factors around utilization aligned in the last quarter. And historically, it’s just not been sustainable to see that level of utilization across the industry. So, everything is clean, shiny, bright, new, and operating very well across the industry. And I think that you will see that, yes, it will roll into a normal turnaround cycle as things naturally evolve. So I don’t think you’ll see the kind of utilizations we witnessed on a sustainable basis across the industry.

Doug Leggate: Yes, it seems that everybody is running well post COVID, it seems. But I appreciate that. We’ll continue to watch it. I guess, I listened to your comments about renewable diesel and the $14 billion. And obviously, mid-cycle is a moving target. But can you help us with what you’re seeing since the plant came up versus, let’s say, that $700 million benchmark? Do you have any line of sight on RINs sorting themselves out to the point where that becomes a realistic target, or do you feel like you need to reset that lower at some point?

Mark Lashier: Yes, I think that RINs, LCFS, producer’s tax credits, all are in — are responding to the increased volumes. And the various jurisdictions will, over time, respond to ensure that there’s incentives to run. Brian is our expert in those matters, but we’re constructive on it in the long run.

Brian Mandell: Yes. And I’d say we’re not ready to adjust our mid-cycle yet. We’ll see. But you have to have the credits to incentivize people to run renewable diesel. And so, we think, over time, those incentives will be there.

Mark Lashier: Yes. And part of what you’re seeing now is just the length in distillate. So, that’s a big part of renewable diesel that has to — all those incentives have to float on top, just the base value of distillate. And there’s quite a bit of volume that’s been brought to the market and I think you’ll see markets respond and realign around that.

Doug Leggate: Great. Thanks for your answers, guys.

Operator: The next question comes from Paul Cheng with Scotiabank. Please go ahead.

Paul Cheng: Hi, guys, good afternoon or good morning, your time. First, Tim, congratulations on the retirement and thank you for the help. And also, thanks for the — giving — breaking out renewable diesel business and also that — some of the new chart in your presentation is helpful. Two questions. First, TMX, do you gentlemen believe that the impact in the West Coast market is already fully felt at this point or that you think additional changes may still come? And from that standpoint, how that impact your West Coast refining operation, if any? Have you changed the way how you run it? That’s the first question.

Brian Mandell: So, maybe I’ll start. I think that TMX is almost up to what we think will be full capacity, 700,000 barrels a day. So we think, currently, if Asia continues taking the same two-thirds of the barrels, we’re basically seeing the impact that it will have. And as far as our refineries, I’ve mentioned that we’ve got more barrels in the Ferndale, but its biggest impact has been on LA, where we’re able to get more barrels into LA at advantaged prices.

Paul Cheng: And just curious, I mean, if we’re looking at California, I think three months ago, we had this conversation, where we thought in the summer, California will be very strong margin, given you shut down Rodeo early in the year. But that was not the case. And so, do you have any sense that, I mean, how the demand seems? You have retail operation in California. Can you tell us that how is the California market shaking up in terms of demand?

Brian Mandell: Yes. So, I would say that after we shut Rodeo, the gasoline production there to make our renewable diesel, many market players, including us, Phillips 66, saw a need and an opportunity to resupply the market to ensure that California gasoline demand was met. And so, during Q2, more supply than needed made its way into the market and it put pressure on the basis and the margin basis came off $0.80 per gallon. But as the markets adjust to less domestic supply and more international supply, which will come in and ensure the market remains balanced, so timing of ships and imports into the market may cause some volatility from time to time, as we saw recently with the oversupply, Paul.

Paul Cheng: But I mean, how is your retail service station over there? How they perform? In terms of the same-store sales, can — is there any information you can share?

Brian Mandell: Yes. Demand in the West Coast has been off some, but the stores and the performance and marketing have been strong. So, I would say that we’re seeing some same-store sales demand off slightly, but not much. And we’ve seen the business doing well.

Paul Cheng: I see. Okay, good news. Thank you.

Operator: Our next question comes from Theresa Chen with Barclays. Please go ahead.

Theresa Chen: Hi. Going back to the early discussion of the Permian NGL build-out, for additional processing capacity growth from here, how do you balance the ability to grow organically versus inorganically, just given your midstream competitors on the NGL side right in the same area of the Midland, spending around $200 million per 200 MMcf per day processing plant built organically versus purchasing at over 2x that rate, plus the option to build another plant? Does the Pinnacle acquisition give you more organic opportunities in general or will a lot of this have to come inorganically?

Mark Lashier: Yes, Theresa, I think that when you think about the Pinnacle acquisition, it does just that. And yes, we understand that a — the newbuild multiple would be lower than the multiple you’d have to pay for a going concern. And you have to remember that we also brought in some very good high-quality, long-term fee-based contracts. And so, with an inorganic acquisition, you get to turn that earnings on instantaneously and you’ve got the contracts already there in place, and they’re solid and you know exactly what you’re getting. Organic growth, of course, there’s a time lag. And so, you build it, you’ve got the construction risk, the time lag risk, and then you’ve got to go out and contract it. We’re not adverse to doing that, but we think where we can bring in high-quality existing assets, backed by strong contracts tied right in the middle of our system, it makes tremendous sense.

And we’ll continue to look at organic opportunities as well. So it’s not an and, it’s not an either/or, but if the opportunity is right, we’ll acquire. If we need to build, we’ll build.

Theresa Chen: Got it. And as we look from now to the end of the decade and the sheer volume of upcoming Permian to Mont Belvieu NGL contract roll-off or Permian to Gulf Coast in general, how should we think about the weighted average rate on Sand Hills with all the legacy contracts in mind compared with the current going rate of, call it, mid-single digit cents per gallon?

Don Baldridge: Sure. This is Don. Yes, if you look at our pipeline system, almost 80% of that is contracted under long term, over five years in duration. And so, as we see contract terms shift, we’re pretty comfortable with our outlook. There’s some obviously, volumes that we recontract on a go-forward regular basis that are closer to the current market. But we feel pretty good about our outlook in terms of our earnings power across our — over our broad NGL long-haul pipelines.

Theresa Chen: Thank you.

Operator: Our next question comes from the line of Joe Laetsch with Morgan Stanley. Please go ahead.

Joe Laetsch: Hi, team. Thanks for taking my questions. So I wanted to ask more on the regional dynamic side. So I know you mentioned some weakness on the coasts, but what are you seeing in the central corridor in terms of balances and margins there?

Rich Harbison: Thanks, Joe. This is Rich. So on the coasts, let’s start on the Atlantic Basin side. Margin decreases did materialize and they really centered around the distillate pricing. And then we also saw some impacts on our secondary products. And what was happening on the secondary products was their prices were dropping as crude prices were rising. So, that was the bigger impact to market capture and margin collection on the Atlantic Basin. Now that — on our operation, that was partially offset by strong operating performance. The assets ran at 98% utilization and they also had a high clean product yield of 87%. So our efforts to continue to improve the business are offsetting these swings in — that we’re seeing in the marketplace.

On the West Coast, volumes were primarily higher for us due to the absence of a first-quarter turnaround at our Los Angeles refinery. The West Coast utilization was sitting at a nice 93% and the clean product yields were also up at 86%. So the plants were running well and putting product on the market. What we saw on our West Coast, the change in refining was primarily due to moving the San Francisco refinery Rodeo into the renewable fuels segment. So, we saw that move some costs out of refining and into the renewable fuel segment. But the West Coast operation always to remember, it is our highest operation — cost operating — high-cost operation in our portfolio. And Mark — or Brian has gone through the demand and the margins on the West Coast.

So I think that was enough color on that front. But we see that shift from San Francisco out of the refining into the renewable segment, kind of cleaning up our profile on the West Coast there. And then the Central Coast — or central corridor, I should say, the margins, what I saw in my numbers were the margins were relatively flat with two things occurring in that. We saw a benefit of an inventory impact that was a headwind in the first quarter. There was a $100 million inventory swing. So we saw that. So when we’re looking at it quarter-over-quarter, that impact was not existing in the second quarter and that was mostly offsetting lower feedstock advantages doing to the — our discussion around Trans Mountain Pipeline and the lower Canadian crude differentials.

Our assets in the central corridor ran very well at 102% utilization, which is an outstanding performance by that part of the organization.

Joe Laetsch: Great. Thanks for all the detail there. Shifting gears a little bit. I was hoping you could talk to the outlook for the marketing and specialties business here. So, 2Q and 3Q are typically seasonally stronger periods, but anything you could share on the setup for the rest of the year? And then I also think there were some minor changes with Rodeo getting broken out. So any color there would be great. Thank you.

Brian Mandell: Yes. This is Brian. We had a good quarter in Q2 with earnings increases seasonally from Q1. Our marketing business in U.S. and Europe along with lubricants business all showing improvements from prior quarter on the back of seasonality and falling prices. So we think that will continue in Q3. Seasonality in Q3 is usually good for the [technical difficulty]. And to your point on the renewable segment, we’ve moved the value of the marketing renewables business to the new segment, which is about $30 million to $50 million per quarter.

Joe Laetsch: Great. Thank you.

Operator: This concludes the question-and-answer session. I will now turn the call back over to Mark Lashier for closing comments.

Mark Lashier: Thank you for all your questions. Our team is executing across the board and delivering on our strategic priorities. The business transformation that we’ve been going through is driving $1 billion of cost reductions per year and lowering our refining costs per barrel. And we’ve got strong refining availability that contributed to our highest crude utilization rate in over five years and Midstream reported near-record results, benefiting from strong operating performance and continued synergy capture. At Rodeo, we’re processing approximately 50,000 barrels per day of renewable feedstocks. We’re optimizing our portfolio to generate incremental shareholder value and increase shareholder returns. Thank you for your interest in Phillips 66. If you have questions after today’s call, please call Jeff or Owen.

Operator: Thank you everyone for joining us today. This concludes our call and you may now disconnect your lines.