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.

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.

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.

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.

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?

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.

Operator:

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

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.

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.

Operator:

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

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.

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.

Operator:

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

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.

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.

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.

Operator:

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

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.

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.

Matthew Blair:

Great. Thank you.

Operator:

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

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.

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.

Operator:

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

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.

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.

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.

Operator:

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

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.

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.

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.

Operator:

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

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.

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.

Operator:

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

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.

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.

Operator:

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

Operator:

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

Mark Lashier:

Thanks, Jeff. Welcome, everyone, to our first quarter earnings call. We continued to progress our strategic priorities and we returned significant cash to our shareholders. While our crude utilization rates were strong during the quarter, our results were affected by maintenance that limited our ability to make higher-value products. We were also impacted by the renewable fuels conversion at Rodeo as well as the effect of rising commodity prices on our inventory hedge positions.

Operator:

[Operator Instructions] Our first question comes from Neil Mehta of Goldman Sachs.

Mark Lashier:

Yes, Neil, that's a great question. Thank you for asking that. The way I'm looking at this is those first quarter headwinds that you mentioned in Refining are all related to activities that will position us to deliver medium- and long-term tailwinds in support of our strategic priorities. And so it's some of the fundamental work going on around Rodeo and some of the work around our turnarounds are critically important.

Richard Harbison:

Yes, Mark. And Neil, when I reflect back on the quarter, I look at the metrics, and we ran pretty well. But the market capture, obviously, was challenged, and it was primarily driven by activity in the Gulf Coast and the West Coast. We achieved about an 84% clean product yield, which, for our assets, is pretty good. It's actually 1% higher year-over-year.

Kevin Mitchell:

Yes. Let me just put a couple of numbers to some of these items. So in terms of some commercial impacts that we talk about, on Gulf Coast product pricing differentials, in absolute terms, that was a $50 million headwind in the first quarter. The inventory hedges that I referenced in the earlier comments, which primarily impacts Central Corridor, that was a $100 million headwind in the first quarter. These are not variances, these are absolutes in the quarter.

Mark Lashier:

Yes. And I think, just to put that in context, we're taking a disadvantaged refinery and converting it into one of the world's largest renewable fuels facilities. And so to bridge to that, we took the heavy lift this quarter, and now we're well positioned to start delivering value again from the Rodeo facility as we continue to push it to full rates through the second quarter.

Neil Mehta:

That's a lot of good color. The follow-up is just on balance sheet, Q1 is always a noisy quarter for working capital. And that cash flow bridge, Kevin, is really helpful. But just your perspective on where you want to get your net debt to capital over time, what's the path to get there, including potential asset sales? And then how do we think about working capital getting into that equation? So big picture question around that metric.

Operator:

Our next question comes from Roger Read of Wells Fargo Securities.

Kevin Mitchell:

Yes, Roger, it's Kevin. So we're selling the Germany and Austria retail assets, like we said. That's a company-owned, dealer-operated model, primarily almost 1,000 sites across those 2 countries. That's a high-performing business, top-rated many years in a row, 10% of market share in each country. A great business, but doesn't really integrate with the sort of core strategic focus areas that we have as a company. So just a little bit of background as to why those assets.

Operator:

The next question comes from Ryan Todd of Piper Sandler.

Ryan Todd:

And do you have -- have you signed contracts on the SAF front? Are you in ongoing negotiations there with partners?

Ryan Todd:

Great. Maybe just one, changing gears to chems, on the Chemical side, the better-than-expected performance of CPChem. Can you talk about kind of the drivers of improvement there? Is it primarily feedstock-related? Are you seeing any signs of underlying improvement in market conditions and maybe how you're looking at the rest of the year?

Mark Lashier:

Yes. Ryan, you're seeing live the last almost 25 years of what CPChem has done to position themselves to be able to run flat out at the bottom of the cycle. And they did that, and they did that profitably. And you're seeing rationalization of assets in Europe while they're running at flat-out rates.

Timothy Roberts:

And Mark, to add on to that point, I think that's a great point. What you're seeing is that a lot of your higher-cost folks, they're running at reduced rates or they're shut down and extending maintenance or running at reduced rates. And we've even seen some facilities, namely in Europe, 2 announcements of 2 crackers that will be shutting down from some competition there because they're at the wrong place in the cost curve, whereas CPChem is on the right place in the cost curve.

Manav Gupta:

Guys, so you did a good job of explaining the variability in earnings quarter-on-quarter on Refining. Can we go through some of that in the Midstream? We saw a big variation on the NGL and Other side. I mean transportation wasn't off that much, but help us understand what drove the variability in the second part of that business.

Brian Mandell:

Manav, this is Brian Mandell. I would say that we've had a number of issues. We had a warm northeast U.S. winter, then refineries came back and they were running really well. Prices for diesel are in contango. We have seen about 200,000 barrels a day of Russian distillate off the market. But we are constructive. We do think the market will come back. You're seeing -- starting to see run cuts in Europe and Asia with hydrocracking and hydroskimming margins at breakeven.

Operator:

Our next question today comes from John Royall of JPMorgan.

Kevin Mitchell:

Yes, John. From a Europe standpoint, the other marketing businesses are in Switzerland, where we have a joint venture with Coop, and in the U.K. And the two are very different in that the Switzerland business is somewhat of a stand-alone retail business, but it's also in a joint venture structure, and so the dynamics are a little bit different around that.

John Royall:

Great. And then my next question is on the West Coast. And I think Mark sort of alluded to this a little in his response to Neil. But how should we think about the structural capture rate on the West Coast? And how it's going to be different now with the Rodeo officially an RD unit and not a refinery? Should we expect it to be higher than what we've seen historically as a result?

Mark Lashier:

Sure.

Operator:

Our next question comes from Matthew Blair of Tudor, Pickering, Holt.

Kevin Mitchell:

Yes, Matt, this is Kevin. The EBITDA, I'll give you the numbers that are on the information that we're providing to the prospective buyers. It's a -- the range is EUR 300 million to EUR 350 million, which the conversion for that is $325 million to $375 million. If you pick the midpoint, $350 million of EBITDA is probably your best number to go with on that.

Matthew Blair:

That's great. And then the $180 million hit from the Rodeo conversion, I think that's a little bit higher than what we're expecting. What drove that increase? And can you provide any sort of breakout on like how much of that was in gross margins versus OpEx versus depreciation? And then also, is it fair to assume that the current Rodeo plant is EBITDA negative since it's not running the low CI feeds yet?

Kevin Mitchell:

That's right. It's another uplift, yes.

Paul Cheng:

I have to apologize, but I want to go back into the West Coast. Can you share that what is the OpEx, excluding Rodeo? And also what is Rodeo going to look like once it's fully ramped up in terms of the OpEx? That's the first question.

Kevin Mitchell:

Well, it's probably down a little. There's still going to be an elevated element of that, and there's some what we would classify as turnaround-related costs associated with the conversion as well that will show up at Rodeo. But the trend is downward. We're past the peak spend, I guess, is the way to say it.

Jason Gabelman:

Yes. The first one is just on commercial performance. And I think you had discussed a desire to integrate different plans in terms of how you buy crude and sell product and try to maximize profitability across the portfolio, rather than at a site level. I'm just wondering if you could provide an update on that journey, and if you've seen any of that earnings benefit come through in the results. And then second, just a quick clarification. Can you remind us what your target cash balance is?

Kevin Mitchell:

And Jason, on the cash number, the target cash balance, the same as we've said in the past, $2 billion to $3 billion. We were slightly below that level at the end of the quarter. I'd also say, the first quarter is typically a heavy drain on cash quarter. So as we look ahead, we're still very comfortable with that target level.

Theresa Chen:

First, on the near-term outlook for capture in second quarter and maybe third as well. Just thinking about the different moving parts, you have presumably less noise from the onetime items impacting first quarter, whether it be from turnarounds or Rodeo. But you do have WCS narrowing based on your sensitivity and the magnitude that we've seen to date, that should be a sizable headwind.

Mark Lashier:

I think at a high level, Theresa, we are laser focused on the things we can control, and that's what we focus on, and that's what Rich and Brian focus on. I think that the things out of our control would be speculative. But I think Rich can talk about what we're doing to -- and what we see over the next couple of quarters with respect to market capture potential, and Brian can chime in from a commercial perspective.

Timothy Roberts:

Theresa, I'll verify the number, but we're well into, I would say, it's 65% to 70% third parties.

Mark Lashier:

Thank you, all, for your great questions. The market fundamentals that we're looking at are supportive, and our assets are running strong since the completion of seasonal maintenance activities. Our integrated portfolio is well positioned to capture market opportunities and to meet the peak summer demand.

Operator:

This concludes today's call. Thank you for joining. You may now disconnect your lines.

Jeff Dietert:

Thank you. Welcome to Philips 66 fourth quarter earnings call. Participants on today’s call will include Mark Lashier, President and CEO; Kevin Mitchell, CFO; Tim Roberts, 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 Philips 66 website along with supplemental financial and operating information. Slide two 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 it over to Mark.

Kevin Mitchell:

Thank you, Mark. I’ll start on slide five with an update on our business transformation progress and how we are reducing costs to sustain higher cash generation. We achieved $1.2 billion in run rate savings as of year-end 2023, comprised of $900 million of cost reductions and $300 million of sustaining capital efficiencies. Sustaining capital is one of our business transformation success stories. Our sustaining capital historically averaged about $1 billion per year and we added approximately $200 million with the consolidation of DCP Midstream. Despite the additional sustaining capital requirements from DCP, we reduced our sustaining capital spend to under $900 million in 2023. This $300 million benefit is also reflected in our 2024 capital plan. Through the end of 2023, we realized $630 million in cost reductions. The majority of these cost reductions relate to Refining, operating and SG&A expenses, as well as benefits to equity earnings and gross margin. On slide six, we provide more detail on the cost reductions at the total company level. Adjusted controllable costs were $8.4 billion in 2023, compared with $8.1 billion in 2022. The chart illustrates the main cost drivers year-over-year, including the impact of a full year of DCP consolidation. We continue to realize cost synergies from the DCP acquisition and subsequent integration. Our successful business transformation has already reduced costs, including our share of WRB costs, by approximately $500 million and this work continues. Slide seven provides a breakdown of Refining costs. Refining adjusted controllable costs, including turnaround expense and our proportionate share of WRB and MiRO controllable costs, decreased over $550 million to $5.2 billion in 2023. Business transformation savings reduced Refining costs by approximately $300 million. Additionally, lower turnaround expense and market impacts, primarily from lower utility prices, further reduced costs. These cost reductions more than offset inflationary impacts. On a $1 per barrel basis, adjusted controllable costs were $7.56 per barrel or $6.57 per barrel, excluding turnaround expense. This is a fully burdened cost that includes about $1 per barrel for Refining share of corporate allocations and SG&A expenses. The business transformation savings reduced our 2023 adjusted costs by over $0.40 per barrel. We expect to achieve our full $1 per barrel run rate target by the end of 2024. Additional details can be referenced in the appendix to this presentation. Slide eight summarizes our fourth quarter results. Adjusted earnings were $1.4 billion or $3.09 per share. We generated operating cash flow of $2.2 billion, including cash distributions from equity affiliates of $226 million. Capital spending for the quarter was $634 million. We distributed $1.6 billion to shareholders through $1.2 billion of share repurchases and $457 million of dividends. Net debt to capital ratio was 34% at year-end 2023 and return on capital employed was 16% for the year. Slide nine highlights the change in results by segment from the third quarter to the fourth quarter. During the period, adjusted earnings decreased $708 million, mostly due to lower results in Refining and Marketing and Specialties, partially offset by improved results in Midstream. In Midstream, fourth quarter adjusted pre-tax income of $754 million was a record, up $185 million from the prior quarter, reflecting improvements in both NGL and transportation. The NGL business increased primarily due to higher margins and record volumes at the Sweeney Hub, as well as lower operating costs. Transportation results were also higher, mainly reflecting the recognition of deferred revenue related to throughput and deficiency agreements. Chemicals adjusted pre-tax income increased $2 million to $106 million in the fourth quarter. This increase was mainly due to higher margins, mostly offset by lower equity earnings from CPChem’s affiliates and decreased sales volumes from lower seasonal demand. Global O&P utilization was 94%. Refining fourth quarter adjusted pre-tax income was $797 million, down $943 million from the third quarter. The decrease was primarily due to lower realized margins. Realized margins decreased due to lower market crack spreads, partially offset by inventory hedge impacts, higher Gulf Coast clean product realizations, wider heavy crude discounts and strong commercial results. Market capture increased from 66% to 107%. Marketing and Specialties adjusted fourth quarter pre-tax income was $432 million, a decrease of $201 million from the previous quarter. The decrease was mainly due to a seasonal decline in domestic wholesale fuel margins, primarily in the Mid-Continent. Our adjusted effective tax rate was 23%. Slide 10 shows the change in cash during the fourth quarter. We started the quarter with a $3.5 billion cash balance. Cash from operations excluding working capital was $2 billion. There was a working capital benefit of $207 million, mainly reflecting a reduction in inventory that was mostly offset by movements in accounts receivables and payables, which included the impact of declining commodity prices. We funded $634 million of capital spending and repaid approximately $100 million of debt. Additionally, we returned $1.6 billion to shareholders through share repurchases and dividends. Our ending cash balance was $3.3 billion. This concludes my review of the financial and operating results. Next, I’ll cover a few outlook items for the first quarter. In Chemicals, we expect the first quarter global O&P utilization rate to be in the mid-90s. In Refining, we expect the first quarter worldwide crude utilization rate to be in the low 90s and turnaround expense to be between $110 million and $130 million. Our turnaround expense guidance excludes costs associated with the conversion and start-up of the Rodeo Renewable Fuels Facility. At our San Francisco Refinery, we are executing the Rodeo Renewed Project. The facility operated as a crude oil refinery in January. [Audio Gap]

Kevin Mitchell:

… refinery, we are executing the Rodeo Renewed Project. The facility operated as a crude oil refinery in January and we will shut down crude operations in February, as we are prepared to start up renewable fuels production by the end of the quarter. We anticipate $100 million of decommissioning and start-up costs in the first quarter. We anticipate first quarter, corporate and other costs to come in between $290 million and $310 million. Full year guidance for 2024 is provided on slide 11 of this presentation. Now we will open the line for questions, after which Mark will make closing comments.

Ryan Todd:

Yeah. Thanks. Maybe starting out on margin, very strong margin capture in the quarter. Can you -- I know you talked about some of the things, but can you talk about some of the underlying drivers of that performance on the quarter, what might be seasonal or transient and maybe what you would highlight that might be more sustainable going forward in terms of improved performance?

Ryan Todd:

Great. Thank you. That was helpful. And then maybe a follow-up on Rodeo. I appreciate the update that you gave there in terms of some of the timeline that we can expect over the next couple of months. As we think about starting the renewable diesel plant. Can you maybe walk through, what you would expect in terms of the first three months to six months of operation there in terms of how long does it take the ramp to full operating capacity, how long does it take to you to get up and running? Maybe some of those things in terms of where we go from end of this quarter until you have kind of a full run right there.

Ryan Todd:

Yeah. Yeah. That was great. Thank you.

Manav Gupta:

Guys, congrats on a very strong quarter and a strong start to the year. Looks like everything is coming together. I just quickly want to focus on the NGO part of the Midstream business. There were some concerns that DCP synergies will be delayed or there’s some degradation of earnings. I think you have silenced a lot of critics over there with this earnings release, but help us walk through the sequential improvement we saw in the NGL business in the fourth quarter.

Tim Roberts:

All right. Thanks, Mark. Yeah. Manav, a couple things. I mean, really, it’s pretty simple. When you put the two -- with the transaction, you put the two businesses together, we had improved volumes, costs were down, we executed well operationally, we executed well commercially and then ultimately what that does is allow you to deliver results and we felt this was more representative of what we’re going to see in this business going forward. It really does highlight the strong earnings and free cash flow generation of the Midstream segment. Now, that doesn’t all happen by accident. It’s been a bit of a slog as we’ve slowly got those folks integrated. We’re almost done with the integration completely. We should be done sometime here early in the second quarter, once we get all the ERP and IT systems all under one versus still running two in parallel. So we expect to see some additional costs come off. But really, it’s just what I call blocking and tackling. We have -- the market hasn’t been overly helpful, so we’ve had to make do with what we can in this environment. And I think, like I said, you operate well and you commercially execute well, you give yourself a chance and I think this is representative of that. So overall, we like the transaction and we like where it’s going and we think it’s getting itself positioned well to go out and compete.

Brian Mandell:

Hi, Manav. It’s Brian. I’ll take that one. Global gasoline demand finished last year about 3% over prior year. We saw about 1% in the U.S. We expect 2024 global gasoline to grow almost 1% and we’re expecting U.S. to remain flat. Gasoline inventories continue at the high end of the five-year average for both U.S. and Europe. We think the majority of the stored gasoline is winter grade, particularly given the current strong octane values. Overall gasoline stocks, we think, should move back to the middle of the five-year range with spring turnarounds as we move toward the summer. On the distillate side, distillate demand finished 2023 about 2% over 2022 and the U.S. was actually down 2%, mostly in the West Coast due to rains and the renewable diesel production and imports. Latin America we saw up 2%. We expect 2024 global distillate demand to grow about 0.5% and the U.S. 2%, given the U.S.’s stronger economy. And U.S. distillate stocks are about 14% below five-year average and we’d anticipate draws through the spring maintenance season that should take inventories even closer to last year’s levels. And finally, on jet demand, finished last year 17% over prior year, with a total C count recovering to 2019. 2024 global jet demand is expected to grow about 6%, with continued recovery on international travel and we’ve seen cargo flights remain elevated and we think that’ll continue in 2024 as well.

Mark Lashier:

Thanks, Manav.

Doug Leggate:

Thank you. Good morning, everybody. Gents, I wonder if I could ask you about the EBITDA number for 2023, the $12.7 billion, you mentioned. If you rebase that to mid-cycle, where are we relative to the $14 billion target? It seems to us you’ve only got a year to go, basically, to do a very small amount of incremental cost-cutting. It seems you might have some upside to those numbers. So if you could help us rebase that, that would be real helpful. That’s my first question.

Doug Leggate:

That’s very granular and much appreciated. Thanks, Kevin. My follow-up is kind of a -- it’s a question on Rodeo, but a different question perhaps than you normally get? We’re trying to understand what the West Coast would look like if we rebased your capture rate, your historical relationship with realized margins versus indicators if Rodeo was not in the system. So I guess it’s kind of a request and a question at the same time, to the extent you can give us the history ex-Rodeo, that would be really helpful. But order of magnitude, was Rodeo loss making for most of the last several years or how would you characterize the EBITDA contribution? I’ll leave it there. Thank you.

Doug Leggate:

Thanks very much indeed, Kevin. We’ll look forward to that. Thanks.

John Royall:

Hi. Thanks for taking my questions. So my first question is on the balance sheet. You guys had guided to hitting the top end of your leverage range by year end 2023. You’re finishing a bit above that, which I think was just driven by the working capital impact of falling prices. So assuming a somewhat stable environment for working capital and price in 2024, do you have any updated guidance on when you think you’ll get back into that range?

John Royall:

Understood. Thanks, Kevin. And my next question is just on the turnaround guide for the year. You took a pretty big year in 2022 or a very big year in 2022, which I think was somewhat of a catch-up year. Last year was a pretty meaningful step down and the guidance looks like 2024 is basically same ballpark as 2023. So should we think of the average -- an average turnaround year from here as being somewhere in that kind of $600 million range and does the Rodeo conversion change that at all?

John Royall:

Thank you.

Paul Cheng:

Hey, guys. Good morning.

Paul Cheng:

Maybe the first one is for Kevin. Thank you. Kevin, can you tell us what in the fourth quarter was running at and what is the cost associated with that? And in the first quarter, the $100 million of decommissioning and decommissioning expense, I suppose that’s going to run through and not being treated as a special item?

Paul Cheng:

We’re trying to understand that without with Rodeo, what is the through-put run rate in the fourth quarter and what is the cost? Actually, yes, or that if you can tell us that what is Rodeo cost in the fourth quarter and what is the run rate also?

Kevin Mitchell:

Yeah. So we -- I mean, we don’t give out that sort of asset-specific level of financial information. What I can say is that the -- when you look at the fourth quarter results and the capture rates, the Rodeo starting to come -- turn operations down, we shut down one of the crude units in the fourth quarter. That did have a detrimental impact to our fourth quarter results versus if we were just carrying on in the traditional normal full crude operations at Rodeo. So it did have an impact. In terms of the $100 million of startup and decommissioning costs in the first quarter, we would not treat those as a special item. They will flow through as GAAP earnings or impact and that will be how we report the results, because they’re not, I mean, it’s normal for what we’re doing. It’s not a unique factor. Now, we can talk about it and you can choose to make your own sort of adjustments around it. But for us, it will just be part of our normal operating results.

Kevin Mitchell:

Yeah. So, I think, the bulk of the rest. So that’s one factor on that. You’ve also got the swing I mentioned on the Gulf Coast product pricing effect. You had a swing there from one quarter to the next. And you also have the benefit in there of our, we talked about our commercial performance during the quarter. That will also show up in that bar. So, all those things get reflected in that part of the representation.

Kevin Mitchell:

Yeah. I mean, it’s a combination of all of those items. So you see benefit on the product side. You see benefit from commercial contribution. You see the benefit from the inventory hedging items that we talked about. So they all combine to make up the bulk of that $7.

Operator:

Our next question comes from the line of Matthew Blair with Tudor, Pickering, Holt. Matthew, please go ahead.

Tim Roberts:

Yeah. Hey, Matt. This is Tim. Yeah. A couple things on that from the Chem standpoint. Yeah, we’ve seen actually pretty good stability with regard to polyethylene prices through the fourth quarter. Things were relatively flat from October through December. Then they got a $0.05 increase in January. How much of the $0.05 they actually get, I think, that might be a little bit of a discussion point. But nonetheless, it did highlight that the U.S. is running hard. Demand in the U.S. has been good, albeit steady in Europe, soft in Asia. The feedstock advantage here is really, you’ve got a highly utilized U.S. Gulf Coast kit, namely CPChem and they’re running hard. So you’ve seen some destocking that’s going on as well. So I think that’s helped underpin a little bit of momentum. Now, I don’t think anybody’s declaring victory on this at this point. I think there’s a lot of destocking that still needs to happen throughout the balance of the year. But it does tell you that the market forces are in play and you will see a rebalancing through 2024.

Matthew Blair:

Sounds good. And then, could you provide an outlook on your deferred taxes for 2024? It’s been a little volatile recently, but I believe that 2023 did come in above your overall expectations. What’s the outlook for 2024?

Matthew Blair:

Great. Thanks for the color.

Operator:

The next question comes from the line of Jason Gabelman with TD Cowen. Please go ahead, Jason.

Rich Harbison:

Yeah. Jason, this Rich. We will start off with the easier feedstocks generally and those are used vegetable oils, maybe some used cooking oils and some neat vegetable oils. As we get the pretreatment unit up and running and lined out, we’ll start introducing lower and lower CI carbon intensive feedstocks, which includes the fats, the greases, the tallows, those types of feedstocks, and we fully expect those to be introduced into the system towards the second half of the second quarter, maybe into the third quarter and we’ll slowly and continuously reduce that carbon intensity feedstock quality as we get more and more comfortable with the operation of the pretreatment unit and their impacts inside the processing units as well. So -- and I think our commercial organizations lined up with that same and they’ve been out and about gathering up these feedstocks and actively developing the aggregation facilities. And so they’re positioning quite well for the -- looking for the green light from the Rodeo team to go ahead and start sending these that direction and they’ll be ready when we’re ready.

Tim Roberts:

Yeah. Jason, that’s a great question. And no, that’s how we would look at it. If I look at 2024, as you kind of think about what we see that IBT looking like, we think that looks somewhere around on average, again, simple average across the four quarters about 675 a quarter. But you’re right, there’s some seasonality that comes into play. Typically, it’s a little stronger in the fourth quarter. Again, you nailed it, propane, butane, all those things kind of come into play. You see a little bit of that still in the first quarter. So, again, first quarter, fourth quarter, a little bit stronger, and then it comes off a little bit. But on average, about 675 is what we’re looking at. Now, that’s at mid-cycle. So, I want to be real clear there. At mid-cycle commodity pricing, that’s the framework we’re operating under. Now, obviously, if you look at first quarter, if there are winter events and things that happen that remember a couple years ago that we had and that’s a different game, too. We’ll have to -- we just deal with that when that occurs. But generally, that’s kind of the framework we’re looking at, again, on an IBT basis.

Operator:

Our next question comes from the line of Theresa Chen with Barclays. Please go ahead.

Mark Lashier:

Well, I won’t go into a lot of detail on that, Theresa, but what I will tell you is we’re long. We are long on NGLs. But actually, we want to be and that’s by design. We offload to third parties to run some of our product for us, whether to transport or whether to frac. And at some point, I’d like to think over time, as we continue to build scale on the integrated value chain that we’ve got, we’ll bring those volumes in-house. But at this point in time, like I said, we’re long and we are for the foreseeable future on NGLs.

Mark Lashier:

Yeah. As far as asset sales go, we said before that everything we have has a value and we understand what that value is and that’s what we’re focused on. If we can capture more value from someone else owning assets, then we’ll do that. But having said that, we are in some active discussions as we speak. There’s a number of processes underway that we can’t comment on, but all I’d say is, leave it there, that we’ll have more comments likely at our first quarter earnings call.

Operator:

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

Mark Lashier:

Yeah. Particularly in Chicago where the crack is now close to zero, a number of factors have caused that weak gasoline margins. Demand has been poor due to winter weather, which affected production, demand more than production. Refinings have been running strongly there. And then the upper Illinois River was frozen for 10 days, which blocked U.S. Mid-Con or Chicago exports from getting to the U.S. Gulf Coast. So kind of our view there is Chicago refineries are soon going to be in turnaround and there’s a closed arc from the U.S. Gulf Coast up north. We think things will clear up, particularly as winter grade gasoline has moved out of tank and the market switches to summer grade gasoline.

Mark Lashier:

I would say, first with Russia, now with the Red Sea, we have been seeing different arbitrage, different places. As you know, Russian barrels are going different places than they used to. But by and large, it’s just increasing freight rates and time. For us, that’s actually helpful because as it does that the European type barrels, the Brent TIs widen out and we buy more barrels at basis WTI, so for us, it’s a benefit. Also, we have a strong and robust bunker fueling business, which also benefits from the higher bunker sales for the longer voyages.

Operator:

Thank you. This concludes the question-and-answer session. I’ll now turn it back to Mark for closing remarks.

Jeff Dietert:

Thanks for all your interest in Phillips 66. If you have further questions, please call Owen or me. Thank you.

Jeff Dietert:

Good morning and welcome to Phillips 66 third quarter earnings conference call. Participants on today’s call will include Mark Lashier, President and CEO; Kevin Mitchell, CFO; Tim Roberts, Midstream and Chemicals; Rich Harbison, Refining; and Brian Mandell, Marketing and Commercial. Today’s presentation material 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 will turn the call over to Mark.

Kevin Mitchell:

Thank you, Mark. Adjusted earnings were $2.1 billion or $4.63 per share. A $9 million decrease in the fair value of our investment in NOVONIX reduced earnings per share by $0.02. We generated operating cash flow of $2.7 billion, including a working capital benefit of $285 million and cash distributions from equity affiliates of $361 million. Capital spending for the quarter was $855 million. We returned $1.2 billion to shareholders through $752 million of share repurchases and $465 million of dividends. We ended the quarter with a net debt-to-capital ratio of 33%. Annualized adjusted return on capital employed was 17%. I’ll cover the segment results on Slide 10. Additional details can be referenced in the appendix to this presentation. This slide highlights the change in adjusted results by segment from the second quarter to the third quarter. During the period, adjusted earnings increased $304 million, mostly due to improved results in Refining, partially offset by lower results in Chemicals and Midstream as well as higher corporate costs. In Midstream, third quarter adjusted pre-tax income was $569 million, down $57 million from the prior quarter. The decrease related to our NGL business and was mainly due to the timing of cargo freight costs as well as higher utility, integration and employee costs. These impacts were partially offset by higher margins from increasing commodity prices. Chemicals adjusted pre-tax income decreased $88 million to $104 million in the third quarter. This decrease was mainly due to lower margins. Global O&P utilization was 99%. Refining third quarter adjusted pre-tax income was $1.7 billion, up $592 million from the second quarter. The increase was primarily due to higher realized margins and strong utilization. Realized margins increased due to higher market crack spreads, partially offset by inventory hedge impacts, lower secondary product margins and lower Gulf Coast clean product realizations. Inventory hedges and losses from secondary products mainly reflect the impact of rising crude prices during the quarter. These market factors negatively impacted capture rate, which was 66% in the quarter. Marketing and Specialties adjusted third quarter pre-tax income was $633 million, a slight decrease of $11 million from the previous quarter, reflecting continued strong margins. The Corporate and Other segment’s adjusted pre-tax costs were $59 million higher than the previous quarter. The increase was mainly due to higher net interest expense related to acquiring DCP Midstream’s public common units on June 15 as well as employee-related expenses. Our adjusted effective tax rate was 24%. The impact of non-controlling interest was improved compared to the prior quarter and reflects a lower non-controlling interest since our acquisition of DCP Midstream public common units. Slide 11 shows the change in cash during the third quarter. We started the quarter with a $3 billion cash balance. Cash from operations was $2.4 billion, excluding working capital. During the quarter, we funded $358 million of pension plan contributions, which comes out of cash from operations. That was a working capital benefit of $285 million. Year-to-date working capital is a use of around $2 billion, primarily related to inventory that we expect to mostly reverse by year-end. We received $280 million from asset dispositions, mainly reflecting the sale of our interest in South Texas Gateway Terminal. Total proceeds from asset dispositions of $370 million through the third quarter of 2023. We funded $855 million of capital spending. This includes $260 million for the acquisition of a U.S. West Coast marketing business. We repaid approximately $500 million of debt, mostly reflecting lower borrowings on DCP Midstream’s credit facilities. Additionally, we returned $1.2 billion to shareholders through share repurchases and dividends. Our ending cash balance was $3.5 billion. This concludes my review of the financial and operating results. Next, I’ll cover a few outlook items. In Chemicals, we expect the fourth quarter global O&P utilization rate to be in the mid-90s. In Refining, we expect the fourth quarter worldwide crude utilization rate to be in the low-90s and turnaround expenses to be between $90 million and $110 million. We anticipate fourth quarter Corporate and Other costs to come in between $280 million and $300 million. Now we will open the line for questions, after which Mark will make closing comments.

Neil Mehta:

Thank you. Good morning, team. This was very helpful, particularly the commentary on the strategic priorities. And so I want to – on the bullet about maintaining financial strength and flexibility, you talked about moving from $3 billion to $4 billion of EBITDA growth and greater than $3 billion of non-core asset dispositions. So wondering if you could take some time to talk about what are the key drivers of the move from $3 billion to $4 billion? And then as you identify non-core asset sales, what are some of the parameters that you’re evaluating as we think about what assets could be part of that discussion?

Neil Mehta:

Okay. Alright, thank you. And then on the quarter itself, the Refining capture rates probably came in a little bit lower than street was expecting. Was that just timing effects with crude? Or is there anything else that we need to keep in mind as we think about what it all means for 4Q and 2024?

Neil Mehta:

It’s very helpful. Thank you, Kevin.

Roger Read:

Yes, thank you. Good morning and appreciate the winding up of the changes here, improvements, I should say, overall. The question I have, to start with, you mentioned $3 billion of target disposition proceeds, but you’ve upped your overall EBITDA target. So I’m just curious, what EBITDA is associated with those ops, if any? And what does that imply about the sort of extra growth in the overall performance of your raised EBITDA target?

Roger Read:

Okay. And I assume based on the idea that there is always a larger pool of assets that could be sold, that’s why it’s unclear right now what the net impact would be.

Roger Read:

Okay. And then a follow-up to Neil’s question on Refining margins, but maybe looking forward rather than back. The shift here, where diesel margins are well above gasoline, I think about generally a diesel yield improvement for you versus industry standards. Is that the right way to think about Q4 here? Or is there anything else that we should be paying attention to that would work against that?

Roger Read:

Great. Thank you.

Manav Gupta:

Good morning, guys. My question here is, and I know kind of answer, most likely you will not answer it, but we get this question a lot. A very strong result on the West Coast again. A weaker default in price environment. Is there a possibility you could let Rodeo Renewed a little longer and capture higher margins and then just wait for LCFS to rebound later in 2024? So is there a way you could – is there a possibility you could move the timing of startup of Rodeo to better coincide with higher LCFS prices and, in the meantime, make more money on the West Coast?

Brian Mandell:

Hi, Manav, it’s Brian. So when you think about the RD margins, you have to think about not just the credits but the price of the feedstock, the price of the RD when it comes to market. So even though we’ve had lower LCFS and RINs, we’ve had these distillate prices that have outrun soybean prices. In fact, soybean prices are off. We have more low CI feedstocks that are making their way into the U.S. Kinder Morgan pipeline is allowing RD on their pipelines now, so that means more reach of RD into the California market for consumption. We’ve had – domestic demand is expected to continue to grow. We’ve converted all our stations. We’re seeing RD demand in Oregon and Washington continue to mature as those programs mature. We’ve been seeing RD moving to states like Texas and Illinois and Colorado, where they have tax abatement and tax reduction programs. And I think traders believe that the U.S. harvest is looking good. And if you remember last year, in Argentina, they had a drought. And this year, we expect a more normal crop level condition. And then finally, what a lot of traders and folks have on their minds is SAF or renewable jet. And as those incentives make more sense to produce renewable jet, you’ll see some of this RD that’s being produced move away and become SAF. So we’re expecting about 200,000 barrels a day of RD at the end of this year, but we will see some of that RD in the future become renewable jet.

Brian Mandell:

Hey, Manav, it’s Brian again. So I’ll say we had a really strong quarter in the third quarter. In fact, it was our fourth best quarter on record. Q2 and Q3 are usually stronger seasonally than Q1 and Q4. And as you remember, starting 2019, we’ve added a lot of retail to our retail joint ventures in the U.S. We’re up to 700 retail stores now, and they performed really well this quarter. We’re also focused on what we’ve called the last-mile strategy internally, which is getting Rodeo complex RD to the market, directly to the market, and getting that value chain value at Phillips 66. We’ve seen product volumes in our businesses relatively flat, but we continue to optimize those volumes through higher-value distribution channels. So as a reminder, we have a wholesale business, we have a branded or franchise business, and then we have a retail business. And the branded or franchise business and the retail business, those margins are significantly higher than the wholesale margins. And then finally, on the lubricants base oil business, it continues to perform really well. So I’d say, for Q4, we think that earnings will be in-line with our normal Q4 mid-cycle expectations.

Manav Gupta:

Thank you.

Doug Leggate:

Thanks. Good morning, everybody. And appreciate all the updates this morning. Mark, I wonder if I could try the disposal question again. I just want to be clear where you guys are in this process. Have you internally identified the assets for sale? I just wanted to be clear on that. And maybe what your expectations are of time line? I don’t think that’s been touched on, and I’ve got a quick follow-up on Refining.

Doug Leggate:

Thank you. My follow-up is on Refining, and I’m going to ask for a little forgiveness on this one ahead of time. But I think you know where our position has been on the strength of the Refining sector, the Refining cycle going forward, volatile as it may be. And we’ve kind of challenged you guys a few times on what you’re assuming as a mid-cycle sustainable EBITDA for your business. So I’m curious if you could walk us through – and expedition’s always possible, given we’re on this call, what the moving parts are behind the contribution of Refining to the new mid-cycle targets? The capture rate is one part, but you’ve been running ahead. When your facility has been running, you’ve been running ahead for quite a while now. And similarly, your utilization rates were not great. Now they are better. Is that a big factor? I’m just wondering what the key kind of moving parts are in the assumptions and what the contribution is from Refining in your new targets. Thank you.

Doug Leggate:

Kevin, has your utilization assumption changed?

Doug Leggate:

Terrific. Thank you very much.

Ryan Todd:

Thanks. Maybe if I could, a question on the shareholder return target. Thanks for the positive update there. I mean, at the midpoint, it implies, I think, roughly $1 billion a year of buyback a quarter to year-end 2024, which is a nice step-up from what we saw during the third quarter, pretty close to the pace that you’ve had year-to-date in 2023 in what has been a – obviously is like – certainly an above-mid-cycle environment. So can you maybe talk about your confidence in – what drove your confidence in being able to lean into the shareholder return target in that way, maybe what it implies in your view of the outlook from here? And on the – should we think – you’ve been above pace on – your prior mid-cycle target has been above mid-cycle. Should we think of it the same way, where, if we continue to stay above mid-cycle in 2024, that you’ll drive towards the upside or beyond and that type of target?

Ryan Todd:

Okay. Perfect. That’s very helpful. And then maybe just a question on the Midstream. You’ve had a little bit of time now with the consolidated position there, DCP under your belt at this point. Synergies have moved a little bit higher from $300 million to $400 million. Maybe can you talk about how you view the opportunity set there, both in terms of what you’re seeing in terms of your ability to drive commercial improvements there and maybe incremental growth down the line?

Mark Lashier:

Yes. And I would like to throw another example out there, Ryan, that last week, a group of us visited the Sweeny Complex, and we got to stop by the control room that operates all of our fractionators. And I asked a couple of frontline operators how they felt integration was going, and they were ecstatic because they see the ability to improve their ability to perform. They see it in real time. They said we can run at harder rates because we get better information, there is greater collaboration. They can run without concern or surprises coming at them. And so the whole mindset around business transformation, synergy capture, being more competitive has evolved all the way to the front line. These folks want to win, and they want to figure out every day how to do better and how to drive more synergies and capture that and deliver value. So, it’s real, and it’s out on the front line.

Operator:

Thank you, Ryan. Paul Cheng from Scotiabank. Please go ahead. Your line is open.

Mark Lashier:

Good morning Paul.

Mark Lashier:

Yes. Paul, what I think you are asking is you are applauding the good performance you have seen in the marketing group, and it continues to increase, as Brian and his team execute their strategy. And you are asking, is there a reset in the mid-cycle performance of the marketing business, is that the question?

Brian Mandell:

Paul, this is Brian. I would say we did raise the mid-cycle a couple of years ago, and we will continue to watch it. And if we need to raise it again, we will. But obviously, the business is performing better and we are proud of the business performing better. We are going to continue to look for opportunities to add to the last-mile strategy and some of our other initiatives. So, as we see that value hitting the bottom line, we will indeed, at some point raise the mid-cycle.

Brian Mandell:

I would say keep watching the bottom line, and you will see the dollars there. And when we feel comfortable, we will move mid-cycle up.

Paul Cheng:

Okay, fair enough. And maybe this one is for Rich. Rich, can you share with us that – what’s the Phillips 66 turnaround activity look like for next year? Is it comparing to this year, whether it’s going to be higher, lower or about the same? And also, what’s your view about the industry turnaround activity for next year? Thank you.

Operator:

Thank you, Paul. John Royall from JPMorgan. Please go ahead. Your line is open.

Kevin Mitchell:

Yes. I mean, John, the market environment will impact profitability. It will impact cash generation. But the bulk of the working capital benefit we expect to see in the fourth quarter will be driven by inventory impacts, and that’s pretty solid in terms of that impact. So, while there will always be other parts moving around in this equation, I feel pretty confident that the top end of that targeted range is – we will be around about there at the end of the year. I am not too concerned by that.

Brian Mandell:

Hey John, it’s Brian. So, like you said, the WCS dips are very wide, minus $25 now. That’s a benefit to us. We are the largest importer of Canadian crude, nearly 500,000 barrels a day. The reason the dips are wide is because you have more production than you have pipeline egress. And you also have the diluent blended into – starting in September, into the crude, which adds or swells volume. We would expect to see the dips remain seasonally wide with more barrels than egress as traders also sell barrels to meet the year-end inventories. TMX has announced the start-up in April. We will take them at their word. Currently, we don’t think the pipeline will run at full capacity. But if you take a look at the forward curves currently, Q2, Q3 average is about minus $15, and that’s about where we think it might end up.

Operator:

Thank you, John. Jason Gabelman from Cowen and Company. Please go ahead. Your line is open.

Rich Harbison:

Jason, this is Rich. Are you asking about the co-product bucket?

Mark Lashier:

Secondary products.

Jason Gabelman:

Got it. Thanks. And my follow-up is on the $3 billion divestment target and not really where that’s going to come from, but use of proceeds. You mentioned in the earnings press release that those proceeds will be deployed to strategic priorities, including returns to shareholders. But I was wondering if there is a desire to use some of that cash to continue to grow and just, kind of in broad strokes, what type of growth you would prioritize? Thanks.

Jason Gabelman:

Got it. Thanks for the color.

Operator:

Thank you, Jason. Matthew Blair from Tudor, Pickering, Holt. Your line is now open. Please go ahead.

Operator:

Hi Matthew, unfortunately, your line is breaking up, so we will have to move to the next question. If you would like to rejoin the queue and potentially try dialing back in.

Tim Roberts:

Yes, let me do that. Sorry, Matt, with the breakout there. I got the front end of it. And so I could take a wild guess on the back end, but that probably wouldn’t go well. So, from a chem standpoint, look, it feels like a little bit of a broken record. We still have a supply-demand imbalance. Clearly, China, Asia is not where we would like it to be. Over time, we expect that to come back around. But you are going to have to see a correction in the new capacity that’s coming onboard, coupled with demand picking up. So, we do think that’s going to be hard to see at least through 2024. But to your point, I mean when you have things like we have seen a little bit of improvement on polyethylene, you see a couple of price increases, which have been good. I don’t know if they are sustainable, but nonetheless, they have come through, which has helped. And we have seen inventories coming off slowly, but coming off. So, from that standpoint, there is a little bit of, I am going to say, constructive, but we know that balance has got to get fixed. Now, the one thing that I think is really important we stress here is, though, that CPChem’s kit and their assets, 96% of their assets are utilizing advantaged feedstocks. So, while there may be a lot of pain in the chemical space, those that are leveraging advantaged feedstocks are doing okay. We would love to be doing a lot better, but they are doing okay. Our assets at CPChem are running hard as well as probably their competition using light feed in the U.S. Gulf Coast and in the Middle East. But those that are using naphtha in higher-cost regions are probably challenged at this point. Our teams are running hard, running well, taking advantage and are well positioned to actually benefit from this low-margin environment because of the feedstock we are in. So with that, we still think, though there is some more lifting to do with regard to getting the supply-demand balance where it needs to be, but if we can continue to see some green shoots like the GDP that we saw earlier this week, maybe you put a couple of those together, and we can start moving that forward.

Joe Laetsch:

Hi team. Thanks for taking my questions. So, I wanted to just start on the demand side. So, recognizing the DOE demand data has been really volatile, could you just share what you are seeing in your system across gasoline, diesel and jet? And then if possible, just your outlook for the remainder of the year, realizing that it’s really volatile right now. Thank you.

Joe Laetsch:

Got it. Thanks. Appreciate your response on that. And I just wanted to ask, on the dividend, so we have – it was good to see the increase in the target. We have touched on the buyback a bit. But could you just remind us how you are thinking on dividend growth from here?

Joe Laetsch:

Great. Thanks. Appreciate it today.

Operator:

Thank you, Joe. This concludes the question-and-answer session. I will now turn the call over to Mark Lashier for closing comments.

Jeff Dietert:

Thanks Mark. If you have any additional questions, please call Owen or me. We appreciate your participation on the call today. Thank you.

Jeff Dietert:

Good morning, and welcome to Phillips 66 Second Quarter Earnings Conference Call. Participants on today's call will include Mark Lashier, President, and CEO; Kevin Mitchell, CFO; Tim Roberts, Midstream and Chemicals; Rich Harbison, Refining; and Brian Mandell, Marketing and Commercial. Today's presentation material 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 it over to Mark.

Kevin Mitchell :

Thank you, Mark. Starting on Slide 5 with an update on our business transformation progress. Our $1 billion business transformation target includes $800 million of cost savings and $200 million of sustaining capital reductions. We have identified over 2,700 initiatives to permanently reduce costs, with employees across the organization actively engaged in the transformation process. We have completed 1,200 initiatives that are generating value today. The chart on the left shows our progress toward the $800 million cost reduction target, with $550 million of run-rate cost savings at the end of the second quarter. The stacked bar shows our actual cumulative cost reductions for the year by category. Over the first half of 2023, we realized $260 million in cost savings. The majority of these cost reductions relate to Refining, which has benefited by about $0.40 per barrel. Business transformation initiatives range from optimizing services across our portfolio of assets to establishing new tools to improve use of steam and energy. Organizationally, we strengthened our centralized model for core functions to drive consistency and efficiencies. We continue implementing cost savings initiatives and are on track to achieve our run rate target by year-end 2023. We expect to realize the full $800 million of cost savings in 2024, which will include Refining cost reductions of $0.75 per barrel. Now I'll move to Slide 6 to cover the second quarter financial results. Adjusted earnings were $1.8 billion or $3.87 per share. The $15 million decrease in the fair value of our investment in NOVONIX reduced earnings per share by $0.03. We generated operating cash flow of $1 billion, including a working capital use of $1 billion and cash distributions from equity affiliates of $239 million. Capital spending for the quarter was $551 million, including $339 million for growth projects. We returned $1.8 billion to shareholders through $1.3 billion of share repurchases and $474 million of dividends. We ended the quarter with 445 million shares outstanding. I'll cover the segment results on Slide 7. Additional details can be referenced in the appendix to this presentation. This slide highlights the change in adjusted results by segment from the first quarter to the second quarter. During the period, adjusted earnings decreased $199 million, mostly due to lower results in Refining and Midstream, partially offset by an improvement in Marketing and Specialties. In Midstream, second quarter adjusted pretax income was $626 million, down $52 million from the prior quarter. The decrease was driven by the impact of declining commodity prices in our NGL business. This was partially offset by higher volumes in transportation. Chemicals adjusted pretax income decreased $6 million to $192 million in the second quarter. The industry polyethylene chain margin increased by $0.03 to $0.20 per pound. However, this was offset by higher maintenance and turnaround costs in the quarter. Global O&P utilization was 98%. Refining second quarter adjusted pretax income was $1.1 billion, down $460 million from the first quarter. The decrease was due to a decline in margins, partially offset by higher volumes and lower operating expenses. Realized margins decreased primarily due to the decline in distillate crack spreads and narrowing heavy crude differentials, partially offset by improved gasoline cracks. In addition, realized margins reflect the impact of losses from secondary products due to declining NGL and coke purchase. Marketing and Specialties adjusted second quarter pretax income was $644 million, an increase of $218 million from the previous quarter, mainly due to seasonally higher global marketing margins on continued strong demand. The Corporate and Other segments adjusted pretax costs were $12 million lower than the prior quarter. The adjusted effective tax rate was 22%, consistent with the previous quarter. The impact of noncontrolling interests was improved compared to the prior quarter and also reflects our acquisition of DCP units on June 15. Slide 13 shows the change in cash during the second quarter. We started the quarter with a $7 billion cash balance. Cash from operations was $2 billion, excluding working capital. There was a working capital use of $1 billion, mainly reflecting an increase in inventory, which included the impact of unplanned downtime at the Bayway Refinery and seasonal storage opportunities. Year-to-date working capital is a use of around $2 billion, primarily related to inventory that we expect to mostly reverse by year-end. We funded $551 million of capital spending. In June, we drew $1.25 billion on a single-draw term loan to partially fund the acquisition of the DCP units for $3.8 billion. This transaction and the redemption of DCP's Series B preferred units of $161 million are represented as repurchase of noncontrolling interests. Additionally, we returned $1.8 billion to shareholders through share repurchases and dividends. Our ending cash balance was $3 billion. This concludes my review of the financial and operating results. Next, I'll cover a few outlook items. In Chemicals, we expect the third quarter global O&P utilization rate to be in the mid-90s. In Refining, we expect the third quarter worldwide crude utilization rate to be in the mid-90s and turnaround expenses to be between $110 million and $130 million. We anticipate third quarter Corporate and Other costs to come in between $280 million and $300 million, reflecting higher net interest expense from funding the purchase of DCP units during the second quarter. In 2023, we expect our full year capital spend to be above the $2 billion budget, reflecting approximately $200 million of additional spending on Rodeo Renewed. In addition, we just closed on a $260 million acquisition of West Coast marketing assets. This acquisition supports the high-return Rodeo Renewed project by optimizing the full value of our renewable fuel sales to end customers. We continue to review our portfolio to determine if assets meet our strategic long-term objectives or if they provide more value to third parties. Earlier this year, we divested the Belle Chasse Terminal, and very recently, we sold our interest in the South Texas Gateway Terminal. Total proceeds from the two transactions are approximately $350 million. Now we will open the line for questions, after which Mark will make closing comments.

Doug Leggate :

I'm not sure who wants to answer this, maybe Kevin, but we've obviously talked ad nauseam about what we think could be a new mid-cycle Refining outlook. But what we haven't taken into account is the continued upgrade to your synergy targets, the faster delivery of your cost reductions, and more importantly, the continued appearance of deferred taxes in your operating cash flow. So, Kevin, I guess my somewhat convoluted question is, what do you think your sustainable mid-cycle free cash flow looks like for the company post these recent series of changes that you've introduced?

Doug Leggate :

Just to be clear, you have not changed your view of mid-cycle margins, is that right?

Doug Leggate :

Okay. Thank you. My follow-up, just a quick one. The step-up in the back piece. Is that a transitory perhaps as a consequence of the DCP process? I'm not quite sure what other things might have delayed you. But I guess my point is that if I look to the $5 billion to $7 billion buyback guidance you gave through 2024, two things come to mind, which is well, it seems to us you could maintain an elevated pace and certainly a pace well beyond 2024. So, I could just wonder if you could just touch on the cash return strategy, and I'll leave it there. Thanks.

Operator:

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

Kevin Mitchell:

Yes, Neil. I think we had given guidance that we expected our debt to cap to increase once we completed the buy-in of the DCP units. And so, it wasn't a surprise to us where we landed on that number. The two big drivers that will bring that back between now and the end of the year are what you pointed to, working capital. So that's about $2 billion inflow in cash that we expect to see between now and the end of the year, and then also just the ongoing ability to generate earnings, generate strong earnings, and build to equity. So, on our math, we think we end the year at right around the 30% level, so the top end of the range, but nonetheless, still within that overall target range. Obviously, this thing will move around quarter-over-quarter depending on what's going on in terms of market environment and cash items like working capital. But fundamentally, we think we're on a reasonable trajectory to be able to sustain in that target range.

Mark Lashier :

Yes, Neil, it's Mark. I'll cover it at a high level and then Rich can drill in a little bit. But essentially, what we've experienced there as we commenced the project execution, we had a lot of heavy rainfall. And of course, even the start of the project was deferred a little bit because of permitting challenges. And we believe -- we recognize that the earnings from this are going too far exceed the earnings we realized to date from the San Francisco refinery so we wanted to stick to the schedule. So, we incurred some more cost to compensate for the productivity loss during bad weather and delays around permitting. We also saw some inflation. When this project was sanctioned, the big run-up in inflationary pressures hadn't hit yet. And so, we realized that really is the only project in our purview where we're seeing that kind of impact or haven't accounted for the inflation at sanction, so we're having to take care of that. So, we still look at that $1.60 a gallon as incredibly competitive. The overall competitiveness of the asset is strong. The location, we've got competitive advantage. The pull-through with our retail presence is a competitive advantage. And as you look at as we bring this facility online, we're taking off almost as much traditional diesel as we're bringing in renewable diesel to the market, so the market disruption will be minimal. So, we really are bullish around this project, and we see that the economics are still very robust in spite of the cost increases. Rich, do you want to go...

Mark Lashier :

And when you look at those increases across '23 and '24, it will require a modest increase in our capital target of $2 billion for this year, but we will manage that additional cost within our $2 billion target going forward in 2024.

Roger Read :

Thank you. Good morning. I was hoping to follow up on the DCP transaction, just how that's gone so far. And while I understand you've raised the, I guess we would call it, cost savings, another part of this transaction was on the revenue synergy side, building a truly integrated model. So, I was just curious what you've seen to date, what you maybe expect in the near term on that or maybe even the medium term on that in terms of how the transaction comes together as a seamless organization.

Mark Lashier :

Yes, I'd just like to comment a little bit on that, the integration impact. This really is a clear indication of how well the teams are integrating, the DCP team, the Phillips 66 teams coming together. And as Tim noted, once we had operational control of the entity after the Enbridge transaction, we were able to really hit the ground running and started executing against our targets. And getting these teams integrated, one team, one culture, taking the best of the best and driving this, this is really the biggest visible measure of how successful that's been. And we see those numbers move up and we see teams excited about the future and looking at ways to capture more value, both from a cost perspective and a commercial perspective. And so, this is going to be what they are and what they do from this point forward.

Rich Harbison:

Yes, Roger, this is Rich. We're well on our way, as you indicated, to our $0.75 per barrel savings target that we announced or committed to during the Investor Day last November. And you know what's most exciting about this whole process for me has really been how the organization, the entire organization is engaged in this process. So yes, there is some oversharing site to site of activity in best practices. But most of these activities are opportunities identified by that local organization, really accepting the challenge to improve the business. And they're uncovering these opportunities to be more efficient in their work process, right? And changing -- and then fundamentally changing how that work process is occurring to drive inefficiencies out of the business, which ultimately reduce costs out of the business. So, if you think about, we talked about $0.40 a barrel already year-to-date. If you -- that's calculated by, if you take our barrels that we've run year-to-date and calculate to the $0.40, you can back into the number that we're seeing drive to the bottom line of our financial report there. And that's been quite impressive. And we've got a lot more in the queue, as Mark indicated on his comments, with the run rate. Our target is $550 million. Over $300 million of that is currently assigned to Refining. And of course, the run rate doesn't mean it's realized, right? But that just means it's identified, it's locked in. And now we've got to drive it to the bottom line, and that's what's most impressive about the organization, really pushing to get these identified opportunities pushed to the bottom line.

Operator:

Our next question comes from John Royall of JPMorgan. Your line is now open. Please go ahead.

Rich Harbison:

John, this is Rich. FCC repairs were complete and the unit is up and running as of July 20. That's the actual date that it was back online producing on specification material. The refinery itself is back to normal operations, so all the units and all the assets there are running to our plan. The Bayway team did a phenomenal job getting that repair work done very efficiently. Very excited about how they performed to complete that work. And additionally, when Mark's just talking about this mindset activity, we saw other parts of our organization also really focused to help pick up our teammates that were struggling a little bit in Bayway. And we saw phenomenal performance in our refineries in Sweeney, Ponca City and Billings. They each had record performance as well as our assets on the West Coast, and it all ended up in a system-wide utilization of 93%, which is our highest crude utilization since 2019. So -- and we're looking forward to building on this momentum and continuing that into the third quarter.

Brian Mandell :

It's Brian. Maybe I'll just talk about product demand, give you a sense of what we're thinking for Q3. The strength in U.S. products basically starts with low inventories. Gasoline, we're under five-year averages by 7%. Distillate, we're under averages, five-year averages by 19%. That's a lot. We have a lot of new capacity coming online in the U.S., but we've had even more outages than the new capacity. For us, we're seeing gasoline demand up about 2% over last year in the U.S. and about 4% globally. So that's strong demand. On distillate, we have the demand down a bit in the U.S., mostly on industrial manufacturing segments. But globally, we have it up. We have lots of pockets of really strong distillate demand in Latin America, up 9%, Asia up 4% and diesel cracks continue to remain strong. In fact, they've gotten a lot stronger and we believe that they'll continue to perform throughout the year as we head into higher demand planning season and into winter in the U.S. where distillate over gasoline every pad now. And then finally on the jet, the jet's also strong. Low inventories, increasing domestic and international travels. Global seat demand is essentially flat to 2019 levels. TSA throughput numbers in the U.S. are back [ph] to 2019 levels. And interestingly, U.S. jet yields remain a little bit higher so that should add some marginal strength to diesel. And then on the WCS, you're right. WCS has started to widen again, which is in our best interest here at -- we buy the most WCS of, I think, anybody there is. And we've seen the widening mostly because of heavy crude dips, in general, have started to widen. We also see fall turnarounds in pad 2 as being very strong. And then if you'll remember in September, which next month, we'll start to see Dillon blending, which will swell the volume of Canadian crude. So, all those things have been putting pressure on and widening the dips to our advantage.

Ryan Todd:

Hi, thanks. We don't often talk that much about Marketing, but your Marketing business, as it continues to generally kind of exceed expectations on a regular basis, so I think first half contributions are fairly in line with last year's first half contributions, which was generally higher-than-expected year-end Marketing. Is that business maybe structurally -- just structurally stronger than we have appreciated and maybe you've guided to? Or what do you attribute kind of continued strength in the Marketing side?

Mark Lashier :

Yes. I would just comment over again and compliment Brian and his Marketing team on the execution of the strategy that they've held for several years is to go in and participate through these joint venture opportunities in markets that make sense for us, that we have a competitive advantage that there's strength to capitalize on. And we don't go and do this everywhere. It's very surgical. It's very intentional, and it is exceeding expectations so it's a well-executed strategy.

Rich Harbison :

Yes, Ryan. Permitting to complete any project in California is very challenging, projects even to convert a conventional crude oil facility refinery to a lower carbon intensity transportation fuel production facility. So, we did recently receive news on an appeal to our environmental impact report that is the supporting document for permits. This was filed by a couple of NGOs in the state. And the good news is the court ruling found several issues in the favor of Phillips 66. And notably, most notably is the construction of the Rodeo Renewed project can continue with the county work to resolve three issues. So, we're working closely with the county and the courts to provide the necessary information to reconsider the open issues. And we remain very confident that the Rodeo Renewed project is on track to start commercial operation in first quarter of 2024.

Rich Harbison :

Thank you.

Jason Gabelman:

Hey, thanks for taking my question. I wanted to follow up on Ryan's question just now on Marketing and the outlook for 3Q. There were reports of droughts in the Rhine River. And I think typically when that happens, you're positioned to supply that region well and take advantage of margin moves there. Have you seen any strength in 3Q, or early 3Q as a result of those outages? And would you expect, as a result, continued outperformance in Marketing in 3Q? And then conversely, what you're seeing on chems, we've seen chain margins fall into July. Just any views on the outlook there into 3Q and then beyond that when you expect Chemical margins to move back to mid-cycle?

Tim Roberts :

Yes. And with regard -- this is Tim Roberts on this. With regard to Chemicals, talk about currently where we're at with chain margins. Yes, it's been an interesting run here. Obviously, you've got supply, plenty of supply available, and demand, they're not matching up. So, therefore, you've seen chain margins have been dropping over the last several quarters. Where you're at right now, I think IHS added about $0.12 in chain margins. And really the way we would look at this and look at it going forward is, is that the high-cost producers, both in Asia and those that are in Europe are going to set the price. And those that are in advantaged feedstock locations will keep running and probably run hard, which is what we're seeing right now in North America and the Middle East. While those are having to shut in capacity or having to manage production or any other reasons I mentioned earlier. Now fundamentally, though, you've got to get demand and supply to match up and you got to start working off inventory. Ethylene inventories here in North America are above the five-year average. So, that's got a direction that needs to start working its way down. And you're seeing the same thing in polyethylene, so, two of the main products that we see with regard to our CPChem JV. However, we're running really strong here. Exports are strong as well with regard to North America because we're advantaged on feedstock. So, our outlook is that yes, you got to hit the bottom before you can start working your way back up. I can't say this is the inflection point, but cash costs typically will drive where you get to the bottom and then how soon you can accelerate. And usually, as we would say and it goes in a lot of different directions is low cost, low prices solve prices. So, fundamentally, we do think that the outlook is still going to be constructive and constructive in that you still got population growth. You still have economies that have not been churning at their all cylinders, China being one of them. And that's not a position of saying they never will, not at all. We think there is still going to be good solid economic growth. You're just not seeing it consistent global. So, we do anticipate that, that will happen and that will help soak up some of the capacity that's out there, bring the markets back into balance and you get back into more of a mid-cycle case.

Mark Lashier:

Yes. I think that again, as Kevin mentioned earlier, we looked across our portfolio, and there's different dimensions across our portfolio where others may have some interest in our assets and may place a greater value because it's not strategic to us and we'll continue to evaluate that. I wouldn't comment on any specific opportunities. And likewise, as we did with Marketing in California to -- we made some relatively small acquisitions to enhance the opportunities around Rodeo once it's up and running, and we've done a series of those and they're all doing quite well. And so, we'll look at smaller opportunistic things. But you think about where we've come from, we've done some pretty significant transactions in Midstream. It's time to digest those and to drive value through those. And if we can find some very accretive small, midsized kinds of things, we'd look at them, but there's nothing in the queue and nothing that we'd want to comment on. We've got a great backbone there and history has shown that the strong backbone in that industry can attract smaller investments that are quite attractive. So, think in terms of small, very accretive, high-return opportunities like we've done in Marketing would be on our scale. But we're going to stick with our disciplined approach going forward. We've got a commitment of around $2 billion for 2024, and anything around that would be very disciplined and high return.

Operator:

Thank you. Our next question comes from Manav Gupta of UBS. Your line is open please go ahead.

Rich Harbison :

Yes. No, this is Rich. Over in that, what we refer to it as the Atlantic Basin, we did have higher volumes and lower costs due to less turnaround activity at Bayway quarter-over-quarter when you look at those. But a lot of those were offset by lower margins. The realized margin was lower primarily due to a weaker market crack. Configuration impacts also played into this with the gasoline cracks increasing by $10 a barrel and then the distillate crack decreasing by $18 a barrel. That played into the market capture quite a bit. And there was lower product differentials there. And then the other one that goes a little bit unnoticed in this market is really the secondary product cost and margins on those secondary products. And both the NGLs for both Bayway and Humber were lower. And then the petroleum coke that sold out of Humber also experienced lower product differentials. So, those are the primary reasons you saw lower market capture there in Atlantic Basin.

Brian Mandell :

Hey Manav, this is Brian. Well, first, I think our view is that TMX will probably come on later in the year, although line fill is forecasted for early Q1. I think the line will not be filled completely. That's our view. I think those are on the lines, I feel like some of those barrels will be exported to Asia. We'll see if that happens. It's hard to get VLCCs there. In fact, you can't load VLCCs. You have to load them ship to ship outside of L.A. So, it's -- we'll see what happens going forward. But certainly, it could be a benefit to the West Coast having more of that crude.

Operator:

Thank you. Our next question comes from Matthew Blair of Tudor, Pickering, Holt. Your line is open please go ahead.

Kevin Mitchell :

Yes, Matt, this is Kevin. We did. We did unwind them or have we let them roll off but we have less of that. We don't have that same hedging on our exposure to the Nat gas NGL commodity price that we have -- that DCP has historically had in our overall portfolio. And when you also factor in our position in Refining as a consumer of those project products, it felt more appropriate just to let the natural offsets flow through. And so, we have done that. I don't think we've given a number. I know we haven't given any specific number out there. What we have done is updated the sensitivities for Midstream to reflect the fact that those hedges are no longer in place. And so, you see a slightly higher Midstream sensitivity to the commodity price than before.

Brian Mandell :

This is Brian. We exported over 200,000 barrels this quarter, which was up. In large part, our Sweeny refinery was making some higher sulfur diesel that we exported to Latin America. Like others have said, we have been exporting more distillate to Europe as trade flows from Russia change and Russia is importing more barrels, particularly into Brazil, 120,000 barrels to 140,000 barrels, and where U.S. exporting more barrels to Europe.

Operator:

Thank you. Our next question comes from Paul Cheng of Scotiabank. Your line is open please go ahead.

Mark Lashier:

Yes. It'll help cover that at a high level. Paul, I think Brian has some views on what's going on there as well. I think at one end of the spectrum, we're well connected to LAX from that facility. And jet is a big opportunity there, and we would certainly look at doing what we could to provide more jet. I think that one mitigant of that is as we take the San Francisco refinery offline, that diesel production will go away and leave the market. And it's almost a gallon-for-gallon replacement with renewable diesel so that is an opportunity there as well. And so, we -- I think that there are exports from California today and Brian can comment further on that, but that's an opportunity to balance things out.

Paul Cheng :

Okay. So, you think that. And do you think that on a longer-term basis, that should be part of your portfolio? Or given the political environment and everything, that, that may -- I mean, is there any plan to do something if there are what you have done to Rodeo?

Paul Cheng :

Okay. And the final one, I think this maybe is for either Rich or Kevin. When we look at your margin capture or that your margin realization in Central Corridor, you're actually doing better than we thought. Is there any one-off benefit that we see or it's just normal market condition and that recovery from the downtime in the first quarter? Thank you.

Kevin Mitchell :

And just to clarify, it's not a function of one-off items that are benefiting. It is all operational, as Rich described.

Joe Laetsch :

Great thanks on Beyond. So, I wanted to go back to a couple of topics we've already hit on. But first on Chemicals. So, with the two CPChem projects starting up in the back half of the year, could you just give us a sense of earnings contribution and uplift, probably 2024 on a normalized margin environment from those two projects, just how we should think about that?

Mark Lashier:

Yes. And CPChem executed the hexene project and brought it in under budget as well so I think that's notable in this environment.

Rich Harbison :

Yes, this is Rich. The project, as it's designed, will be able to produce SAF. What's really missing from the whole equation is the market indicator to do that. And as soon as that's in place, we will quickly shift to a renewable jet sustainable aviation fuel production. The facility will have the capability of producing 20,000 barrels a day of sustainable aviation fuel on the backbone of 10,000 barrels a day of renewable jet that's blended with traditional crude oil-based jet production.

Rich Harbison :

And there is the capability to invest and increase that production level.

Joe Laetsch :

Great thank you.

Mark Lashier:

Thank you, Alex, and thanks to all of you for your questions. We delivered strong second-quarter financial and operating results as we executed on our strategic priorities by focusing on the things we control, most importantly, the commitments we made to our owners in November. We continued a healthy pace of returning cash to shareholders. And in Refinery -- Refining, we had another quarter of strong operating performance with above-industry average crude utilization and lower operating costs. We're executing our Midstream NGL wellhead-to-market strategy and completed the buy-in of DCP's units and raised our synergy targets to over $400 million, wrapping up a series of foundational transactions to drive value creation in our NGL business. We're realizing our business transformation initiatives and are on track to achieve at least $1 billion of annual run rate savings by year-end while driving a transformative mindset across the enterprise. As we deliver on our strategic priorities, we remain committed to financial strength, disciplined capital allocation, and returning cash to shareholders. The outstanding operational performance will position us to capture the current strong market environment in the third quarter. And we look forward to updating you on our progress. Thank you all for your interest in Phillips 66.

Jeff Dietert:

Good morning, and welcome to Phillips 66 First Quarter Earnings Conference Call. Participants on today's call will include Mark Lashier, President, CEO; Kevin Mitchell, CFO; Brian Mandell, Marketing and Commercial; Tim Roberts, Midstream and Chemicals; and Rich Harbison, Refining. Today's presentation material 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.

Kevin Mitchell:

Thank you, Mark, and hello, everyone. Starting with an overview on Slide 5, we summarized our financial results for the first quarter. Adjusted earnings were $2 billion or $4.21 per share. The $12 million decrease in the fair value of our investment in NOVONIX reduced earnings per share by $0.02. We generated operating cash flow of $1.2 billion, including a working capital use of $1.3 billion and cash distributions from equity affiliates of $369 million. Capital spending for the quarter was $378 million, including $228 million for growth projects. We returned $1.3 billion to shareholders through $486 million of dividends and $800 million of share repurchases. We ended the quarter with 459 million shares outstanding. Moving to Slide 6. This slide highlights the change in adjusted results by segment from the fourth quarter to the first quarter. During the period, adjusted earnings increased $66 million, mostly due to higher results in Chemicals and lower corporate costs, partially offset by a decrease in Marketing and Specialties. Slide 7 shows our Midstream results. First quarter adjusted pre-tax income was $678 million compared with $674 million in the previous quarter. Transportation contributed adjusted pre-tax income of $270 million, up $33 million from the prior quarter. The increase was primarily driven by seasonally lower operating costs. NGL and Other adjusted pre-tax income was $420 million compared to $448 million in the fourth quarter. The decrease was mainly due to the impact of declining commodity prices in the gathering and processing business. The fractionators at the Sweeny Hub continued to run above nameplate capacity, averaging 554,000 barrels per day. The Freeport LPG Export facility loaded a record 282,000 barrels per day in the first quarter. Turning to Chemicals on slide eight. Chemicals had first quarter adjusted pre-tax income of $198 million compared with $52 million in the previous quarter. The increase was mainly due to improved margins from lower feedstock costs, higher sales volumes and decreased utility costs. The industry polyethylene margin increased by $0.10 to $0.17 per pound during the quarter. Global O&P utilization was 94% for the quarter. Turning to Refining on slide nine. Refining first quarter adjusted pre-tax income was $1.6 billion, down $18 million from the fourth quarter. The impact of lower volumes from turnaround activities was mostly offset by higher realized margins and lower utility costs. Our realized margins increased by 5% to $20.72 per barrel, while the composite 3:2:1 market crack decreased by 5%. In the first quarter, turnaround costs were $234 million, crude utilization was 90% and clean product yield was 83%. Slide 10 covers market capture. The market crack for the first quarter was $22.39 per barrel compared to $23.58 per barrel in the fourth quarter. Realized margin was $20.72 per barrel and resulted in an overall market capture of 93%, up from 84% in the previous quarter. Market capture is impacted by the configuration of our refineries. We have a higher distillate yield and a lower gasoline yield than the 3:2:1 market indicator. During the first quarter, the distillate crack decreased $19 per barrel and the gasoline crack increased $7 per barrel. Losses from secondary products of $2.56 per barrel were $1.03 per barrel lower than the previous quarter due to falling crude prices. Our feedstock advantage of $2.34 per barrel was $2.37 per barrel improved compared to the fourth quarter, primarily due to running more advantaged crudes. The Other category improved realized margins by $2.19 per barrel. This category includes freight costs, clean product realizations and inventory impacts. First quarter was $1.73 per barrel higher than the previous quarter, primarily due to improved clean product realizations. Moving to slide 11. Marketing and Specialties had a solid quarter, reflecting stronger-than-typical first quarter margins. Adjusted first quarter pre-tax income was $426 million compared with $539 million in the prior quarter, mainly due to lower international marketing margins. On slide 12, the Corporate and Other segment had adjusted pre-tax costs of $248 million; $32 million lower than the prior quarter. The improvement was mainly due to higher interest income and recognition of a transfer tax on a foreign entity reorganization in the fourth quarter of 2022. Slide 13 shows the change in cash during the first quarter. We started the quarter with a $6.1 billion cash balance. Cash from operations was $2.5 billion, excluding working capital. There was a working capital use of $1.3 billion, mainly reflecting an increase in inventory, partially offset by a decrease in our net accounts receivable position. During the quarter, we issued $1.25 billion of senior unsecured notes in support of the pending buy-in of DCP Midstream's publicly held common units. We funded $378 million of capital spending and returned $1.3 billion to shareholders through dividends and share repurchases. Our ending cash balance was $7 billion. This concludes my review of the financial and operating results. Next, I'll cover a few outlook items for the second quarter. In Chemicals, we expect the second quarter global O&P utilization rate to be in the mid-90s. In Refining, we expect the second quarter worldwide crude utilization rate to be in the mid-90s and turnaround expenses to be between $100 million and $120 million. We anticipate second quarter Corporate and Other costs coming between $260 million and $290 million, reflecting higher interest costs. In March, we issued senior unsecured notes of $1.25 billion and entered into a delayed draw term loan of up to $1.5 billion in support of the DCP Midstream buy-in transaction, which is expected to close during the second quarter. Now we will open the line for questions.

Neil Mehta:

Good morning team. The first question is around refining utilization. It was better than expected in the quarter, and the guide for Q2 also looks a little bit better. So you talked about what improvements that you're making on the ground and it's been a choppy 18 months in Refining from a utilization standpoint. So what conviction can you provide the market that we've turned the corner here? Thank you.

Mark Lashier:

Yes, Neil, this is Mark. I'll just come over with a little bit relating that back to the Investor Day commitments, that we made those commitments based on the groundwork that had been underway for some time, the fairly small projects that we were going through, the blocking and tackling that we were taking on, and we're really starting to see those come to fruition now. And we're pleased with what we're seeing out there. And really, I think the biggest impact of business transformation has been the hearts and minds of our employees. They are all in. Wasn't that way a year ago when first started the initiative, but now they see the things that they're doing, the hard work that they're doing are starting to impact their results and turnarounds, starting to impact the operational effectiveness of the plants as well as they're seeing it in the cost. And that's just been a very virtuous cycle for our employees. There's a stronger competitive edge out there and they really want to own their future now.

Rich Harbison:

Yes, I think that plays into the Refining capture rate of 93% for the quarter for us. Last year, we actually implemented 12 projects focused on market capture. The result of the impact of those projects is a 1.2% improvement in market capture with mid-cycle pricing assumptions. We implemented $225 million worth of projects, and the net return on those or the EBITDA generation for that investment was $158 million at mid-cycle pricing. 2023, we actually have additional 18 projects identified that are in flight, and the estimate is a 1.4% improvement in market capture. So, I think what you're seeing here is the plan we laid out in November is starting to really come to the bottom line of the performance of the Refining.

Brian Mandell:

Well, let me start, Neil. This is Brian. Talking about marketing and probably noticed we had very strong marketing earnings in Q1. Pretty happy about that. You know that we have a geographic diverse portfolio with assets both here in the US and Western Europe, which is great. But we also market through a number of channels, wholesale, branded, and retail. And what we've been doing is trying to focus our sales on the higher margin parts of our business, particularly in retail. And we purchased retail in the past few years. In fact, in mid-2019, we had 50 retail JV stores in the US. Now, we have 1,000 retail JV stores in the US, and we also spent some time reimaging all of our stores to get higher margins in business. And I would also say that in the lubes business, that it's also performing quite strongly in both base oils and finished products. So, as you mentioned, as spot prices come off, that generally benefits the marketing business because marketing margins, generally, or marketing prices generally fall slower.

Kevin Mitchell:

Yeah. Neil, just on the working capital impact. As you've highlighted, with the declining prices, we will have a working capital hurt because we're in a net payables position. So you think about a system that's essentially 2 million barrels per day and a longer duration on the payables outstanding than on the receivables. So the approximate rule of thumb is somewhere in the order of $40 million to $50 million of working capital hurt per $1 of price reduction. And that assumes that the crude and the products move together, and the crack stays at the same level. But as you know, also, there's a lot of other moving parts in working capital, what's happening to inventories and so on. But as a rule of thumb, simple rule of thumb, you can use that $40 million to $50 million per $1 movement in price.

Mark Lashier:

Thanks, Neil.

Doug Leggate:

Thanks everyone for getting me on. Guys, I want to ask a follow-up to Neil's question on the capture rate. So should -- I mean, obviously, reliability was a bit of a question mark over the past year? So should we now think about this level of capture rate, should we anticipate that, that's kind of a new normal? And if I could risk it, just a bolt-on to that, the same kind of seems to be true of the cost-cutting progress. It looks like you're a little bit ahead of schedule there. So as we wrap it all together, the earnings power of the business overall, it looks like you're kind of past the hump and trending higher. So I just wonder, if you could kind of characterize whether we're thinking about that the right way.

Rich Harbison:

Yeah. So capture rate has a lot of moving parts to it so it's very difficult to predict that, the configuration component of it, secondary products, feedstock costs, others. But back to focusing on what we can control in our business, Doug, is we're seeing continued maturity in our reliability programs, and these saves are coming on a regular basis where we're catching issues early and preventing larger events from occurring. And also under asset availability, as I mentioned earlier, the turnaround execution is going very well for us. We've significantly improved our predictability on this. That takes a lot of leg work over time to improve those processes. And most importantly, even though we're hitting our turnaround execution goals, we are continuing to complete all the necessary work to operate the equipment safely and reliably over time. So that program is continuing to mature. We'll continue to see that. And that will allow our utilization rates to be available to operate in the market if the market is there. And then as you mentioned, the cost side of it is a big component of this as well. We have a clear path that we've identified reducing our costs by $500 million by the end of this year on a run rate basis. Over half of the $400 million run rate cost savings that Kevin mentioned in his comments are coming out of Refining. And that's good news for us. And probably more importantly, as Mark has indicated, our entire organization is uncovering opportunities to lower cost. We're being much more efficient in how we work and accepting the challenge to improve the business, which all should directionally support improved market capture and utilization.

Doug Leggate:

A lot of progress in a short period of time, Mark. I guess my follow-up is fairly predictable, and I apologize for this demand. Your large -- one of your large competitors talked about big increases in deal demand year-over-year. And a healthy outlook for gasoline and market doesn’t seem to believe that right now. I just wonder, through your marketing channels, if you could share, what you’re seeing on both of those trends.

Doug Leggate:

Interesting color. Will watch with interest, guys. Thanks so much for your answers.

Operator:

Ryan Todd from Piper Sandler. Please, go ahead. Your line is open.

Mark Lashier:

I'll touch a couple of those things, Ryan, at a high level, and then Kevin can drill into how the savings are distributed. But really Refining has performed very well. With respect to business transformation, we're seeing that. On the sustaining capital, I just want to make it clear that, that's really not an outright reduction in sustaining capital opportunities. It's becoming more efficient and more productive in how we're spending that, and we're going to continue to do that. You'll see really that impact in any of our capital projects that we look at going forward and we're not really capturing that. So, it's going to be a continuous process to look at how to get more and more efficient around sustaining capital. And we're not going to end this adventure when we get to the end of the defined program at the end of next year. We have outlined goals. We expect to continue to generate more savings on into 2024 and beyond. There are some things that we aren't even talking about today that require modest capital that will further enhance cost savings. So, we're instilling this as part of our culture, Ryan, and this is just going to be an ongoing march of continuous improvement, greater competitive edge. We've got 14,000 employees that want to win out there every day and they're highly motivated. Now, Kevin can give you a little insight to where you're going to see these numbers.

Ryan Todd:

Great. Thanks. And then maybe, I mean, you mentioned the importance of crude differentials to Refining profitability. Can you talk a little bit -- I mean, we've seen some pretty big moves on crude differentials widening and then coming in some Canadian heavy differentials narrowing. Can you talk about what you're seeing out there, what your outlook is for some of these crude differentials over the remainder of this year?

Ryan Todd:

Okay, thank you.

Operator:

Manav Gupta with UBS. You may proceed. Your line is now open.

Tim Roberts:

Yes, Manav. This is Tim Roberts on the chemicals front which has got really our -- yes, we did benefit but then if it was really related to lower advantage feedstocks, ethane, propane, butane namely here in the United States, so you saw that advantage as those prices dropped. They became advanced in the crack and subsequently that showed up in the margin. The other side of that as well as lower natural gas prices, which of course is driving that whole structure. Also help with regard to utility cost. So yes, lower utility costs, the better feedstock advantage so it really helped in the quarter. You still got a supply issue and you have a demand issue and supply side fundamentally you've got more capacity that's coming on board and here in the United States. So you're going to have to work through that new capacity. The demand side is coming around. But you're still trying to work off a lot of inventory that happened as you had the supply chain disruptions out there in the marketplace. So you got to work through that inventory. And you also need to see China coming back stronger. As Brian mentioned, there are some strength there in travel, driving so some good things there needs to also show up in consumption on that side as well as production to meet global demand for products made out of polymers. So fundamentally, I think it's still going to take us a little bit of time to work through those two imbalances. We're not expecting anything to happen by the end of the year, there's going to be a significant bump. But I would throw one caveat is China is a significant impact in the market. If they're clicking on all cylinders, you can see things change rapidly. But at this point in time, we've got an inventory to work off, and we need to see some additional demand come back, especially from Asia.

Brian Mandell:

Yes. And I do think, Mark, exactly on that point though is that also their product slate is geared towards consumables. Durables are a little bit -- you're seeing it slow up a little bit on the durables front, and they don't have as much exposure to that.

Mark Lashier:

Yes. Manav, we're making good progress on the project out at Rodeo. You heard me mention we shut down the Santa Maria facility, which is basically a feed prep unit for the Rodeo facility. The project is moving along. And there are lots of weather challenges out there, but the team has fought through it and dealt with it, and we're looking forward to having that on in the first quarter of next year. And I'll remind you that we've had a unit there operating and producing renewable diesel, what we call Unit 250 since April 2021. And I'll tell you what, it's exceeded both our operating expectations and our commercial expectations. And frankly, we're ready for more. We've got a great strategy out there and we are implementing and executing. And I'll let Brian touch on more of those details.

Manav Gupta:

Those are all very encouraging updates. Thank you, guys.

Operator:

John Royall with JPMorgan. Please proceed. Your line is open.

Kevin Mitchell:

John, this is Kevin. I would just say, I mean, your points are valid. We'll see -- we'll benefit from lower maintenance turnaround costs. And the natural gas prices are settling in at a pretty low level, and so you would expect to see a drop 1Q to 2Q. We're not giving specific guidance on the number. Now the other side of that is utilization will be higher, so some of the variable costs, you'll see a small impact from. But that's a good thing. But net-net, I think you should see a small -- a modest sequential decline.

Kevin Mitchell:

Yes. John, I wouldn't be too concerned about buyback pace being driven by the funding the buyback because we are at a $7 billion cash balance at the end of the first quarter. We had drawn -- we had issued $1.25 billion of notes but we have the term loan facility, which has not been drawn yet. And so we will draw on that as we fund the buy-in. So even all other things unchanged, we'll still have a healthy cash balance at that point in time. We're still generating cash. And so I think that our buyback pace should still be at a very respectable level in the second quarter. The balance sheet is in a good position. The operating cash flow is still strong. We've seen some weakening in Refining margins. But relative to our mid-cycle assumptions, the business is still looking really good. So I'm not too concerned about the buyback pace being impacted by the DCP buy-in.

Operator:

Matthew Blair with TPH. Please proceed. Your line is open.

Rich Harbison:

Yes, this is Rich. So Central Corridor, I think the first thing to remember, the quarter-over-quarter analysis, fourth quarter, we had some pretty heavy headwinds with the Keystone shutdown and the winter storm effects, so that kind of sets the baseline. In the first quarter, we did see improved feedstock advantage running the heavy crudes. And more importantly, we are able to actually increase our crude slate percentage of these crudes that we were able to run. That impacted our market capture there as well. Now some of that was offset by the unplanned downtime impacts that carried on -- initiated fourth quarter, carried on into the first quarter. That unplanned downtime, primarily at Wood River was -- is now repaired and that facility is back up and running. We did slide one turnaround from the first quarter to the first half of the second quarter. That turnaround is now ramping up this week here. So we do expect the utilization rates to get back to higher levels for the WRB assets. There -- also, there was other some slight turnaround impacts as well to that first quarter results and a little bit lower market cracks also that played into that result. But that's how we see the Central Corridor kind of moving forward. We expect our utilization rates to turn back upwards.

Rich Harbison:

Well, we -- this is Rich again. We anticipated this flood of activity that would occur for -- to get these LCFS pathways approved. And we've been working diligently to get these approved even ahead of the start-up of the project. Any pathway that was approved for the Unit 250 operation is also applicable to the Rodeo Renewed project as well. So while we are concerned, I would say that there is a flood of applications to pathways. We think we're in a good position, and that should meter into our system, consistent with the start-up of the project.

Operator:

Paul Cheng with Scotiabank. Please proceed. Your line is open.

Mark Lashier:

Yeah. Paul, that's been taking up a lot of intellectual capacity for, I think, the entire industry since that was rushed through. Before that, California was a tough place to manage Refining business, and I think this just makes it even a little more difficult. We're like everyone else, working hard to understand both the intended and unintended consequences of SBX1-2. And it certainly, at a fundamental level, creates more uncertainty, and it's going to make it more difficult for people to step up and invest in the supply chain that the consumers need, because even though you've got a lot of things coming over the hill to reduce demand, today, demand is strong, and you can see what happens when there's disruptions and the supply chain can be pretty tight there. So it's really tough for us to see how this new law is going to benefit the consumers at the end of the day.

Mark Lashier:

Yeah. I think that it's logical to assume that industry associations will defend and protect the interests of the industries, and even individual companies may take action. That's certainly going to be up to each company. But from an industry perspective, I think that, that's an angle that's obviously being looked at.

Kevin Mitchell:

Yes. Paul, the big driver of the change this quarter, especially comparing to last quarter is around the product, clean product realizations or clean product differentials. And that was a particular negative item in the fourth quarter because the way we do our market crack for Atlantic Basin, we use a New York Harbor-based crack and the distillate crack or the jet crack was particularly strong in New York Harbor. It was weaker in Europe. And our capacity is approximately 50-50 between New York, Northeast and Europe. And so our Europe distillate production is causing a negative relative to that market. And so that pulled down the overall capture, and that shows up in other -- we had a little bit of a similar phenomenon going on in the West Coast as well, where we used an LA marker for the entire West Coast, which includes Northern California and the Pacific Northwest. And so when those markets are out of sync with each other, that can drive differentials in our actual product realizations, and that will show up in that other. That's the biggest single driver in there, Paul.

Kevin Mitchell:

Yes.

Jason Gabelman:

Hey, thanks for taking my questions. The first I wanted to ask was on kind of global Refining margin structure. There are stories out there that Asian plants are cutting runs while US cracks are still really healthy, $20 a barrel. So the question is, is that kind of a leading indicator that some of that weakness will ultimately make its way over into the US via lower margins, or is it an indication that the global margin environment could be at a floor because we're cutting around somewhere? Thanks.

Jason Gabelman:

Okay, great. And my follow-up is on DCP, and I understand the deal isn't closed yet but just maybe wanted to get some early indications on progress. And specifically, I think part of the rationale for the deal was the combined Midstream platform of Phillips and DCP would attract more acreage to fill midstream assets within that platform and support growth there. And so the question is, are there any early indications that upstream companies do view this combined platform as more favorable to partner with, to support future growth for Philips? Thanks.

Jason Gabelman:

Great. That's really helpful. Thanks for the color.

Operator:

That concludes the question-and-answer session. I will now turn the call back over to Mark Lashier for closing remarks.

Jeff Dietert :

Good morning, and welcome to Phillips 66 Fourth Quarter Earnings Conference Call. Participants on today's call will include Mark Lashier, President and CEO; Kevin Mitchell, CFO; and Brian Mandell, Marketing and Commercial; Tim Roberts, Midstream and Chemicals; and Rich Harbison, Refining. Today's presentation material 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.

Kevin Mitchell :

Thank you, Mark. Starting with an overview on Slide 5, we summarize our financial results for the year. Adjusted earnings were $8.9 billion or $18.79 per share. The $442 million decrease in the fair value of our investment in NOVONIX reduced earnings per share by $0.71. We generated $10.8 billion of operating cash flow. Cash distributions from equity affiliates were $1.7 billion, including $574 million from CPChem. We ended 2022 with a net debt-to-capital ratio of 24%. Our adjusted after-tax return on capital employed for the year was 22%. Slide 6 shows the change in cash during the year. We started the year with $3.1 billion in cash and generated record cash flow during the year. Cash from operations was $10.8 billion. We received net loan repayments from equity affiliates of $590 million. During the year, we paid down $2.4 billion of debt. This includes $430 million of debt paid down by DCP Midstream since we began consolidating effective August '18. We funded $2.2 billion of capital spending and returned $3.3 billion to shareholders, including $1.5 billion of share repurchases. The other category includes the redemption of DCP Midstream's Series A preferred units of $500 million. Our ending cash balance increased by $3 billion to $6.1 billion. Slide 7 summarizes our fourth quarter results. Adjusted earnings were $1.9 billion, or $4 per share. The $11 million decrease in the fair value of our investment in NOVONIX reduced earnings per share by $0.02. We generated operating cash flow of $4.8 billion, including a working capital benefit of $2.1 billion and cash distributions from equity affiliates of $261 million. Capital spending for the quarter was $713 million, including $310 million for growth projects. We returned $1.2 billion to shareholders through $456 million of dividends and $753 million of share repurchases. We ended the quarter with 466 million shares outstanding. Moving to Slide 8. This slide highlights the change in adjusted results by segment from the third quarter to the fourth quarter. During the period, adjusted earnings decreased $1.2 billion mostly due to lower results in Refining and Marketing and Specialties. In the fourth quarter, we made certain changes to the composition and reporting of our operating segment results. Our slides reflect these changes and prior period results have been recast for comparative purposes. The 2022 and 2021 quarterly information has been recast and is included in our supplemental information. Slide 9 shows our Midstream results. Fourth quarter adjusted pretax income was $674 million compared with $608 million in the previous quarter. Transportation contributed to adjusted pretax income of $237 million, up $8 million from the prior quarter. NGL and Other adjusted pretax income was $448 million compared to $412 million in the third quarter. The increase was primarily due to record fractionation volumes as well as a full quarter of consolidating DCP Midstream, Sand Hills Pipeline and Southern Hills pipeline. The fractionators at the Sweeny Hub averaged a record 565,000 barrels per day, reflecting the start-up of Frac 4 at the end of the third quarter. The Freeport LPG export facility loaded a record 271,000 barrels per day in the fourth quarter. Our NOVONIX investment is mark-to-market each quarter. The fair value of the investment, including foreign exchange impacts, decreased $11 million in the fourth quarter compared with a decrease of $33 million in the third quarter. Turning to Chemicals on Slide 10. Chemicals at fourth quarter adjusted pretax income of $52 million compared with $135 million in the previous quarter. The decrease was mainly due to lower margins and volumes partially offset by decreased utility costs and the impact of legal accruals in the third quarter. Global olefins and polyolefins utilization was 83% for the quarter, reflecting planned turnaround activities and the impact of the winter storm in December. Turning to Refining on Slide 11. Refining fourth quarter adjusted pretax income was $1.6 billion, down from $2.9 billion in the third quarter. The decrease was primarily due to lower realized margins. Our realized margins decreased by 27% to $19.73per barrel, while the composite 3 to 1 re-adjusted market crack decreased by 16%. Turnaround costs were $236 million. Crude utilization was 91% in the fourth quarter and clean product yield was 86%. Slide 12 covers market capture. We are now using a composite 3 to 1 in adjusted market crack to be more consistent with peers and more comparable to our realized margin. The 3 to 1 rent-adjusted market crack for the fourth quarter was $23.50 per barrel compared to $28.18 per barrel in the third quarter. Realized margin was $19.73 per barrel and resulted in an overall market capture of 84%. Market capture in the previous quarter was 95%. Market capture is impacted by the configuration of our refineries. We have a higher distillate yield and lower gasoline yield than the 3 to 1 market indicator. During the fourth quarter, the distillate crack increased $8 per barrel, and the gasoline crack decreased $10 per barrel. Losses from secondary products of $3.59 per barrel were $0.09 per barrel higher than the previous quarter. Our feedstock loss of $0.03 per barrel was $1.45 per barrel improved compared to the third quarter due to more favorable crude differentials. The other category improved realized margins by $0.46 per barrel. This category includes freight costs, clean product realizations and inventory impacts. Fourth quarter was $6.66 per barrel less than the previous quarter, primarily due to lower clean product realizations and inventory timing. Moving to Marketing and Specialties on Slide 13. Adjusted fourth quarter pretax income was $539 million compared with $828 million in the prior quarter, mainly due to lower domestic and international marketing margins. On Slide 14, the Corporate and Other segment had adjusted pretax costs of $280 million, $34 million higher than the prior quarter. The increase was mainly due to higher net interest expense as well as a transfer tax related to a foreign entity reorganization and higher employee-related expenses. Slide 15 shows the change in cash during the fourth quarter. We had another strong quarter of cash generation. We started the quarter with a $3.7 billion cash balance. Cash from operations was $2.7 billion, excluding working capital. There was a working capital benefit of $2.1 billion, mainly reflecting a reduction in inventory and a decrease in our net accounts receivable position. We received a loan repayment from an equity affiliate of $426 million. During the quarter, we repaid $500 million of senior notes due April 2023 and funded $713 million of capital spending. We returned $1.2 billion to shareholders through dividends and share repurchases. Additionally, the other category includes the redemption of DCP Midstream's Series A preferred units of $500 million. Our ending cash balance was $6.1 billion. This concludes my review of the financial and operating results. Next, I'll cover a few outlook items for the first quarter and the full year. In Chemicals, we expect the first quarter global O&P utilization rate to be in the mid-90s. In Refining, we expect the first quarter worldwide crude utilization rate to be in the mid-80s and turnaround expenses to be between $240 million and $270 million. We anticipate first quarter corporate and other costs to come in between $230 million and $260 million. For 2023, Refining turnaround expenses are expected to be between $550 million and $600 million. We expect Corporate and Other costs to be in the range of $1 billion to $1.1 billion for the year. We anticipate full year D&A of about $2 billion. And finally, we expect the effective income tax rate to be between 20% and 25%. Now we will open the line for questions.

Neil Mehta :

Yeah. Good morning, good afternoon, guys. I guess the first question I have is around refining. And if I try to isolate what the market is reacting to today, I think it's the capture rate, surprised folks relative to a lot of your large-cap peers. And so maybe you can simplify it for us and talk about what you're seeing in the system. Is there anything that you feel was more temporary versus structural? And give us confidence that that capture rate is going to continue to improve as we think about the progression through the year?

Jeff Dietert :

I might just add, the turnaround activity occurred in October and early November, which was the highest margin part of the quarter.

Mark Lashier :

Well, I'll start with the turnaround guidance part of that and then kick it over to Brian, you can talk about the market outlook a little bit there for the first quarter. So our first quarter turnaround, you can tell by our guidance there that Kevin provided our annual guidance is in the 550 to 600 range. And our first quarter is a majority of that spend. So we are heavy centric first quarter on our turnaround. And those are primarily related in just a couple of sites. So I don't -- I see that as really impactful to our Atlantic coastal operations there as the biggest part of that impact on the turnarounds. There is also some Gulf Coast turnaround activity as well that is less impactful. So although there is a heavy spend, it's centric really in one primary facility.

Neil Mehta :

Thanks, guys. Appreciate it.

Operator:

Our next question today comes from Doug Leggate with Bank of America. Please go ahead, Doug.

Kevin Mitchell :

Yeah. Doug, that's -- we've historically not done that in terms of what we've put out there into the market. We've talked about the kind of areas where that has shown up and Rich walk you through that. But it is a -- in any given period, there's invariably some element of LP component. And certainly, what we saw in the fourth quarter was quite a bit higher than what I would consider. I mean, ideally, you don't want any of it, but there's usually some degree of that. It was significantly higher than that. So not something we've historically given out. But I guess, to give you some some help, it's probably -- the number is probably in the order of $100 million to $200 million of LPO in the quarter.

Brian Mandell :

Yeah, I think we -- it's always an import market for gasoline typically up to 800,000 barrels a day. We do expect that to continue being an import market. The imports may come from different locations in the future, but we would expect that we still need to import gasoline about that level.

Brian Mandell :

I would say any market that is short needs resupply and the resupply comes from some distance away, has that opportunity for volatility. The same thing that happens on the West Coast, West Coast that we supplied is further away four weeks away. And then in -- and just in the Pad 1, but any time resupply is in close, you have that opportunity volatility.

Doug Leggate :

That's kind of what we're thinking. Thanks so much guys. That was a tricky one to answer. Appreciate your perspective.

Operator:

Our next question today comes from Roger Read with Wells Fargo. Please go ahead, Roger.

Kevin Mitchell :

So Roger, when you say index you're referring to the market crack, the adjusted market crack change?

Kevin Mitchell :

Yeah. Really, it's -- we're setting up for -- we've talked about this for a while, and we're setting up for 2023 and the cleanest way to make that change is to do it in the fourth quarter, and that enables us to restate or recast in our supplemental information, the prior 2021 and 2022 all on that same basis. And then the first results we report for 2023 will be on that same basis. And so it's just the cleanest timing to make a change like that. It's something we've considered for a little while, but we thought it was the appropriate thing to do.

Brian Mandell :

I'd say we continue to think that high sulfur fuel oil will remain weak, just with all the Russian cargoes coming on the market, both high-sulfur fuel oil and heavy crude cargoes coming out in the market. So I think we'll continue to see that in the market.

John Royall :

Good morning. Thank you for taking my question. So just hoping for a little more color on the DCP synergies that you called out in your press release, I think $300 million. I think you've probably been pretty anxious to speak about those numbers. And so any buckets you can speak to and anything on timing and how that should trade in?

Tim Roberts :

Yeah. At this point, Mark is correct. Look, we're looking at this. It's going to probably over a time frame, we came out with $300 million. We think it's probably about third with regard to costs. You got two third on the commercial side. We're anticipating this is going to take us around two years to fully capture this. It's like anything else, once you get into it further and deeper, we're hoping there's more there and initial indications are that they're likely are. And hopefully, I can update you another call later to validate or confirm that, but we do see the commercial side is probably driving that. It just makes sense. When you look at the integrated value chain, you put these two entities together, we, in effect, now have gas processing in the key regions. We now have fractionation capacity at Conway, Mont Belvieu, also at Sweeny and long-haul pipelines coming in out of the DJ and coming out of the Permian. When you look at those, there are tremendous opportunities to make sure the barrel gets the right place. And in our world, the right place means where it creates the most value. So, as we dig further on that, like I said, we're looking forward to giving you more details going forward.

Mark Lashier :

Yeah. I think, John, that you've seen at the ethane -- that the polyethylene value chain margins kind of hit bottom. Those producers that were really squeezed pulled back on production. So you can see that clearly -- we've hit a point where there's great discipline and nobody is going to operate while they're bleeding cash, and we've kind of passed through that period. Margins have modestly ticked up, and you'll continue to see as the capacity that's coming online in North America gets digested, we'll be at that bottom for some time, but then start to work our way out because demand globally continues to increase. And China is certainly an upside and there are number of signs that China is coming back. We're not going to call at their back. I think it could come in fits and starts, but certainly, the noise coming out of China is productive directionally.

Ryan Todd :

Great. Thanks. Maybe starting out with one on shareholder returns. The buyback was strong this quarter. As we think about 2023 going forward, you've provided guidance at the recent Analyst Day that would suggest something on the order of $500 million to $700 million a quarter of buyback in a mid-cycle environment. We're clearly above the mid-cycle environment. You were at the high end of the guided pace this quarter. How should we think about the use of that excess cash? Should the backdrop remain very constructive? And how aggressive might you look to be on shareholder returns versus building more cash on the balance sheet?

Ryan Todd :

Excellent. And then maybe shifting gears somewhere else. I wonder if you could discuss a little bit about what you're seeing and what you expect going forward in European refining. There's some big moving pieces in recent months, the natural gas spread between Europe and the U.S. has declined significantly and you've got an upcoming Russian product ban going into effect. What are you seeing in the market right now? And any thoughts on expectations in the coming months?

Rich Harbison :

So, natural gas for us, certainly has some impact on our operations, primarily for the purchase of electricity, but we see that really not as a disadvantage to our peers either. So, the competitive nature of refining will continue to be there with some cost impacts associated with higher natural gas and that's the numbers we put out in the past are still in play today as well. The challenge for that will be the continued impact of the Russian supply scenarios and then the resupply are that will set the really the minimum price for those marketplaces, and we'll see that shapes up here as the market moves forward.

Operator:

The next question comes from Paul Cheng with Scotiabank. Paul, please go ahead. Your line is open.

Mark Lashier :

If you look -- again, if you look at those projects and if you look at the assumptions on project financing, I think we had talked about earlier, maybe even at Investor Day, that our exposure to foregone dividends is really probably about 10% of the aggregate capital spend if you look at those two projects combined. And that's spread out over four years. So it's not a major impact on our ability to generate cash overall. Kevin, do you want to --

Paul Cheng :

Kevin, do you have any rough estimate whether you expect CPC to sensory pay out to earn 100% or 50% or 75% or any estimate that you have?

Operator:

Our next question comes from Jason Gabelman with Cowen. Please go ahead, Jason. Your line is open.

Tim Roberts :

Yeah. Jason, this is Tim Roberts. I'll handle that front end hand it off to Brian. I think it's important, you're right. We did talk about simplifying our overall structure. And you have PSXP done in the process of completing DCP. We do think we'll be in a much cleaner position with regard to ownership levels and just had a cleaner side work from. We do recognize as well that this market is evolving. There is some consolidation going on in the industry, producers are consolidating. You'll see some of the midstream infrastructure guys doing that too. So we're going to pay attention to that. And what's happening out there, if there is opportunities, but I think it's probably going to be real clear as we've got a task at hand. Our task at hand right now is to get DCP integrated and integrated well. We want to be successful at it. It's going to take us, we believe somewhere towards the end of the year. It may leak into 2024, but our expectation is get it done by the end of this year and deliver synergies. You drove most along those and that's pretty impactful with regard to value of the company. So we ant to do that, but do rest assured, not that we're out on any spending spree, we always have an eye open, what's going on out there and what can create value for our shareholders. And if there's something that's truly compelling, we'll talk about it and see if it makes sense. But right now, it's being integrated successfully.

Operator:

The next question comes from Matthew Blair of Tudor, Pickering, Holt. Please go ahead.

Brian Mandell :

Well, we'll start with WCS differentials. There were a number of things that we're kind of pushing and pulling on supply and demand. Inventories north of the board in Canada have been very high, and you had Keystone off the market for 22 days, which was 10 million barrels off the market. North of the border, you had about 4 million barrels of production off the market in December, another 0.5 million barrels off the market in January. And then you had the winter storm where refiners shut down. There was 27 million barrels of crude backed out, not all that's heavy crude, but refiners weren't pulling as much of the WCS. So all of that -- if you kind of add all that up, it meant that WCS dips were weaker than they have been. TMX provided an update in early January that they said that their 75% of the pipe is now in the ground. They haven't changed their in-service date for the fourth quarter of this year. Our internal expectations are that start-up will slip into 2024 and full rates won't be achieved immediately. We don't think you need another pipeline to exit the product that is in Canada. So we don't see it doing much. The first call for those barrels will always be Pad 2 and Pad 3 before they go to China or anywhere overseas, so they'll have to price to get into those markets.

Operator:

Next, we have a follow-up question from Paul Cheng from Scotiabank. Please go ahead.

Mark Lashier:

So we generally don't, for commercial reasons, talk about what we run into refineries and how much we run. But of course, Wood River had some hiccups. In Q4, we ran less WCS in our system than normally. We are the largest importer of Canadian crude to the U.S. We expect, as Wood River comes back up, we'll run more, Rich, maybe you can talk about where we are in Wood River.

Paul Cheng :

Okay. Can you tell us that what's the current runway of Wood River?

Brian Mandell :

Not that specific.

Operator:

We have now reached the end of today's call. I will now turn the call back over to Jeff.

Operator:

Thank you, ladies and gentlemen. This concludes today's conference. You may now disconnect.

Jeff Dietert :

Good morning, and welcome to Phillips 66 third quarter earnings conference call. Participants on today's call include Mark Lashier, President and CEO; Kevin Mitchell, EVP and CFO; Brian Mandell, EVP, Marketing and Commercial; Tim Roberts, EVP, Midstream and Chemicals; and Rich Harbison, SVP, Refining. Today's presentation material can be found on the Investor Relations section of the Phillips 66 website, along with supplemental financial and operating information. We provided supplemental information this morning for Chemicals, Refining and Marketing and Midstream. The remaining supplemental information will be available with the 10-Q filing. We'll return to the normal supplemental release next quarter. 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. Before we begin our discussion, I would like to highlight that we will be hosting an Investor Day in New York on November 9. With that, I'll turn the call over to Mark.

Kevin Mitchell :

Thank you, Mark, and hello, everyone. Before I talk about the financials, let me begin by summarizing the accounting impacts of DCP Midstream. On August 17, we completed the merger of DCP Midstream, LLC and Gray Oak Pipeline, LLC. In connection with the transaction, we were delegated governance rights over DCP Midstream, LP and its general partner entities as well as DCP Sand Hills Pipeline, LLC and DCP Southern Hills Pipeline, LLC. Effective August 18, our financial results reflect the consolidation of these entities. So starting with an overview on Slide 4, we summarize these financial results. We reported third quarter earnings of $5.4 billion. We had special items amounting to an after-tax gain of $2.3 billion, including the net gain related to the consolidation of DCP Midstream, Sand Hills Pipeline and Southern Hills Pipeline and the transfer of interest in Gray Oak Pipeline. Excluding special items, adjusted earnings were $3.1 billion or $6.46 per share. The $33 million decrease in the fair value of our investment in NOVONIX reduced earnings per share by $0.05. We generated $3.1 billion of operating cash flow. Capital spending for the quarter was $735 million, including the company's $306 million investment in DCP Midstream, LLC associated with the merger, net of cash acquired. We returned $1.2 billion to shareholders through $466 million of dividends and $694 million of share repurchases. We ended the quarter with 473 million shares outstanding. Moving to Slide 5. This slide highlights the change in adjusted results by segment from the second quarter to the third quarter, including the impact of consolidating DCP Midstream, Sand Hills Pipeline and Southern Hills Pipeline effective August 18. The Midstream segment, Corporate and Other, income taxes and noncontrolling interests are impacted by the consolidations. The higher noncontrolling interest reflects the portion of these entities not owned by Phillips 66. During the period, adjusted earnings decreased $163 million, mostly due to lower results in Refining and Chemicals, partially offset by higher Midstream and Marketing and Specialties results. Slide 6 shows our Midstream results. Third quarter adjusted pretax income was $645 million compared with $292 million in the previous quarter. The consolidation of DCP Midstream results are now reported within NGL and Other. Transportation contributed adjusted pretax income of $229 million, down $21 million from the prior quarter. The decrease was mainly due to lower equity earnings from the Gray Oak Pipeline resulting from the merger. NGL and Other adjusted pretax income was $449 million compared with $282 million in the second quarter. The increase was primarily due to the consolidation of DCP Midstream, Sand Hills Pipeline and Southern Hills Pipeline effective August 18. The fractionators at the Sweeny Hub averaged 429,000 barrels per day, and the Freeport LPG export facility loaded 249,000 barrels per day in the third quarter. Our NOVONIX investment is marked-to-market at the end of each reporting period. The fair value of the investment, including foreign exchange impacts, decreased $33 million in the third quarter compared with a decrease of $240 million in the second quarter. Turning to Chemicals on Slide 7. Chemicals had third quarter adjusted pretax income of $135 million compared with $273 million in the previous quarter. Olefins and Polyolefins adjusted pretax income was $105 million. The $111 million decrease from the previous quarter was primarily due to lower margins resulting from a sharp decline in polyethylene prices. This was partially offset by lower turnaround costs. Global O&P utilization was 90% for the quarter. Adjusted pretax income for SA&S was $60 million, in line with the second quarter. The higher costs in Other mainly reflect legal contingencies. During the third quarter, we received $41 million in cash distributions from CPChem. Turning to Refining on Slide 8. Refining third quarter adjusted pretax income was $2.8 billion, down from $3.1 billion in the second quarter. The decrease was primarily due to lower realized margins, partially offset by higher volumes. Our realized margins decreased by 6% to $26.58 per barrel, while the composite global 3:2:1 market crack decreased by 22%. Pretax turnaround costs were $225 million, in line with the previous quarter. Crude utilization was 91% in the third quarter and clean product yield was 85%. Slide 9 covers market capture. Our composite global 3:2:1 market crack for the third quarter was $36.29 per barrel compared to $46.72 per barrel in the second quarter. Realized margin was $26.58 per barrel and resulted in an overall market capture of 73%. Market capture in the previous quarter was 61%. Market capture is impacted by the configuration of our refineries. We have a higher distillate yield and lower gasoline yield than the 3:2:1 market indicator. During the third quarter, the distillate crack decreased $8.14 per barrel, and the gasoline crack decreased $11.84 per barrel. Losses from secondary products of $3.50 per barrel or $0.47 per barrel higher than the previous quarter. Our feedstock loss of $1.48 per barrel was in line with the previous quarter. Feedstock advantage from widening heavy sour crude differentials was offset by the impact of higher feedstock costs relative to dated Brent in the Atlantic Basin. The other category reduced realized margins by $1.29 per barrel. This category includes RINs, freight costs, in-product realizations and inventory impacts. Moving to Marketing and Specialties on Slide 10. Adjusted third quarter pretax income was $847 million compared with $765 million in the prior quarter. Marketing and Other adjusted pretax income was $717 million, up $61 million from the second quarter. The improvement reflects higher international margins, partially offset by lower domestic results, including inventory impacts. Specialties generated third quarter adjusted pretax income of $130 million. The $21 million increase was largely due to improved base oil margins. On Slide 12, the Corporate and Other segment had adjusted pretax costs of $246 million, $11 million higher than the prior quarter. The increase was mainly due to consolidating DCP Midstream interest expense of $34 million, partially offset by higher interest income. Slide 12 shows the change in cash during the third quarter. We started the quarter with a $2.8 billion cash balance. Cash from operations was $3.1 billion. During the quarter, we funded $735 million of capital spending, including the company's $306 million investment in DCP Midstream, LLC associated with the merger, net of cash acquired. We returned $1.2 billion to shareholders through dividends and share repurchases. Our ending cash balance was $3.7 billion. We ended the quarter with a net debt-to-capital ratio of 29%, including the consolidation of DCP Midstream. This concludes my review of the financial and operating results. Next, I'll cover a few outlook items. In Chemicals, we expect the fourth quarter global O&P utilization rate to be in the mid-90s. In Refining, we expect the fourth quarter worldwide crude utilization rate to be in the low to mid-90s and pretax turnaround expenses to be between $180 million and $220 million. As a result of strong turnaround execution and timing, we expect full year turnaround expenses to be lower than our original $800 million to $900 million of guidance. We anticipate fourth quarter Corporate and Other costs to come in between $300 million and $325 million pretax, reflecting a full quarter of DCP Midstream interest expense. Now we will open the line for questions.

Doug Leggate :

Kevin, I wonder if I could just ask you about your thoughts on the balance sheet going forward. I mean, clearly, you're back to, I guess -- on a capitalization basis, you're back to pre-COVID levels pretty much. But the absolute debt, now you have DCP is still about 30% up on where it was before the downturn. So how are you thinking about where you want the balance sheet to be going forward and how that might play into your cash return strategy?

Doug Leggate :

I'm trying hard, Kevin, not to ask anything that I know you won't answer, given that you've got the Analyst Day. So I'm avoiding some of the obvious things, but I do want to try 1 that really came up in the last -- the call that preceded this one with Marathon. And it's the issue about the industry or senior management's view of mid-cycle. And Marathon were quite clear to say, look, in mid-cycle has moved up. You guys used to talk about, I guess, $6 billion to $7 billion of mid-cycle cash flow. Again, not preempting next week but can you maybe offer, whether Mark or anyone else, how you feel about the go-forward outlook for mid-cycle earnings for this business, of the Refining business?

Doug Leggate :

I understand. We'll wait until next week.

Neil Mehta :

Yes. I wanted to start off on the waterfall on Slide 20 of the deck in the Central Corridor. Really exceptional capture rates in that region. And I was wondering if there's anything unusual in there if there's something structural that we should capitalize, as I know that other bucket can be -- move around a bunch. And how much did WCS help this quarter? Or given the fact that it typically comes in at a lag, is that more of a 4Q tailwind?

Rich Harbison :

Okay, Mark. Neil, good question. And yes, the Mid-Con Central Corridor had a very good quarter. Let me start by resetting the basis for the second quarter. Second quarter for us was a heavy turnaround in this region. So a lot of the difference you're seeing is the lack of turnarounds in the third quarter. Our mechanical availability during the third quarter was very good. We had high utilizations sitting at around 93% and strong clean product yields sitting at 88% for the corridor. So good performance on both of those. Of course, those directly relate to increased volumes. And with the lack of turnarounds, we had a lot lower operating expense for the quarter as well. As you indicated as well, Neil, the market conditions were quite favorable for our kit. We saw widening Canadian spreads which are quite favorable for us as well as a very strong distillate crack in the region. And that also plays well for our kit, which is a strong distillate producer. So I think what you're seeing here is a strong operating performance in favorable market conditions playing out for us in the third quarter.

Brian Mandell :

Neil, this is Brian. I'll start by saying that WCS started weakening with unplanned maintenance. WCS was forced into the Gulf Coast and then forced to compete with SPR barrels. We've released about 180 million barrels of SPR crude. Most of that has been sour so we competed with WCS. High sulfur fuel oil has also been weak and it competes as well, given weaker bunker demand and the end of summer utility burn. And also, generally, WCS is purchased by Asia and India, and they were out buying euros, Russian crude, so they weren't buying as much. And finally, WCS has a high naphtha cut, and that naphtha has been very, very weak because of the Chemicals business. So that also caused some pressure. So currently, WCS is at about $30 differential. Q4, if you look at the forward curve is at $26 off and next year is about $23 off. So we assume that it will continue to be weak and the market players also feel the same way.

Roger Read :

I guess I'd like to maybe take a shot here at the Chemicals side of things. So obviously, kind of the softer results and coming off what was an impressive sort of '21, early '22 run. You mentioned FID for the Gulf Coast and then also the Ras Laffan opportunity. Does the weakness in Chemicals here at all imperil your timing on decision of FID? Or does it have any impact whatsoever?

Roger Read :

That makes sense. And then my other question on the Marketing business. You had an exceptional Q2 and now in an even more exceptional Q3. Any kind of background on what's going on there? And are the fundamentals that created the last two quarters showing any signs of reversing here?

Operator:

Next question will be from Ryan Todd at Piper Sandler.

Mark Lashier :

Yes. This is Mark. I'll come in at a high level, then I'll let Rich and Brian follow up. But I think generally, those are constructive for us. It's -- I think it could strengthen our position, particularly around distillates and it's going from strength to strength. But I will let Brian and Rich comment on the details.

Rich Harbison :

Yes, I don't -- this is Rich. I really don't have much to add to that other than from a Refining perspective, of course, the natural gas price will drive up our operating expenses. And we will see higher feedstock costs as this market evolves here into the future and these sanctions go into play. So how that all sails out will be interesting.

Mark Lashier :

At a high level, Ryan, that -- the process is underway. We are negotiating with independent directors that represent the unitholders. And I will just say that we need to let that process play out. It's better to get the right number than to get a quick number. And as far as the strategic dynamics, Tim can talk more about that, but it really is about driving this wellhead to market strategy that we really believe will create a lot of long-term value and opportunity for Phillips 66. Tim, do you want to comment on that?

Operator:

Next question will be from John Royall at JPMorgan.

Mark Lashier :

At a high level, John, we are committed to buybacks. We had to hold back in the second quarter due to a blackout period. And so that kind of held us back for a bit. But what you saw last quarter is just a signal that we are serious about buybacks. And I'll let Kevin talk about the balance between what it will require to execute the roll-up of DCP versus share repurchases. But we have got a solid plan. And like a broken record, I'll say you'll hear more about it at Investor Day.

John Royall :

Okay. And then apologies to repeat a prior question, but I was just thinking through your commentary on the strength in Central Corridor. And correct me if I'm wrong, but I'm not sure if the things you guys talked about necessarily address the Other bar, flipping from negative 8 to positive 4.50 going from 2Q to 3Q. So apologies if I missed this, but if you could go through the dynamics in that Other bar specifically, that would be really helpful.

Operator:

Next question will be from Matthew Blair at TPH.

Mark Lashier :

Yes. Thanks, Matt. That's a great question. We've talked to the folks at CPChem about that. I think part of it is that lack of European capacity though. Though we do, the Middle East assets do supply a lot of volume into Europe but they continue to perform well. The interesting thing is others have had to cut back production in North America, CPChem continued strong production. They had some unplanned outage but no intentional cutbacks. And I think that reflects their cost position. They didn't have to cut back to contain inventory. They didn't have to cut back due to economics. They had -- they ran strong and were profitable. And part of that is they're heavy into high-density polyethylene and the dynamics there are a little different than linear low-density polyethylene. And those that were cutting back were more exposed to that segment of the market. So I think they're -- while no one's having any fun in that environment right now, they are positioned a little -- to be a little more productive during this difficult time. And then as far as the fourth quarter, fourth quarter is typically soft and we continue to see this new capacity that's coming online being digested. Margins have gone down. Marker margins have gone down to just about the breakpoint. So I think as you see people that have cut back, as you see them signaling to the market that they need prices to go up and polyethylene to continue to provide what is needed in the marketplace, it's sounding feeling like it's kind of hit bottom. We'll probably see it hit bottom in the fourth quarter and then slowly recover. It will take a couple more quarters to really -- to see a lot of movement upward, but I think you're seeing those signs of bottoming out.

Brian Mandell :

Yes. Generally, when you have weak naphtha, Matt, you have high or large octane spreads, and naphtha's been very, very weak so gasoline blenders need the octane to blend into the gasoline to make finished grade. And I would say that like most marketers, we're about 11% or 12% on our premium in our Marketing business.

Paul Cheng :

Two questions, please. First, with the latest news from Biden talking about the oil industry with the windfall profit tax, just wondering that your people in D.C., when they talk to the senator, what's your guess is whether there will be sufficient vote in the Senate for them to pass that, if the President does propose one? The second question is that, want to see what is your R&D strategy, renewable diesel strategy beyond the retail conversion that you're currently doing? I mean, that over -- I mean, it was -- the first phase will come onstream soon and then full completion probably in 2024. And so wanted to see that beyond that, that is going to be one-off or let's say, more maybe that strategy going forward on that?

Operator:

Next question will be...

Operator:

Our last question is from Jason Gabelman at Cowen.

Mark Lashier :

Yes, Kevin will touch on the cash flow detail. I'll talk about those reports on headcount.

Mark Lashier :

Yes. On the -- Jason, on the headcount issue, yes, we've been focused on our business transformation for well over a year now, and this is a facet of that work, and we've been executing that portion of the work. It's material. We will provide more details next week at Investor Day. I think though, it's a clear signal of our commitment to lower our cost, to eliminate unnecessary work, to have an optimal organization to go forward in what is an ever-changing volatile environment that we did execution reduction in force during the best two quarters in our history.

Jeff Dietert :

We thank all of you for your interest in Phillips 66. If you have questions on today's call, please call Shannon and me. And we look forward to seeing many of you at the Investor Day next week. Thank you.

Jeff Dietert:

Good morning, and welcome to Phillips 66 second quarter earnings conference call. Participants on today's call will include Mark Lashier, President and CEO; Kevin Mitchell, EVP and CFO; Brian Mandell, EVP, Marketing and Commercial; Tim Roberts, EVP, Midstream; and Rich Harbison, SVP, Refining. Today's presentation materials 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. Before we begin our discussion, I would like to highlight that we will be hosting an Investor Day in New York on November 9. With that, I'll turn it over to Mark.

Kevin Mitchell :

Thank you, Mark, and hello, everyone. Starting with an overview on Slide 4, we summarize our financial results for the second quarter. Adjusted earnings were $3.3 billion or $6.77 per share. A $240 million decrease in the fair value of our investment in NOVONIX reduced earnings per share by $0.38. We generated $1.8 billion of operating cash flow, including a working capital use of $1.8 billion. Cash distributions from equity affiliates were $527 million. Capital spending for the quarter was $376 million, including $167 million for growth projects. We returned $533 million to shareholders through $460 million of dividends and $66 million of share repurchases. We ended the quarter with 481 million shares outstanding. Moving to Slide 5. This slide highlights the change in adjusted results by segment from the first quarter to the second quarter. During the period, adjusted earnings increased $2.7 billion with a substantial improvement in Refining. Slide 6 shows our Midstream results. Second quarter adjusted pretax income was $292 million compared with $242 million in the previous quarter. Transportation contributed adjusted pretax income of $250 million, down $28 million from the prior quarter. The decrease was mainly due to lower equity earnings, driven by reduced Bakken crude volumes associated with winter storm impacts. NGL and Other adjusted pretax income was $152 million compared with $91 million in the first quarter. The increase was primarily due to improved margins and volumes at the Sweeny Hub. The margin improvement includes unfavorable inventory impact in the previous quarter. In addition, we had higher Sand Hills Pipeline equity earnings in the second quarter. The fractionators at the Sweeny Hub averaged a record 441,000 barrels per day, and the Freeport LPG export facility loaded 240,000 barrels per day in the second quarter. DCP Midstream adjusted pretax income of $130 million was up $99 million from the previous quarter, mainly driven by improved gathering and processing results and hedging impacts. The hedge gain recognized in the second quarter was approximately $30 million compared with a hedge loss of approximately $50 million in the first quarter. Our NOVONIX investment is marked-to-market at the end of each reporting period. The fair value of the investment, including foreign exchange impacts, decreased $240 million in the second quarter compared to a decrease of $158 million in the first quarter. Turning to Chemicals on Slide 7. Chemicals second quarter adjusted pretax income of $273 million was down $123 million from the prior quarter. Olefins and polyolefins adjusted pretax income was $216 million. The $161 million decrease from the previous quarter was primarily due to lower margins resulting from higher feedstock costs as well as increased utility and turnaround costs. Global O&P utilization was 94% for the quarter. Adjusted pretax income for SA&S was $59 million, up $27 million from the prior quarter. The increase was mainly due to improved margins on benzene and specialty chemicals as well as improved styrene results. The $11 million improvement in Other mainly reflects lower employee-related expenses and higher capitalized interest related to growth projects. During the second quarter, we received $216 million in cash distributions from CPChem. Turning to Refining on Slide 8. Refining's second quarter adjusted pretax income was $3.1 billion, up from $140 million in the first quarter. The improvement was primarily due to higher realized margins across all regions. Realized margins increased by 168% to $28.31 per barrel. Pretax turnaround costs were $223 million, up from $102 million in the prior quarter. Crude utilization was 90% in the second quarter and clean product yield was 83%. Slide 9 covers market capture. Our composite global 3:2:1 market crack for the second quarter was $46.72 per barrel compared to $21.93 per barrel in the first quarter. Realized margin was $28.31 per barrel and resulted in an overall market capture of 61%. Market capture in the previous quarter was 48%. Market capture is impacted by the configuration of our refineries. We have a higher distillate yield and a lower gasoline yield than the market indicator. During the quarter, the distillate crack was $61.38 per barrel, and the gasoline crack was $39.52 per barrel. The configuration impact as a percentage of the market crack was similar to first quarter. Losses from secondary products of $3.03 per barrel were in line with the prior quarter. Our feedstock loss of $1.46 per barrel declined $2.47 per barrel from the previous quarter due to narrowing Canadian crude differentials. The other category reduced realized margins by $7.48 per barrel. This category includes RINs, clean product realizations, freight costs and inventory impacts. Moving to Marketing and Specialties on Slide 10. Adjusted second quarter pretax income was $765 million compared with $316 million in the prior quarter. Marketing and Other increased $453 million from the first quarter. This was primarily due to higher realized fuel margins, including inventory impacts. Refined product exports in the second quarter were 153,000 barrels per day. Specialties generated second quarter adjusted pretax income of $109 million, in line with the previous quarter. Slide 11 shows the change in cash during the second quarter. We started the quarter with a $3.3 billion cash balance. Cash from operations was $3.6 billion, excluding working capital. There was a working capital use of $1.8 billion, mainly reflecting an increase in accounts receivable due to higher product prices and timing of sales. We repaid $1.5 billion of debt, lowering our net debt-to-capital ratio to below 30%, the lowest it has been since the fourth quarter of 2019. In addition, we funded $376 million of capital spending and returned $533 million to shareholders. Our ending cash balance was $2.8 billion. This concludes my review of the financial and operating results. Next, I'll cover a few outlook items. In Chemicals, we expect the third quarter global O&P utilization rate to be in the mid-90s. In refining, we expect the third quarter worldwide crude utilization rate to be in the low to mid-90s and pretax turnaround expenses to be between $260 million and $290 million. We expect full year pretax turnaround expenses to be at the lower end of our $800 million to $900 million guidance. We anticipate third quarter corporate and other costs to come in between $210 million and $230 million pretax. Now we will open the line for questions.

Neil Mehta :

I wanted to kick off with you, Mark, on your perspective as the new CEO, and congratulations to you, again, on the role. And one of the areas that you've talked about in the past that you think there is an opportunity gap around earnings is to improve the profitability of the Refining segment and some of that came through this quarter, for sure. So I just would love to hear how you're seeing the business transformation. What are the things that you're doing strategically on the ground? And how should we as an investment community evaluate that progress?

Neil Mehta :

And maybe the follow-up to that is a little bit more from your term question is how should we think about the refining market conditions right now impacting your 3Q profitability? You're guiding to crude utilization, which is pretty good, low to mid-90s, diesel is trading above gasoline, WCS is winding out. In theory, this should be a good opportunity set for your Refining business.

Operator:

Doug Leggate from Bank of America, please go ahead.

Mark Lashier :

Thanks, Doug.

Mark Lashier :

You broke up a little bit, Doug. I think the first part of the question was about our view on capacity additions. I'm going to have Jeff address that. And then we may have you repeat the second half because you broke up a little bit.

Douglas Leggate :

Okay. So Jeff, I want [indiscernible]...

Douglas Leggate :

Okay, I apologize. My phone signal is not best. So I'll try my follow-up. I'm interested in the relative profitability of Humber relative to your U.S. business. I'm thinking specifically about the cost of natural gas in Europe is obviously lifting the cost of European refining. You've got a unique insight to that, I guess, along with [oil]. So I'm just wondering if you could share your perspective on how Humber is doing in this environment. And where you see [indiscernible] perhaps relative to the other European refiners?

Rich Harbison :

Yes, certainly. Thanks, Mark. And Doug, good question. And certainly, it's on the minds of a lot of folks right now. The price of natural gas in the European market has gone quite high. Fortunately, for us, the Humber facility has a very mature energy stewardship program. It's been in place for over 20 years in that marketplace. They're a very efficient operation, actually the lowest CO2 emitter in the UK refining systems. They're a very low consumer of purchased natural gas. And in a high natural gas price environment, obviously, there's some impact on their business, right, as far as electricity costs that are externally provided and chemical costs in those areas, which are consistent with the broader industry as well. But primarily, where Humber's advantage is in the operation is that fuel efficiency. And they buy very little to no natural gas for fuel gas supply to the facility.

Rich Harbison :

Yes. And they consume a little bit of hydrogen but mostly self-generated inside the facility. And that hydrogen price will be impacted a little bit by the natural gas, that's right.

Brian Mandell:

Generally, for most refiners, we think in somewhere in the $10 to $12 range, we're advantaged versus those refiners. Rich pointed out Humber and where that stands versus other refiners in the market.

Roger Read :

Mark, welcome to the role. Maybe to take in a little bit of a forward look, I mean, I know everybody worries about gasoline demand taking a hit. But as mentioned many times, diesel is a bigger part of your kit. And as we look towards the following winter, where do you think we are now in terms of broadly speaking, diesel production, sensitivity, if any, that you've seen on price? And then between either max diesel or max jet or max distillate first gasoline, how that setup looks for you?