Hello. And welcome to the Fourth Quarter and Full Year 2023 Philips 66 Earnings Conference Call. My name is Emily, and I’ll be your operator for today’s call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded. I will now turn the call over to Jeff Dietert, Vice President, Investor Relations. Jeff, you may begin.

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.

Thanks, Jeff. Welcome, everyone, to our fourth quarter earnings call. We delivered a strong quarter and a strong year. In 2023, our total shareholder return was 33% and we increased our quarterly dividend by 8%. Today we’re going to cover a few major items, including the reasons why Philips 66 is an attractive investment opportunity and we’ll highlight the progress we’ve made on our strategic priorities. Next, we’ll discuss our fourth quarter financial results. Then we look forward to your questions. On slide three, we summarize the attributes that make us a differentiated and attracted value proposition. Our diversified and integrated portfolio delivers strong returns on capital employed and a high payout ratio supported by dividend growth. We’re on a path to increase mid-cycle adjusted EBITDA by 40% to $14 billion by 2030. In addition, 75% of this growth will be outside of Refining. We expect this growth and more stable cash flow to support our valuation going forward and contribute to attractive total shareholder returns. Our disciplined approach to capital allocation across our portfolio has contributed to an average return on capital employed of 13% since our formation in 2012, almost double our cost of capital. We’re committed to financial flexibility and our strong investment grade credit rating remains differentiated relative to our peers. We expect to return in excess of 50% of our growing operating cash flow to shareholders. All of these attributes will support a secure, competitive and growing dividend, strong share repurchases, as well as debt reduction at mid-cycle margins. Slide four summarizes our achievements to-date on our strategic priorities. On our last call, we raised our targets and continue to successfully execute our plan to increase mid-cycle adjusted EBITDA and grow shareholder distributions. Since July of 2022, we’ve distributed $8.3 billion through share repurchases and dividends. We’re on track to achieve our $13 billion to $15 billion target by the end of 2024. The execution of our plan to enhance Refining operating performance has resulted in crude utilization rates above the industry average for four consecutive quarters. In fact, we operated at our highest annual rate since 2019. We remain focused on improving performance, increasing market capture and reducing costs to enhance our earnings per barrel. In Midstream, our NGO wellhead to market business continues to exceed our expectations. The team has done a remarkable job of integrating DCP Midstream and captured run rate synergies of $250 million as of year-end and we expect over $400 million of synergies by 2025. Since increasing our ownership of DCP, the Midstream annual run rate for adjusted EBITDA has been $3.6 billion. The stable cash generation from our Midstream business has grown to a level that covers the company’s top capital priorities, funding sustaining capital and the dividend. We’re delivering on business transformation targets and remain laser focused on further reducing our cost structure in 2024. Kevin will be providing more details. In addition, we plan to monetize assets that no longer fit our long-term strategy. These asset dispositions are expected to generate over $3 billion in proceeds that will support our strategic priorities, including returns to shareholders. Timing of these dispositions will be subject to satisfactory market conditions and any necessary regulatory approvals. Our total adjusted EBITDA in 2023 was $12.7 billion, reflecting above mid-cycle margins in Refining and nearly $6 billion contributed by our more stable Midstream and Marketing and Specialties businesses. We’re focused on disciplined capital allocation, only funding attractive, high-return projects across our portfolio. The Rodeo Renewed Project to convert our San Francisco Refinery into one of the world’s largest renewable fuels facilities is expected to generate strong returns. The project’s progressing well and we expect to start up later this quarter. Looking forward, we’re well positioned to achieve our targets by capitalizing on the strengths of our diversified and integrated portfolio. We’ll do this through continued operating and commercial excellence to deliver significant shareholder value through the economic cycles as demonstrated by our total shareholder return of 33% in 2023. Our commitment to a secure, competitive and growing dividend has resulted in a 16% compound annual growth rate since 2012. Before I turn the call over to Kevin to review the financial results, I’d like to thank the Phillips 66 team for their continued dedication to safe and reliable operations. Our employees enable us to execute on our strategic priorities and deliver on our mission to provide energy and improve lives. Kevin, over to you.

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]

Thank you. [Operator Instructions] [Audio Gap] Apologies, everyone. We have lost connection to the speakers. Please stand by while we reconnect them.

… 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.

Thank you. [Operator Instructions] Our first question comes from Ryan Todd with Piper Sandler. Please go ahead.

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?

Yeah. Ryan, it’s Kevin. Let me make some additional comments around that. So a few different drivers to the strong market capture. You’ll recall back in the third quarter, we talked about some inventory hedge impacts that were a negative $100 million to $150 million and that we expected that to reverse in the fourth quarter, and that is in fact what happened. And so you had that benefit, which is a circa close to $300 million swing quarter-over-quarter. We also had improved feedstock, especially in the central corridor on Canadian crude differentials, and obviously, that’s really a market-driven item. In the Gulf Coast, we had benefit from product pricing because of the effect on -- sort of lagged effect on product pricing for barrels going up colonial and so that again is a bit of a market-driven factor. So that item was a bit of a headwind in the third quarter, it was a tailwind in the fourth quarter and what will happen in the first quarter is going to be dependent on where prices end the quarter at. But we also had strong commercial results and this is a result of really being able to take advantage of market opportunities as they present themselves to us. So we were able to capture strong pipeline arbitrage and the commercial optimization around that as we optimized those barrels. So it’s a bit of a combination of there are certain things that you would say were unique to the market dynamics in the quarter, but some of it is a function of strong operations, strong commercial execution by that organization.

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.

Yeah. Ryan, this is Rich. I’ll take that question here to kick it off and maybe somebody will fill in for some additional color here. But the way we see the project progression at this point is, as Kevin mentioned in his points that, in February, we’re going to shut down the facility and that will allow us then to tie in the common utilities for one of our hydrocrackers, which is currently in the conversion process. We expect that to start up in March timeframe, which will quickly ramp up to about 50% of the stated capacity of the Rodeo Renewed Project. In April, we will finish up the PTU and continue the conversion of the second reactor hydrocrackers system and finish that up in April and then start the commissioning process, which will roll into the May timeframe and then we’ll continue to optimize performance up and we expect to be up to full rates by the end of the second quarter would be the ramp period for that. Does that answer your question there, Ryan?

Yeah. Yeah. That was great. Thank you.

Our next question comes from Manav Gupta with UBS. Please go ahead.

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.

Yeah. Manav, thanks for your comments. I’m just going to make some high level comments and then turn it over to Tim. But I appreciate you recognizing that we are delivering on the integration. The integration has been a success. The DCP team is fully integrated into Phillips 66 and performing seamlessly, and we’re seeing great, really synergies across the whole value chain that even down at the level of communications, things happening quicker, things -- better decisions being made faster and it’s really been something to behold. As we noted in the comments, we did hit $250 million of synergies captured and we’ve got a line of sight on another or getting that up to $400 million plus. And Tim and his team are hard at work, so I’ll let him give you some more color on that.

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.

Perfect. And my quick follow-up is, you always have a very informed view of the Refining macro. Help us understand within your system what you’re seeing in terms of gasoline, diesel and even jet fuel demand out there?

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.

Thank you so much, guys.

Thanks, Manav.

The next question comes from Doug Leggate with Bank of America. Doug, please go ahead. Your line is open.

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.

Yeah. Doug, it’s Kevin. Let me try and fill in the gaps on that one for you. There’s really a couple of items that are probably a bit more significant in terms of the shift from current to what’s 2025 mid-cycle the $14 billion target. So for one, remember, the $14 billion is mid-cycle. The Chemicals business is not at mid-cycle currently and that’s about an incremental $1 billion to get to mid-cycle. And then in a -- on a mid-cycle basis, there’s an increment of about $200 million from the mid-cap projects that they have just put into place, most of which took place -- happened towards the end of last year and so an incremental billion in Chemicals really driven by the overall environment. Rodeo is not reflected in current and that’s a $700 million mid-cycle impact. And so that’s a -- between those two, you’re at getting close to $2 billion of increment that is still to come. There is some additional on the cost side of things and there’s Midstream at -- while we’re close to our mid-cycle on a run rate basis, remember, the $12.7 billion only had our current ownership of DCPs since June of last year. So there’s that incremental step up on it from an adjusted basis on that -- in that respect. In addition, we talked about the $600 million of additional commercial contribution to the business. We expect to see that materialize over the next two years and we’re also executing on the Refining projects that Rich has talked about in the past. And so those are the items that are going to get us to that $14 billion 2025 mid-cycle level.

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.

Yeah. Doug, it’s -- understand the request and why you would want that and we’ll take that under consideration as we think about how we’re going to report the go-forward Rodeo as a renewable fuels facility, because we do want -- we also want to be able to demonstrate that that asset as a renewable fuels facility is generating the kind of financial results that we’ve been talking about and so we’ll take that under consideration in terms of what we show from a recast basis. I think the question on what Rodeo has done in the past, it’s really been a function of the market environment. I mean, it has been challenged over the last few years as what was historically a very strong crude advantage, sort of disappeared with the declining supplies of domestic feedstocks for this facility and having to rely more on imported barrels. But then you’re also, it’s a high cost area as you know, so it’s, although that’s typical, that’s all of California is that way and then you’re into what the market environment looks like. And so what we’ve typically seen in California is when there’s operating upsets and supply is impacted, then you see an increase in margins and the financials look respectable, but there are -- when everything’s running well, it’s more challenged.

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

The next question comes from the line of John Royall with JPMorgan. Please go ahead, John.

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?

Yeah. John, you’re right that the working capital tailwind that we expected to see for a variety of reasons didn’t quite materialize the way that we thought they would and that probably impacted us by 2 percentage points to 3 percentage points on the net debt to capital metric. We expect to make some modest progress on a debt reduction in 2024. We have a total of $1.1 billion of maturities in 2024 at the Phillips 66 level. And so that gives us some flexibility in terms of how we manage this. I will say though, that the working capital component is always a little bit of a wild card, because it can swing us to the tune of a couple of billion dollars over the course of a quarter and that has an impact on the stated metrics. So I think what I’d say is that, we still target the 25% to 30% range, but when you step back and look in aggregate terms, we’re very comfortable with where we are, and our capital allocation decisions are going to be made with consideration of all the different priorities that we’ve got out there of which the balance sheet and debt is one of them. So I don’t want to commit to any sort of rash decisions just to target that one particular metric. We want to make sure we make the right overall decisions factoring in all of the different priorities.

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, I’ll take that. This is Rich. Yeah. I think that the range that we’re at last year and this year is what you would consider an average year for us and the outlook for this year stays in that. Like most companies, we do concentrate our plan maintenance activity in the first and fourth quarters in our system in any given year and we tend to lighten those during the driving season, second quarter and third quarter of the year. But the way our turnarounds are working and a huge effort by the organization, which I need to compliment them, is to really flatten out these heavy peak periods in our turnaround cycles. Now, we will occasionally get a couple sites that get stacked up on ourselves, but what we’ve really tried to do is push those out, level out the spend on a long-term basis and work towards this $500 million to $600 million range as our average turnaround cycle. So there will be a few years that will be a little bit higher than that and then there will be some that may be slightly under that as well. But in a general sense, that’s a good number to use.

Thank you.

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

Hey, guys. Good morning.

Good morning, Paul.

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?

So, Paul, what was the first part of the question? I missed that first piece.

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?

So, Rodeo performance in the fourth quarter versus the first quarter.

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.

And, Kevin, if I look at on your page 23 on your presentation, in terms of the margin capture, the other column, you’re talking about $7.11. And in here that, you have, call it, $200 million of, I think, the swing benefit from the Colonial Pipeline product pricing. So that’s translating to about $3.90. So where is other, say, $3 per barrel contribute to that?

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.

So I suppose that the bulk of the gap, say, $3 is contributed by commercial operation or that there’s just a minor piece of that you have other things that are even a bigger contributor?

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.

Okay. Got it. Thank you.

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

Hey. Good morning. Thanks for taking my questions here. On the Chem side, sorry, on the Chem side, you provided strong utilization guidance once again for Q1. Could you talk about the recent improvement in PE prices? What’s driving that? And then also, could you share any trends on demand that you’re seeing, either export-related or domestic?

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.

Yeah. And Matthew, I think this just demonstrates the resilience of CPChem across this down cycle. They’ve done relatively well, been able to run at high rates and compete, and be cash positive and show bottom of the cycle returns that we’re happy with. We’re anxious to see them come out of this cyclical downturn, but they are really, really well positioned for the long-term.

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?

Yeah. Matt, that’s a great question. We had pretty strong deferred tax benefit in 2023 and also 2022, and in both years the primary driver to those were the MLP roll-ups. So in 2022, we had benefit associated with PSXP, and in 2023, with the DCP roll-up. And that end -- in the end, that was a bigger benefit than we were anticipating, which drove some of the movements in that that you saw last year. That benefit drops off significantly as we go into 2024 and it’s a combination of less lower capital spend and so less depreciation to take advantage of, and bonus depreciation is scaling down as well, so we dropped 60% year one bonus in 2024. So we’re anticipating about a $200 million benefit for the year in 2024, so quite a lot lower than what we had in 2023. There is one caveat on this and that there’s a current bill in Congress that if ultimately passed, will extend some of the tax provisions from the Tax Cuts and Jobs Act. Right now we’re in the process of starting to sunset out, and if that passes, we’ll actually see 100% bonus depreciation backdated to 2023, so you’d get 2023, 2024 and 2025 all at 100%. That would benefit us in 2024 and to the tune of probably an incremental $300 million or so, but that’s contingent on that legislation passing.

Great. Thanks for the color.

Yeah.

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

Yeah. Hey. Thanks for taking my questions. I had a follow-up question on the Rodeo startup plan and I appreciate all the color. I know you mentioned it was going to be ramping up to full rates by midyear. Does that also include indicative feed slate, meaning you’re going to be running dirty lower CI feed from the middle of the year? Is that going to be more of a ramp up once you hit full rates?

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.

Got it. And then my follow-up is on the Midstream segment and clearly very strong results, as you’ve discussed on the call. But I’m wondering if there’s any seasonality we should think about to the business that would result in maybe stronger winter results and weaker summer results, thinking of things like higher propane demand and butane being pulled out of storage for blending and anything else that would be included like that that would drive kind of lower earnings 2Q and 3Q relative to 4Q and 1Q. Thanks.

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.

All right. Great. Thanks.

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

Hi. In terms of your longer NGL wellhead-to-market strategy, can you just remind us, on a run rate basis, what do you anticipate is the breakdown of Y-grade volumes you control from your own processing plants flowing to your downstream assets versus third-party?

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.

Got it. And would you mind giving us an update on the progress with the asset sales? How far are you along this process and have you narrowed things down further?

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.

Thank you.

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

Great. Thanks for taking my questions and congrats on a good quarter. So I wanted to ask on cracks in the central corridor, particularly on the gasoline side, which have remained weak to start the year. I know you benefit from running WCS there, but I was just hoping to get your latest thoughts on Mid-Con dynamics and just watching there as the year progresses.

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.

Great. Thank you for that. And then I just wanted to ask on the export side, have you seen a shift in any crude or product flows with the Panama Canal capacity limitations or any Suez Canal diversions, maybe shipping more product to Europe.

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.

Great. Thank you all.

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

Thanks for all your questions. I’m going to wrap up with slide 13 and have some comments about where we’ve been and where we’re headed. You’ll recall back in 2022 at our Investor Day, we set some pretty ambitious goals and those goals were based on shareholder feedback. Then in 2023, we focused on what we control and we delivered on our plans with strong operating and financial results. Those results enable us to deliver the attractive returns to shareholders that you heard about today. Now, in 2024, we’re raising the performance bar once again to enhance our ability to reward shareholders with strong returns now and in the future. For those of you that are invested in Phillips 66, we thank you for your confidence.

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

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