Welcome to the Fourth Quarter 2022 Phillips 66 Earnings Conference Call. My name is Emily, and I'll be your operator for today's call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Please note that this conference is being recorded. I will now turn the call over to Jeff Dieter, Vice President of Investor Relations. Jeff, you may begin.

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.

Thanks, Jeff. Good morning, and thank you for joining us today. In the fourth quarter, we had adjusted earnings of $1.9 billion or $4 per share. We generated $4.8 billion in operating cash flow. For the year, adjusted earnings were $8.9 billion or $18.79 per share. Our diversified integrated portfolio generated strong earnings and cash flow in 2022, supported by a favorable market environment and solid operations. Our cash flow generation allowed us to strengthen our financial position by repaying debt and resuming our share repurchase program. We returned $3.3 billion to shareholders through share repurchases and dividends. We continue to focus on operating excellence and advancing our strategic priorities to deliver on our vision of providing energy and improving lives as we meet global demand. In Midstream, we continue integrating DCP Midstream to unlock significant synergies and growth opportunities across our NGL wellhead to market value chain. Additionally, we completed Frac 4 at the Sweeny Hub, adding 150,000 barrels per day. Our total Sweeny Hub fractionation capacity is 550,000 barrels per day, making it the largest fraction -- or the second largest fractionation hub in the U.S. In Chemicals, CPChem is pursuing a portfolio of high-return projects, enhancing its asset base as well as optimizing its existing operations. This includes construction of a second world scale unit to produce one hexene in Old Ocean, Texas, and the expansion of propylene splitting capacity at its Cedar buying facility. Both projects are expected to start up in the second half of 2023. CPChem and Qatar Energy announced final investment decisions to construct petrochemical facilities on the U.S. Gulf Coast Ras Laffan, Qatar. CPChem will have a 51% interest in the $8.5 billion integrated polymers facility on the U.S. Gulf Coast. The Golden Triangle Polymers facility will include a 4.6 billion pounds per year ethane cracker and two high-density polyethylene units with a combined capacity of 4.4 billion pounds per year. Operations are expected to begin in 2026. In January, the Ras Laffan petrochemical project was approved. CPChem will own a 30% interest in the $6 billion integrated Polymers complex. The plant will include a 4.6 billion pounds per year ethane cracker and two high-density polyethylene units with a total capacity of 3.7 billion pounds per year. Start-up is expected in late 2026. In Refining, we're converting our San Francisco refinery into one of the world's largest renewable fuels facilities. The Rodeo Renewed project is on track to begin commercial operations in the first quarter of 2024. Upon completion, Rodeo will have over 50,000 barrels per day of renewable fuels production capacity. At our Investor Day, we announced priorities to reward Phillips 66 shareholders now and in the future. We're holding ourselves accountable, and we know that you are as well. Slide 4 summarizes our progress. We are delivering returns to shareholders. Since July 2022, we've returned $2.4 billion to shareholders through share repurchases and dividends. We're on track to meet our target return of $10 billion to $12 billion by year-end 2024. In January, we reached an agreement to acquire all of the publicly held common units of DCP Midstream. We expect the transaction to close in the second quarter of 2023, at which point, we will have an 87% economic interest in DCP Midstream. The increase in our economic interest from 28%, prior to the third quarter transaction, is expected to generate an incremental $1.3 billion of adjusted EBITDA, including commercial and operating synergies. We're executing our business transformation. The team achieved savings in excess of $500 million on an annualized basis at the end of 2022, setting us up well for 2023. This includes cost reductions of over $300 million, mostly related to reducing headcount by over 1,100 positions during the year as we redesigned and streamlined our organization. In addition, our 2023 capital program includes a $200 million reduction of sustaining capital. We're transforming to a sustainable lower cost business model and expect to deliver $1 billion of annualized savings by year-end 2023. We're laser-focused on executing these strategic priorities to deliver returns and increase distributions in a competitive and sustainable way. We look forward to updating you on our progress. Now, I'll turn the call over to Kevin to review the financial results.

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.

Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our first question today comes from Neil Mehta of Goldman Sachs. Please go ahead, Neil. Your line is open.

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?

Hey, Rich here. Yeah, that's a really good question. When I look at that capture rate for the fourth quarter, the three simple things that stand out to me are really the impact of our turnaround activity. That's the first one. It was centric in the Gulf Coast and the Pacific Northwest. And the Pacific Northwest was an actual entire refinery shutdown that shouldered the third and fourth quarter of the year. So I look at those as temporaries. There was also some product differentials that played out across our system the Atlantic, the difference between the European distillate price and the New York Harbor price is reflective in that market capture. There was a significant reduction in diesel price there in Europe as well as the turnaround effect in the Pacific Northwest and also Northern California product prices were dislocated from the Los Angeles market as well. And the third influence in fourth quarter capture was really centric around the Keystone shutdown of the pipeline as well as the winter storm events in there. So that's -- when I look at those three effects, there's the majority of the impact associated with the capture rate in the fourth quarter.

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

Thanks for that. And the follow-up to that is just as we think about Q1, how some of these dynamics potentially reverse especially given it's going to be a pretty heavy turnaround quarter, it looks like, with the utilization guides in the mid-80s? Or do we really see that improvement materialize potentially more Q2 through balance of the year?

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.

And I would add in talking about European to New York distillate prices and Pacific Northwest and Bay prices to L.A., they should both normalize. We saw New York is over Europe. That's unusual. Europe imported a lot of Russian distillate prior to the price gap next week. And New York, because of the winter storm, didn't get all the barrels that it needs. So the reason why New York is over Europe now it's a prompt issue. And if you look at Colonial Pipeline, it's running at full rates now. New York will get fed back and then Europe will be over -- or under -- or over New York rather going forward. And the Pacific Northwest versus and Bay versus L.A. that was -- that's a temporary issue as well. Our pad refineries ran really well in November, December, we saw inventories really build across the markets. And given the oversupply, the markets needed to price to incentivize exports and the infrastructure for exports is in the Bay and Pacific Northwest. So that's where the exports came from. And also, we need to aggregate barrels for the exports. So some of the barrels that normally went to L.A. didn't go to L.A. at that time. So that increased the L.A. price, decreased the Pacific Northwest and Bay price. But going forward with heavy Pacific Northwest turnarounds and work in the Bay, we'd expect inventories to moderate as we get back to seasonal demand spreads between the north and south will come back into normal areas.

Thanks, guys. Appreciate it.

Thanks Neil.

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

Well, thank you. Good morning everyone. I wonder if you wouldn't mind, I'm going to try -- I'd like to build on Neil's question, if I may, but ask it a little differently. Is there any way, Kevin that you can quantify the lost opportunity cost in the fourth quarter to help us kind of reconcile that capture rate question? Is that possible?

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.

Okay. I guess -- thank you for that. I know it's a top tricky one to answer. So my follow-up is really more of a kind of an outlook question. And speaks to your comments about Northeast. I realize everyone is probably pushing product up to the Northeast during the winter because of all the noise around heating oil margins. But it occurs to us that, that was probably the first normal winter without Philadelphia Energy Solutions in 2019 when fire hasn't come back since. So we think about what does the Northeast look like in a normal summer driving season without Philadelphia Energy Solutions? And I'm just curious if you have -- given any thought, given that you did push product up to the Northeast, how you're thinking about what the gasoline market could look like in the summertime in the U.S.?

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.

I guess what I'm asking is, do you see the risk of an outside spike in gasoline the way we saw an outside spike in heating oil in the Northeast?

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.

I think the other thing I'd add is you look at gasoline, diesel and jet inventories, they're all below five-year ranges and it looks to us as though we've got an above-average industry refining turnaround period plan for the spring. So it looks tight from our vantage point.

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

Thank you, Doug.

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

Good morning, everybody. I guess I'll continue with the theme of hammering on capture and expectations of capture. Just curious why this quarter did change the index that you're using? And then I know you explained the gasoline and the diesel aspect. So configuration, I guess, makes sense. What maybe went on with secondary products? And is that something that we might see carry through to '23 here?

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

Yeah, your market indicator, yeah.

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.

Yeah. And then the secondary products, I'll kick that off and then turn it over to Brian maybe for some outlook on it. But third quarter to fourth quarter, in refining, we see those relatively flat actually. There are some puts and takes associated with that, asphalts and fuel oils drop off in price and volume, but butane picks up and offsets a lot of that. So the overall impact of our secondary products was relatively flat quarter-over-quarter.

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.

Our next question comes from John Royall of JPMorgan. Please go ahead, John.

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?

Yeah. I think, John, the $300 million really falls into two categories. Operating synergies that we're actively pursuing upfront now even before the close of the roll-up of the publicly held units. And then there's, I think, even more prolific commercial synergies that we can capture as we combine -- or as we roll the business into our own. Tim, you can provide a little more color there.

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.

Okay. That's helpful. And then just looking at the chemicals market, do you expect that we've seen a bottom there? And how does China reopening impact the future of that market? And then let's just say hypothetically, the market doesn't improve from here. Is there any risk of CPChem's ability to self-fund the two growth projects?

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.

Our next question comes from Ryan Todd with Piper Sandler. Please go ahead, Ryan.

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?

Yeah, Ryan, it's Kevin. So, you're right, we did the high end of the range in the fourth quarter, and I think it's reasonable to assume that we would continue somewhere round about that level. We're also -- we're sitting on a decent healthy cash end of the year just over $6 billion. And just to give some context to the overall balance sheet condition relative to where we were before the pandemic. Over the pandemic, we added $4 billion and I'm ignoring the impact of BCP debt consolidation here. We added $4 billion over the pandemic. We subsequently paid off 3.5 of that but we've improved our cash position by $4.5 million since the end of 2019. So net-net, we've enhanced the balance sheet by $4 billion from where we were going into the the pandemic. And so that gives us a lot of flexibility. But we've also got the DCP roll-up to take care of, which we expect to be sometime in the second quarter. So that's a $3.8 billion transaction. And while we won't use all cash for that, we want to make sure that we retain plenty of flexibility as we go into that and close on that rollout. But I do think what it all speaks to we continue to see these above mid-cycle conditions, we will have some good flexibility to -- I would tell you really do a bit of all of it. We'll want to pay off some incremental debt, especially as we think about the impact of the DCP roll-up, but we should also be positioned to look at the cash returns to shareholders, both in the context of the dividend, we would expect to increase the dividend. This year, we remain committed to a secure, competitive growing dividend. And we'll look at the buyback pace. We're clearly at a very healthy level today, but there's potential flexibility on that. And so, we -- it's something that we'll prioritize and keep very focused on. But in the near term, we're probably pretty comfortable with where we are given that we've got the DCP transaction out there ahead of us.

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?

I think with natural gas coming off some. We're not -- I mean Rich can talk about the natural gas issues at the plant.

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.

I'd like to circle back. I don't think I covered one of the questions that John asked around Chems and that's the risk -- the market risk of CPChem generating enough cash to self-fund these two projects. Both of those projects, they own 30% of the Ras Laffan project, 51% of the U.S.-based project, both will be off-balance sheet project finance, mitigating their cash outflows, substantially mitigating our exposure there. So you can never predict that there is no risk, but I think it's highly mitigated because of the debt structuring they're going to undertake to support those projects.

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

Hi, guys. Good morning. Maybe for Kevin, can you go back into the CPC with the two major cracker is going to be under construction? How is the CPC distribution to [Indiscernible] for the next several years we should assume? So we assume that it's going to be quite minimum and that they will build up their own financing and also some cash in the year given that there's a heavy spending ahead? Or that do you think that the decision is that they will just use more of that capacity and continue to payout?

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 --

Yeah. So just to expand on that a little bit. The -- when Mark talks about off-balance sheet financing, he is specifically referring to project level financing. So financing those projects at the Ras Laffan Petrochemical project level and at the Golden Triangle Polymers project level. So that's not on CPChem's balance sheet, and we're not anticipating that CPChem would have to go to its own balance sheet to fund its equity contributions into those joint ventures to fund those projects. And in fact, we'll still be able to do that and continue making distributions to the owners. Obviously, there is a dependency on what the overall market environment looks like. But based on what we're seeing, we still expect to be receiving distributions from CPChem through this period. Clearly, there's an impact. Anything -- any discretionary spend by CPChem into a capital investment is cash that's not available for distribution out, but it's all pretty manageable within the overall expectation of where their cash flows will be.

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?

Yeah. Well, you would expect it to be less than 100% because they do have the capital projects underway. So there's the two big ones that we've been talking about, and then there's a slate of smaller projects, several of which will actually finish this year. So it's going to be less than 100%. We've never given specific guidance on what we expect the distributions to be. And our history has actually been pretty strong with regard to cash coming back from CPChem.

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

Hey, good afternoon. I wanted to first ask on M&A in midstream. And I know when you rolled up PSXP part of the rationale was to have more flexibility across the whole portfolio, and you've, obviously, brought in DCP. So I wonder on the other side, is there any desire to reoptimize some of the midstream assets that you have in the portfolio that may not be core at this point? And then my second question is just on the marketing business, which has continued to perform pretty well. I was wondering if there were any dynamics in your markets that continue to support margins. And is there an outlook that, that margins can maybe be above mid-cycle in that business for 2023? Thanks.

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.

On the marketing business, I'd say that we will continue to perform well, perhaps not as well as 2022. That was a record year. But with increased volatility in the market, that generally drives better business. We also had a joint venture retail record year last year, and we continue to grow our retail joint venture in the U.S., and that continues to perform. Also, there are issues in the European market that have helped us, even things like expanding our credit card business has been helpful to growing our business. So I think we'll continue to grow the business. You'll see the earnings strong, but perhaps not quite as strong as 2022.

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

Hey, good morning. Thanks for taking my question. I wanted to ask about the WCS discounts, so they're pretty favorable. Could you talk about what's driving that? And will you be able to capitalize on these wide WCS discounts in Q1 in the Central Corridor? And then finally, how do you think the Trans Mountain expansion might affect these discounts? Thanks.

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.

Great. Thank you.

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

Hey, guys. Just real quick. Because of the keystone downtime, can you share that how much is the WCS that you run in the fourth quarter? And then what do you expect you're going to one year in the first quarter? And also, I believe with -- after the turnaround actually has been running at a pretty depressed way. I think at one point, about 60%, 65% and where are we in the Wood River?

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.

Yeah. So Wood River, there was an unplanned event incident that occurred at Wood River and -- let me start by saying our thoughts go out for the affected employees, contractors and their families that were associated with that event. But there was an incident there. We are working diligently right now to increase the utilization that was affected by this, and we expect that utilization to continue to increase through the first quarter and returned to normal operations early second quarter is our current outlook on that, Paul.

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

Do we normally give guidance by plant?

Not that specific.

Yeah. Unfortunately, Paul, we don't give that type of guidance by plant as to what our current run rates are.

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

Thanks, Emily. Thank all of you for your interest in Phillips 66. If you have questions after today's call, please call me or Owen Simpson. Thanks for your time.

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