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Intrinsic Value is all-important and is the only logical way to evaluate the relative attractiveness of investments and businesses.
Welcome to the First Quarter 2021 Phillips 66 Earnings Conference Call. My name is Hillary, and I will be your operator for today's call. [Operator Instructions].
I will now turn the call over to Jeff Dietert, Vice President, Investor Relations. Jeff, you may begin.
Good morning, and welcome to Phillips 66 First Quarter Earnings Conference Call. Participants on today's call will include Greg Garland, Chairman and CEO; Mark Lashier, President and COO; Kevin Mitchell, EVP and CFO; Bob Herman, EVP, Refining; Brian Mandell, EVP, Marketing and Commercial; and Tim Roberts, EVP Midstream.
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 presentation and our Q&A session. 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 over the call to Greg.
Thanks, Jeff, and good morning, everyone, and thanks for joining us today. First, I'd like to welcome Mark Lashier, our new President and Chief Operating Officer. I think many of you know Mark from his previous role as President and CEO of CPChem. And Mark, it's great to have you here with us at Phillips 66.
In the first quarter, we had an adjusted loss of $509 million or $1.16 per share. Our results reflect the impact of the severe winter storms in the U.S. Gulf Coast and Central regions where we experienced reduced volumes, increased utility costs and maintenance and repair costs.
We safely resumed operations across our businesses following the storm-related downtime. We're proud of our employees and their commitment to operating excellence, particularly during these challenging times.
Gasoline diesel demand continues to recover and product inventories have normalized, supporting higher refining margins and utilization rates. We expect continued recovery as we wrap up spring turnarounds and head into the summer driving season. Also, chemicals facilities are back to normal operations with continued strong demand and margins.
We remain optimistic about the impact COVID-19 vaccines and monetary stimulus will have on economic recovery in the back half of the year. Leading indicators suggests economic growth is accelerating, which supports demand for our products.
In the first quarter, we returned $394 million to shareholders in dividends. We remain committed to a secure, competitive and growing dividend. In February, we repaid $500 million of maturing debt. We will continue with a disciplined approach to capital allocation, including debt repayment as cash generation improves. We'll maintain a conservative balance sheet and a strong investment-grade credit rating.
The South Texas Gateway terminal commissioned additional storage, bringing the total capacity to 8.6 million barrels. This completes the final construction phase for this project. In addition, the terminal has up to 800,000 barrels per day of export capacity. Gold 66 Partners owns a 25% interest in the terminal.
Phillips 66 Partners continue construction of the C2G Pipeline, connecting its Clemens Storage Caverns to petrochemical facilities in the Corpus Christi area. The project is backed by long-term commitments and is expected to be completed in mid-2021. At the Sweeny Hub, we plan to resume construction of Frac 4 in the second half of 2021, which will add 150,000 barrels per day. Upon completion, the Sweeny Hub will have 550,000 barrels per day of fractionation capacity supported by long-term customer commitments.
In Chemicals, CPChem is advancing optimization and debottlenecking opportunities. This includes approved projects at its Cedar Bayou facility that will increase production of ethylene and polyethylene. In addition, CPChem is developing an expansion of its normal alpha olefins capacity.
We're advancing our Rodeo Renewed project at the San Francisco refinery. Earlier this month, we began renewable diesel production from the hydrotreater conversion, which will ramp up to 8,000 barrels per day in the third quarter. Subject to permitting and approvals, full conversion of the facility is expected in early 2024. On completion, the facility will have over 50,000 barrels per day of renewable fuel production capacity.
This capital-efficient investment is expected to deliver strong returns and reduce the facility's greenhouse gas emissions by 50%. This project will help California meet its lower carbon objectives.
We're increasing our focus on lower carbon initiatives across the company. This includes the creation of Emerging Energy group earlier this year and ongoing research and development by our energy research and innovation organization.
We've invested in Shell Rock Soy Processing, a joint venture that plans to construct a new soybean facility in Iowa. We expect the project to be completed in late 2022, and we will purchase 100% of the soybean oil production.
We signed an MoU with Southwest Airlines to commercialize sustainable aviation fuel. We launched a technical collaboration with Faradion, a leader in sodium-ion battery technology, to develop lower-cost, higher-performing anode materials for sodium-ion batteries. These activities further our commitment to addressing the global climate challenge while delivering attractive shareholder returns.
Finally, we'd like to comment on our company's operating excellence. We are honored that our refining, midstream and chemicals businesses were recently recognized for 2020 safety performance. Six of our refineries were recognized by AFPM, including Lake Charles, Ponca City and Santa Maria refineries, which received distinguished safety awards.
This is the highest annual safety award in our industry and the 5th year in a row that our refineries have received this honor. Our midstream businesses was awarded API Distinguished Pipeline Safety Award for large operators. This is the highest recognition by API from the midstream industry. In addition, we're recognized by the Gas Processors Association for outstanding safety performance in midstream.
In chemicals, AFPM selected CPChem's Conroe, Orange and Port Arthur facilities as recipients of the Elite Silver Safety Award. So congratulations to all these facilities well done, we're really proud of you.
So with that, I'm going to turn the call over to Kevin to review the financial results.
Thank you, Greg. Hello, everyone. Starting with an overview on Slide 4, we summarize our first quarter results. We reported a loss of $654 million. Special items this quarter included an impairment resulting from Phillips 66 Partners decision to exit the Liberty Pipeline project as well as winter storm-related maintenance and repair costs. Excluding these special items, we had an adjusted loss of $509 million or $1.16 per share.
We generated operating cash flow of $271 million, including distributions from equity affiliates of $502 million. Capital spending for the quarter was $331 million, including $174 million for growth projects. We paid $394 million in dividends.
Moving to Slide 5. This slide shows the change in adjusted results from the fourth quarter to the first quarter, a decrease of $2 million. Improved results in refining and marketing and specialties were offset by lower pretax income in the other segments. Our adjusted effective income tax rate was 16%. The rate is influenced by the proportional mix of pretax income from domestic, foreign and MLP sources.
Slide 6 shows our midstream results. First quarter adjusted pretax income was $276 million, a decrease of $47 million from the previous quarter. Transportation contributed adjusted pretax income of $206 million, up $10 million from the previous quarter. The increase was due to lower operating costs and higher equity earnings, partially offset by lower volumes. NGL and other adjusted pretax income was $36 million. The $50 million decrease from the prior quarter was mainly due to higher operating costs associated with the winter storms.
The Sweeny fractionation complex averaged 330,000 barrels per day and the Freeport LPG Export facility loaded a record 41 cargoes in the first quarter. DCP Midstream adjusted pretax income of $34 million was down $7 million from the previous quarter, mainly due to the winter storms.
Turning to Chemicals on Slide 7. First quarter adjusted pretax income was $184 million, down $19 million from the fourth quarter. Olefins and Polyolefins adjusted pretax income was $174 million. The $42 million decrease from the previous quarter was primarily due to winter storm impacts which resulted in lower production and higher utility costs. This was partially offset by higher margins, primarily due to tight supplies, low inventory levels and continued strong demand.
Global O&P utilization was 79% for the quarter. All impacted CPChem facilities safely restarted operations by early April. Adjusted pretax income for SA&S increased $14 million, primarily due to improved margins. During the first quarter, we received $205 million in cash distributions from CPChem.
Turning to Refining on Slide 8. Refining first quarter adjusted pretax loss was $1 billion, an improvement of $68 million from the fourth quarter. First quarter results reflect the impacts of the winter storms. The improvement was driven by higher realized margins, largely offset by increased turnaround costs as well as higher utilities resulting from the winter storms.
The increase in realized margins reflects improved crack spreads and the sale of excess electricity to help meet demand in the Texas market, partially offset by lower product differentials and higher RIN costs. Pretax turnaround costs were $192 million, up from $76 million in the prior quarter. We completed the majority of our spring turnaround activity this month. Crude utilization was 74% compared with 69% last quarter. The first quarter clean product yield was 82%.
Slide 9 covers market capture. The 3:2:1 market crack for the first quarter was $13.23 per barrel compared to $7.84 per barrel in the fourth quarter. Realized margin was $4.36 per barrel and resulted in an overall market capture of 33%. Market capture in the previous quarter was 28%. Market capture is impacted by the configuration of our refineries. We make less gasoline and more distillate than premised in the 3:2:1 market crack.
During the quarter, the gasoline crack improved $6.38 per barrel, while the distillate crack increased $3.41 per barrel. In addition, we had a lower clean product yield this quarter as a result of turnaround activity and unplanned downtime, which also contributed to the configuration impact. Losses from secondary products of $1.29 per barrel were $0.09 higher than the previous quarter.
Feedstock costs improved $0.37 per barrel compared with the prior quarter. The other category reduced realized margins by $4.78 per barrel. This category includes RINs, freight costs, clean product realizations and inventory impacts. It also reflects revenues from the sale of excess electricity into the grid.
Moving to Marketing and Specialties on Slide 10. Adjusted first quarter pretax income was $290 million compared with $221 million in the prior quarter. Marketing and other increased $30 million due to higher domestic margins, partially offset by lower international margins. Specialties improved $39 million, largely due to improved base oil and finished lubricant margins. Refined product exports in the first quarter were 204,000 barrels per day.
On Slide 11, the Corporate and Other segment had adjusted pretax costs of $251 million, an increase of $16 million from the prior quarter. This was primarily due to the timing of charitable contributions and environmental expenses. as well as lower capitalized interest.
Slide 12 shows the change in cash for the quarter. We started the year with a $2.5 billion cash balance. Cash from operations was $271 million. This included a working capital benefit of $98 million. In February, we repaid $500 million of floating rate senior notes upon maturity. Capital spending was $331 million, and we paid $394 million in dividends.
The other category includes a $155 million loan to our WRP joint venture. Our ending cash balance was $1.4 billion. At March 31, we had $6.7 billion of committed liquidity, reflecting $1.4 billion of consolidated cash plus available capacity on our credit facilities $5 billion at Phillips 66 and $299 million at Phillips 66 Partners.
This concludes my review of the financial and operating results. Next, I'll cover a few outlook items. In Chemicals, we expect the second quarter global O&P utilization rate to be in the mid-90s. In Refining, crude utilization will be adjusted according to market conditions. In April, utilization has been in the mid-80% range. We expect second quarter pretax turnaround expenses to be between $110 million and $140 million. We anticipate second quarter corporate and other costs to come in between $240 million and $250 million pretax.
Now we will open the line for questions.
[Operator Instructions]. Your first question comes from the line of Neil Mehta with Goldman Sachs.
And congratulations, Mark, on your new role.
Thanks, Neil.
Maybe I'll start with you, Mark, you and Greg have both spent a lot of time looking at chemicals over the years. We're obviously in a very strong margin environment right now. Where do you think we are in the polyethylene cycle from a margin perspective? And how are you thinking about the puts and takes? And then it sounds like utilization is ramping pretty well here in the second quarter. Should you be able to run and capture that strong margin, all else equal?
Right, Neil, thanks for the question. Yes, if you look at even back into 2020, CPChem experienced really strong demand and outstanding operational excellence margins were suppressed a bit by crude oil pricing, frankly, but we saw the record demand, record production coming out of CPChem. And margins were starting to improve late 2020. A lot of people have moved turnarounds out into 2021. We needed to build some inventory for those turnarounds and then Winter Storm Uri hits and really decimated the inventory in the system.
So we do see strong fundamentals, and we do see those margins improving even though we didn't realize it in the first quarter because of the winter storm. And so we believe that CPChem will see the benefit of those margins. So on average, the rest of the year, we'll continue to see increase into the second and third quarter, then maybe some seasonal weakness in the fourth quarter. But on average, we should see CPChem at or above mid-cycle margins this year.
And has your view of those mid-cycle margins changed? And maybe that's a question for Greg. I think historically, you said at $0.25 through the cycle fully integrated polyethylene margin.
Yes. I think if you look at '12 through '19, that's about what it averaged, Neil. And I think we're pretty comfortable on a go-forward basis. That's going to reference some kind of a mid-cycle number. We kind of look at reinvestment level economics and what does it take to get you kind of a 12% return, and that's what it is.
Great. And then the follow-up is just on leverage levels. Going into the pandemic, pre-pandemic, Debt levels were around $12 billion consolidated. Today, they're at $15 billion. Just can you take us into some of the conversations you're having with your bondholders and credit agencies around the appropriate leverage level in your mind until you get that leverage down to those levels? Are you constrained about what you can do around the share repurchase program?
Neil, it's Kevin. Let me make a few comments on that. So you're right, we came into the pandemic with $12 billion of debt. And we added $4 billion over the course of last year. We paid off $0.5 billion in the first quarter. Our primary focus from a leverage standpoint is around the credit rating. So we have an A3 and BBB+ rating, so very strong investment grade, but we do have a negative outlook on both.
And so we want to get back to maintain those ratings and with a stable outlook. And to do that, we need to demonstrate that we're getting debt levels back somewhere towards where they were before the pandemic kicked in. As you think about recovery and cash generation and the things we've done in terms of scaling back our capital and suspension of share repurchases as you start to see cash generation improve, we should actually have quite a lot of flexibility to make progress on paying down debt.
And once we're on a nice sort of pathway to getting back to somewhere around about that $12 billion level, I think we'll have a lot more flexibility to start considering other alternatives which could entail at some point, we want to get back to the dividend, get a dividend increase at some point. Again, at the right time, we'd like to be buying our shares back.
We still think they represent really good value and then potentially growth capital. We've intentionally restrained our growth capital. Our total capital budget this year is $1.7 billion, only $600 million of growth capital. And we're anticipating that for the next couple of years, we'll continue to be pretty constrained in terms of how much we're reinvesting in the business. And part of that's a function of where the opportunities are as well and the availability of that.
So then the last thing I'd say is we've got good flexibility with the debt maturities we've got coming up and the sort of callable debt we have. We have easy line of sight to over the next year or 2, assuming the cash generation is there. We've got $3.75 billion of debt that we can take care of either because it's callable or it's maturing.
And your next question comes from the line Roger Read from Wells Fargo.
I guess if we could talk a little bit about the midstream business, and I'm going to stay away from any DAPL questions. But specific to your commentary about Frac 4 starting up the number of vessels that left during the quarter. And as you think about that business going forward, I mean, some of the forecast for NGL type production in the U.S. are pretty robust despite maybe a more static oil environment.
So I was just wondering if that's what underpins frac for? Or just the volumes are already there, and it's just a question of getting past the whole pandemic issues and moving into that unit?
Roger, this is Tim. Thanks for the question. Actually, the fundamentals for NGLs are still good, albeit from the quarter standpoint, we had some puts and takes in there with regard to the winter storm. But the go-forward actually has -- it feels like it's got good strength, partially driven by -- and I'll go back to frac 4 to answer that question. But really, it's partly it's driven by global demand clearly for LPGs, propanes and butanes and then also growing demand for ethane, both here in the U.S. Gulf Coast, export ethane and just fundamentals in petrochemicals, as Mark just mentioned here, it's strong, and it's growing.
So in that capacity, NGLs and specialty advantaged NGLs will fill that void. Frac 4, we've got commitments on Frac 4. So actually, we paused while there was some uncertainty in the market last year. And we paused to kind of, okay, let's make sure we're taking care of our liquidity and balance sheet. We paused the project but we actually are looking to start it up in the second half of this year and get frac 4 completed as we continue to build out the hub down at Sweeny.
And again, there is continued demand. We've been running our facility. You noted that on the cargoes, that was a record level for the quarter for us. But we still see continued demand for LPGs and see that into the future as well as petchem becomes a bigger piece of that export pie versus res-com.
Great. And then my other question, follow-up in the refining business. I understand the guidance and all that. I was just curious how the RINs, the elevated RINs issue is kind of running through the business? I mean it seems like the outperformance, at least relative to the way we were looking forward in marketing and specialties is probably where the RINs benefit came through.
But I just wanted to make sure that you all are more or less balanced on the RIN issue and maybe how you think about that if it maintains these elevated levels kind of hits the rest of the year on capture for refining?
Yes. This is Bob. Roger, I'll take a shot at that. I think, yes, when you look at it, right, so we fully burden our refining results with the cost of the RIN and the run-up in RIN prices. But we believed and continue to believe that the RIN is priced out in the crack. So as that moves downstream through our various channels of trade, gets blended.
Some of it we get through our own liquid blending at our terminals, right, and generate the RINs there for our needs, and it really does pass on downstream to the ultimate consumer. Some of that, it goes through other channels of trade. We're not exposed on the exports. We had 200,000 barrels a day of exports in the quarter. So we continue to watch that market and we really like the fact that we can push a lot of our barrels through our own branded outlets.
I would just add that in our business, we blend about half. So we create to generate half -- about half the RINs we need for our obligation at Phillips 66. And then also in Q1, there was some blend margin. So RBOB was above ethanol. So there was some benefit in blend market and marketing as well.
Your next question comes from the line of Doug Leggate with Bank of America.
Guys, I'm sorry to beat on this. Roger tend to steal my [indiscernible] issue. So I want to dig into this a little bit more, if you don't mind. So Kevin, I'm looking at -- I think it's slide -- I've got -- I've lost the slide number. Now the one is showing basically the other issue in the crack. It was 4.78 this quarter. This past 3 or 4 quarters it started at negative 2.22. Back in 2019, the average is around $0.30, $0.40 negative. And it seems that, that number has moved up almost lockstep with the RIN.
So I just wonder if you could offer a little bit of color to, I guess, just to Roger's question, but is that what's going on here? Is that the biggest driver of that delta? And what should we be thinking on a go-forward basis because it's obviously denting the capture rate quite a bit.
Yes. Doug, you're exactly right. The RIN costs, as Bob describing, that being burdened in refining, that shows up in that other -- on that chart. I think it's Slide 9 on the deck. And so it's a direct hit to the capture rate. So as the RIN pricing increases, you'll see that happening there. Now the other comment that when we -- over the last year or so where we've been in a depressed margin environment, capture rates just generally are impacted by the fact that you've got costs that flow through here that are on a fixed per barrel basis. So there's some freight and the like that it's fixed cost per barrel. So proportionately, that becomes a bigger impact takes a bigger hit out of capture than when you're in a more normalized market environment. But RINs in that other is a big element.
Yes. And I think I would add to that kind of quarter-to-quarter you look at a couple of additional things that impacted them and in this particular analysis on the market crack, they end up another. One of them is that is the pricing differentials between Europe and New York Harbor. So we captured that. And Europe was particularly weak here in the first quarter. So that accounts for a good part of that delta off the fourth quarter.
And then we always get into the timing issues between the Gulf Coast and New York Harbor as we go up Colonial Pipeline. And so we saw a pretty negative hit there that really is timing as prices run up, and we'll get it back on the other side eventually. So -- but we don't -- in this analysis, there's no other place to capture them, so they end up in that other category.
Understood, guys. I don't want the labor at this point, but again, I'm building on Roger's question here, Kevin. It seems to me that even if I look elsewhere in the business, whether marketing or whatever, I can't see where you're getting that back. So can I just ask you again to clarify when is a net neutral or negative for Phillips.
Yes. So at the end of the day, as Brian covered earlier, right, we blend for about half and then half is other people blending and we're exposed to the commercial market on those RINs. So net-net, it is a negative to us at the end of the day. We do not capture the RIN at the 100% level.
Okay. My follow-up, and maybe this is for Mark, perhaps and welcome, Mark. It's good to hear on the call. It might not be actually, but I'll see you as one of you guys wants to answer this. It's really more about operational availability. I think Kevin mentioned that you're back early April. I think -- I'm not sure about the reference in refining of the referencing everything. So after the furthering last year, obviously, the downtime and then you had the storm, what should we think about the mechanical availability of your system, both refining and chemicals? And I'll leave it there.
I can comment on Chemicals. I think Chemicals is back, excluding normal turnaround activity. They're back. They're available and the plan is to run them basically at full capability.
And we guided to 95% O&P utilization for the quarter. So pretty much normal, normal operations.
And on the refining side, we -- first part of -- our first quarter was actually fairly heavy turnaround quarter for us. Some of that carries in here to the first month of the second quarter. But we got a couple of FCCs we're finishing up as we speak. And we'll really be out of turnaround mode here in the next week to 10 days. And that we've kind of got core sailing for the rest of the second quarter and into the third quarter for the gasoline season.
So we feel really good about coming out of the first quarter with all of our kit in shape ready to run. And as we expect gasoline demand to kind of roll back here in the summer season, we're ready to run.
Your next question comes from the line of Phil Gresh with JPMorgan.
One follow-up question on refining, recognizing there are so many onetime factors in the first quarter. Your utilization, you said was mid-80s here in the second quarter, which sounds pretty similar to your peers. One of your peers commented that they -- in March, they are run rating at a positive operating income.
And I recognize the effects of the storms is the longer dated for Phillips, but would you say that April or as we move into May, that you feel comfortable that you're also able to achieve that type of level of profitability?
Yes. I think in April, we still had a long turnaround activity going on within the refining system, right? And it was mostly FCC and Alky works that depresses our market capture and our clean product yields were still a heavy burden. As I said, we're coming out of that now. As the market continues to improve, our capture rates will improve. I think we'll see some better crude diffs this quarter, so that should help our market capture.
And it's all about kind of where that market moves to. But we're feeling a lot better here as we head into the month of May, then obviously, we were in the first quarter.
Phil, I think to -- I mean a lot of our peers report refining and marketing together. If you kind of add both of those together, I think we feel pretty good.
Okay. Yes. No, fair enough, and you also expense your turnaround. So on the chemical side, I mean, I guess, if you look at the first quarter, is there a way to isolate the onetime impacts? The reason I ask is because -- I mean, the $0.45 full chain margin were kind of actually running above that now. So I'm trying to get a better sense of for your profitability there to land in the second quarter.
Considering you've said many times, Greg, that $0.25 full chain margin, your annualized EBITDA, would be $2 billion, which would be $500 million quarterly. So any color on the first quarter or how you think about the second quarter would be really helpful.
Yes. Phil, it's Kevin. There was a significant impact from downtime. So the lost production impact in the first quarter. And we're not going to quantify that and give that number out. But I think what's fair to say is you look at where the margin environment is today and the projections through the rest of the quarter where operations are. I think -- and we touched on this earlier in the discussion.
I think we feel pretty comfortable saying we'd expect to see that above mid-cycle EBITDA contribution in the second quarter. And hopefully, some of that sustained into the second half of the year, although you'd normally expect some falloff in margins towards the end of the year. So we feel pretty optimistic that we should have a strong second quarter in chemicals.
Your next question comes from the line of Paul Cheng with Scotiabank.
Kevin, just curious that you talk about near term, you're trying to get the debt back to the pre-pandemic level around $12 billion. And then you will start looking at alternative or that incremental cash return to shareholder or kind of flexibility.
And the question is that is $12 billion is really the right number? Given the unpredictable nature of the refining market and all that, should we even target a much lower bad debt for the company. So that's the first question. Now that doesn't mean that you should not, at the same time, to maybe that increase the shareholder return. But is that one or the other or that we can concurrently to have continue a portion of the free cash flow being drive down the debt or put on the balance sheet until the balance sheet will be a much lower debt level. So that's the first question.
The second question is I think this is for maybe Bob and for RIN brand, 50%, that seems really low, given how big is your total network in the U.S. So are we missing something here that because one we thought given that Phillips 66 today is a combination of Phillips and Chronical both that have a pretty large wholesale network and all those contracts historically that will allow you to capture the win. So one we thought that you will brand far more than 50%. So are we missing something here?
Kevin?
Okay. Paul, let me talk to the first question. So you're right that I'd say $12 billion or thereabouts is a sort of near-term objective. That's where we were pre-pandemic, and we'd like to be back on the pathway to that. I would say that on a -- as we get to that level, I think there's a -- we're continually evaluating what our optimal capital structure looks like.
And depending on the state of the business, the growth opportunities, other capital allocation sort of priorities, we will optimize in whatever direction makes sense. But I'd also say that while there's -- when you come through a period of extreme volatility and depressed margins like we saw in 2020, that may lead you to conclude that maybe we should just permanently run at a lower debt level. I'd also say that there is -- the business is growing.
And as you expect, the underlying cash generation to increase, you're effectively delevering, right, on a sort of debt-to-EBITDA basis as you execute on those growth programs. And so I don't know that I'd get to a point of saying we need to have an ongoing debt level or an ongoing debt reduction objective. I think we want to get back to that sort of $12 billion level or thereabouts. And the main priority is to maintain that strong investment-grade credit rating.
Yes. When you look at the cost of debt, I mean you're driven really to have an efficient capital structure in your company. And I think that probably lands us around that $12 billion. So we want to be on a glide slope to that. It's not an absolute target that we're trying to hit here before we get back to increasing our dividend or looking at share repurchases.
I do think that the gating decision for us is really mid-cycle cash book. We want to get back to $6 billion to $7 billion of mid-cycle cash flow, and that creates the optionality for us certainly to invest $1 billion in our sustaining capital to fund our dividend, $1.6 billion and grow that dividend. And then that leaves us with a lot of optionality, Paul, that further paying down debt or investing more in the company.
And we're still comfortable with the guidance around the 60-40 guidance that we've given over the last few years. And so we still think that, that's good guidance going forward for our company.
Paul, on the blending RINs question, it is true that we have a large marketing business, both here and overseas in Europe. We also have a large fixed based operator business, about 900 of those in the U.S. So if you pull out the fixed-based operations business, if you pull out the stores in Europe and you look at how much we blend, and don't forget we have 11 refineries in the U.S., so we produce a lot of gasoline.
So generally, we run through our stores about a little over 50% to 60% in normal times of the gasoline we produce in our refineries, we went through our stores. So those -- that's the gasoline that we blend and create those RINs.
Your next question comes from the line of Theresa Chen with Barclays.
Maybe switching gears a bit to your renewable fuels initiative Can you give us an update on your renewable diesel strategy from here? Have there been any early learnings from the recent hydrotreater conversion at Verde? And at this point, what are -- where are you on the permitting for the full conversion? What are the other key puts and takes in moving that project forward?
Theresa, it's Bob. So on unit 250, we started it up here early in April after turnaround to convert the unit to run soybean oil, and so we're running the clean soybean oil out there. And unit came up first time and has run well. There's some learnings around how to run the unit and it's a very actually different process. Even though it's the same kit that we had before we shut down that was processing diesel. It's very different for the operators to operate.
It's actually really good for us. It's a learning curve around some of the products -- how to handle the product coming off the unit and everything before we get to the big projects. So we'll continue to ramp that unit up into the third quarter here as some of the logistics to feed the unit to get some of those projects get finished. And we're able to get to the 9,000 barrels a day of input out there of the soybean oil.
So we've also been able to test our logistics supply chain to bring the soybean oil to Rodeo and that's all worked out really well. And that's key for us as we start learning how to feed a much bigger machine in early '24. Permitting process in California is progressing. It's a very rote process to work our way through the environmental impact statement. And we have a full-time team working with a full-time team at Contra Costa County, which is the permitting authority.
We would expect sometime in the third quarter to have a draft environmental impact statement out there and available, and then you go into the public comment period and you kind of work yourself into early next year as the opportunity for that permit to be issued to us and which really then in California, you need permit in hand to do much on-site construction work.
So in the meantime, we continue to work the final engineering details for all parts of the unit and for the part of the system for the cleanup, the pretreatment unit, all that is ongoing. So we feel really good about our timeline and where we're on. We continue to optimize our schedule and look for opportunities to pull construction forward and get the unit up and running as soon as possible.
Got it. And then on the sustainable aviation fuel front, can you talk about your MoU with Southwest? How that came about? And what kind of economics would this potentially entail? Would it significantly alter the CapEx or scope of the Rodeo project?
And with the project as it stands, what percentage of that 800 million gallons do you envision would be dedicated to renewable diesel production versus sustainable aviation fuel, renewable naphtha and such?
So hi, Theresa, this is Brian Mandell. Just to start off with, this is a MoU and agreement with Southwest Airlines. In terms of jets into and out of California and just domestically in California, they're the largest airline. So we have an opportunity to work with them, both on public and policymaking, kind of educate policymakers in the public an opportunity to work on R&D with Southwest Airlines.
You may know that we have energy, research and innovation group. I think we're the only one of our peers that have that where we work on lots of different things, including solid oxide fuel cells, battery technology, solar, we want to also work on sustainable aviation fuel and development of that fuel. And then think about improving the economics. Right now, if you look at the economics of sustainable aviation fuel versus renewable diesel, renewable diesel makes more sense to produce.
So we need to think about the economics that can come from thinking about how to make it. It can come from the credits, it could come from the price of the fuel. So we have to think through all of that. And then finally, we're exploring whether we want to have a supply agreement with Southwest Airlines, whether that makes sense. And at the plant, we can produce up to 10,000 barrels a day, that will take some capital. We can produce some without any capital going forward. So we're taking a look at whether we want to spend capital, how much we want to make and how it competes with renewable diesel?
Yes. As the project is going through its design phase today as is, it will make about 10% sustainable aviation fuel without doing anything. So beyond that, we've got a couple of options you can add a little more kit. You can work on catalyst reformulations. But Brian makes a really good point, to get there, there needs to be a pathway all the way to the jet and need to be a price signal to pull it out of the distillate pool and into the sustainable aviation pool.
And just to add to that. If you think about the credits on LCFS credit, if you go the LCFS credit for sustainable aviation fuel but it's predicated on a lower CI. You get RINs, but the multiplier is 1.6 instead of 1.7 on renewable diesel and you get biodiesel tax credit as well. The other thing is when you make SAF, you also make some renewable naphtha and the economics for renewable naphtha are lower. So you have to deal with lower economics associated with naphtha and also the segregation and blending of that naphtha.
Your next question comes from the line of Manav Gupta with Crédit Suisse.
Just wanted to quickly focus on the feedstock deal that you signed. Again, congrats on getting the feedstock, but my assumption here is this cannot be a majority portion of the feedstock because this is a high CI feedstock and the plant that is coming up was designed for a lower CI feedstock. So what percentage of the feedstock have you actually been able to secure with this contract?
Manav, this is Brian. So when we think about the plants and ultimately coming up from 24,000 and the 50,000 barrels that we'll need. For the first 8,000 barrels, we will need soybean. For the rest of the plant, we will need any form of feedstock. So the plant is predicated on mostly low CI feedstock, we'll be buying used cooking oil, fats, but we'll also be buying some vegetable oils, some higher, some lower feedstock.
And our LP model will kind of dictate to us which feedstock to buy. And it's not just the CI of the feedstock, it's also the transportation, the location, and the cost of the feedstock is the different feedstocks will change in price. It's a benefit of having a hydrotreater in front of the plant where you can kind of run different feedstocks. So our goal, too, is to buy, just like we do in our -- in the crude and the gasoline and diesel market, our commercial group buys much more than we need.
As an example, in the crude market, we buy twice as much crude as the refineries need And that allows us to optimize the crude. So at any given time, we could think about each refinery and what could we have available and what could optimize at that refinery at that time. And we plan to do the same thing in the feedstock business.
So we've been in the feedstock business for a while now. It -- in Humber, we've been buying used cooking oil now for almost 4 years, and we've set up our commercial organization to do just that. We have business. We have an office in China, an office in Singapore, one in London and one here in Houston. We have tanks for used cooking oil. In Asia, we have tanks in Europe. And we're moving use cooking all around the world, optimizing that business, and we'll do the same with the other feedstocks as time goes on.
And don't forget, we're also responsible to supplying feedstock for the right facilities. That's a 10,000 barrels a day, the feed were responsible for procuring.
Okay. A quick follow-up here is, I think last quarter, I think Jeff went on and explained, which are the areas where the demand is recovering at the fastest pace. So if you could help us understand where -- I mean international jet will remain weak. But other than that in your system, if you go pad wise, where do you think you have achieved full recovery? And like which are the areas which we can expect would recover in the next 3 to 6 months?
Manav, I'll take that one. If you take a look at demand for us, On the diesel side, we're back to 2019 levels. On the gasoline side, in the U.S., we're about 5% off. We're further off on diesel and gasoline in Europe where we have business in Germany, about 20% off because they're still on the lockdowns and Austria about 15% off. They're coming out of lockdowns in May 18. So we see some sunlight. And then in Switzerland, they're off about 10%. They're open now. I think the U.S. is doing really, really well. If you look at COVID vaccines, 43% of the population has gotten at least one dose, more than 80% of the population over 65 has gotten one dose.
So we can see a lot of sunlight. Our view going forward is that we expect given the strength of the economy, we've seen lots of containerships. The CDC just said that cruise ships can start up in July. We're seeing a lot of strength in the economy. We think diesel will be up about 2%. We think ultimately, gasoline is going to be up about that same amount as people start getting out of the house coming back to work. Jet, we think jets down about 25% here in the U.S. We think that will be about 15% as the year goes on. That 15% represents mostly international travel where people are still needing the quarantine, and we think that we don't want travel as much. But if you think about the gasoline and diesel up 2%, roughly and jet down 15%, that whole net-net, that means that we'll be at 2019 levels in the back half of 2021.
And then on top of that, if you think about the refining capacity, we've shut down over 1 million barrels of refinery capacity since 2019. So we'll be back up to demand levels of 2019 with at least 1 million barrels of refining capacity in the U.S. shut down. So we -- that makes us think -- we're very bullish in the second half of this year for that reason.
I think I might just add, when you look at gasoline demand, we are seeing trips to the grocery store, recreational activity has gone back to slightly above pre-COVID levels. And so there's strong demand there. We're seeing a movement out of some of the big cities into suburban areas where people drive more, consume more gasoline.
So I think there are positives and negatives, but I think the other thing is, as you look to the summer, hotel reservations are up. It looks like it's going to be a robust travel season for the summer.
Your next question comes from the line Matthew Blair with Tudor, Pickering, Holt.
I just had a follow-up on the renewable diesel conversation. Currently, I don't see an LCFS fuel pathway for Phillips. So I just wanted to clarify whether you will be capturing an LCFS credit on this initial 120 million gallons?
Yes, we will. So the way that works that is -- you have to come up and run and demonstrate your capability and where your feedstock is coming from. And they actually assign you kind of an average CI for the first 2 quarters of operations. So we will capture an LCFS and the difference between the statutory level and that assigns CI. And then as we run and we'll demonstrate that the actual feedstocks we're providing are a lower CI than the one assigned will ramp kind of into over the next two quarters, a larger LCFS benefit than we're getting today. So It's a process that's prescribed by CARB, and we don't have any choice but to fall. And so we're in the middle of that now since we're operating.
And that CI difference is around 9 or 10 CI points. So we expect after the first couple of quarters of running that machine that we'll get at CI about 9 or 10 points better than we're currently getting.
And so we'll capture, just to be clear, LCFS, RINs and BTC with these barrels.
Sounds good. And then as a follow-up, do you have an opinion on why LCFS credits have sold off over the past month? Do you think it's maybe like a seasonal issue around the annual compliance date? Or do you have concerns that the overall California LCFS market is becoming oversupplied.
No. We think it's utilization with utilization down, there's less demand. If you look at the forward curve, the -- it's a contango so the forward curve is higher. That makes sense because the obligation increases every year. So we would expect it to come back up as utilization rate rises in California.
California has announced opening up mid-June, which should support demand. We are seeing a correlation with the increase in vaccines and the increase in vehicle models traveled and demand for gasoline.
Your next action comes from the line Jason Gabelman with Cowen.
I'd like to go back to the RIM discussion because it seems like an important one. I'm just trying to understand the ability to, I guess, pass through the RIN cost to the consumer within your marketing business. And what I'm thinking is, does the kind of net ring cost of fill-ups go up during periods of weak demand like during COVID, just because it's more difficult to pass through the cost to the customer.
So is that kind of creating some volatility in understanding what your own exposure is? And then my second question is just a simple one. I was hoping if you could provide the OpEx impact to the refining business from Uri?
So Jason, we think that we passed the RIN to the customer. I think it's true that during times of low demand, our marketing margins suffer because we have to compete to sell our barrels. But in terms of the RIN, we think the RIN gets passed to the consumer ultimately.
Second -- your second question was around cost to the refining system from storm Uri. So we saw first significant fuel gas costs, electricity costs across our system. There wasn't just the 4 plants that were heavily affected in the kind of in the Mid-Con and the U.S. Gulf Coast, but because of just the way gas pricing works, right, we saw we saw FX kind of across our system.
So if you look at the impact to us in kind of our total operations in there, right, we're up in that kind of $175 million, $200 million range for increased utility costs and a little bit of cost increase to fix broken pipes and things. We really didn't have that much damage, most of that we saw in the utility sector.
We have reached the end of today's call. I will now turn the call back over to Jeff.
All right. Thank you very much for your time and for your interest in Phillips 66. Please contact me and/or Shannon with any follow-up questions, we're happy to help.
Thank you. Ladies and gentlemen, this concludes today's conference. You may now disconnect.