Phillips 66
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Phillips 66
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Good morning. And welcome to the Fourth Quarter 2021 Phillips 66 Earnings Conference Call. My name is Sia, and I will 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.
Good morning. And welcome to Phillips 66 fourth 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 two 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 will turn the call over to Greg.
Okay, Jeff. Thank you. Hey. Good morning, everyone, and thanks for joining the call today. In the fourth quarter, we had adjusted earnings of $1.3 billion or $2.94 per share. For the year, adjusted earnings were $2.5 billion or $5.70 per share.
We delivered record results in Midstream, Chemicals, and Marketing and Specialties, demonstrating the strength of our diversified portfolio. For the third quarter in a row, we saw improved Refining performance. Looking ahead, we are optimistic about the outlook for our business.
In 2021, our employees exemplified the company’s values of safety, honor and commitment. Our 2021 combined workforce total recordable rate of 0.12 was more than 25 times better than U.S. manufacturing average. Last year, our strong cash flow generation allowed us to invest $1.9 billion back into the business, returned $1.6 billion to shareholders and pay down $1.5 billion of debt.
The 2022 capital program of $1.9 billion reflects our commitment to capital discipline. Approximately 45% of our growth capital this year will support lower carbon opportunities, including Rodeo Renewed.
As cash flow improves further, we will prioritize shareholder returns and debt repayment. In October, we increase the quarterly dividend to $0.92 per share. We remain committed to a secure, competitive and growing dividend. We would like to resume share repurchases this year and on our path towards getting back to pre-COVID debt levels over the next couple of years.
We are taking steps to position Phillips 66 for the long-term competitiveness. Across our businesses we are assessing opportunities for permanent cost reactions. Mark and Kevin are leading this initiative, and we will provide additional details on the first quarter call in April.
We are committed to a lower carbon future, while continuing to deliver our vision of providing energy and improving lives around the globe. We announced targets to reduce greenhouse gas emissions intensity last year. By 2030, we plan to reduce Scope 1 and Scope 2 emissions by 30%, and Scope 3 emissions by 15% compared to 2019 levels.
So, with that, I will turn the call over to Mark to provide some more details.
Thanks, Greg. Good morning, everyone. In the fourth quarter, we had strong earnings from Midstream, Chemicals and Marketing and Specialties, and we saw continued recovery in Refining profitability. We made progress advancing our growth projects, as well as taking strategic actions to position Phillips 66 for the future.
In Midstream, we began commercial operations of Phillips 66 Partners, C2G Pipeline at the Sweeny Hub construction of Frac 4 is 50% complete and we expect to begin operations in the fourth quarter of this year.
CPChem is investing in a portfolio of high return projects growing its asset base, as well as optimizing its existing operations. This includes growing its normal alpha olefins business with a second world-scale unit to produce 1-hexene, a critical component in high-performance polyethylene. CPChem is also expanding its propylene splitting capacity by 1 billion pounds per year with a new unit located at its Cedar Bayou facility, both projects are expected to start up in 2023.
CPChem continues to develop two world-scale petrochemical facilities on the U.S. Gulf Coast and in Ras Laffan, Qatar. In addition, CPChem completed its first commercial sales of Marlex Anew Circular Polyethylene, which uses advanced recycling technology to convert difficult to recycle plastic waste into high quality raw materials. CPChem successfully processed pyrolysis oil in a certified commercial-scale trial and is targeting annual production of 1 billion pounds of circular polyethylene by 2030.
During the year, we began renewable diesel production at the San Francisco Refinery and continued to progress Rodeo Renewed, which is expected to be completed in early 2024 subject to permitting and approvals. Upon completion, Rodeo will initially have over 50,000 barrels per day of renewable fuel production capacity. The conversion will reduce emissions from the facility and produce lower carbon transportation fuels.
In Marketing, we acquired a commercial fleet fueling business in California providing further placement opportunities for Rodeo renewable diesel production to end-use customers. Additionally, our retail marketing joint venture in the Central region acquired 85 sites in December, bringing the total to approximately 200 sites acquired in 2021. These sites support long-term product placement and extend our participation in the retail value chain.
Our Emerging Energy Group is advancing opportunities in renewable fuels, batteries, carbon capture and hydrogen. We recently signed a technical development agreement with NOVONIX to accelerate the development of next-generation materials for the U.S. battery supply chain. We own a 16% stake in the company, extending our presence in the battery value chain. In December, we entered into a multiyear agreement with British Airways to supply sustainable aviation fuel produced by our Humber Refining -- Refinery beginning this year.
For 2022, we will execute our strategy with a focus on operating excellence and cost management. We will do our part to advance the lower carbon future, while maintaining discipline capital allocation and an emphasis on returns.
Now, I will turn the call over to Kevin to review the financial results.
Thank you, Mark, and hello, everyone. Starting with an overview on slide four, we summarize our financial results for the year. Adjusted earnings were $2.5 billion or $5.70 per share. We generated $6 billion of operating cash flow or $3.9 billion excluding working capital. These results reflect our highest annual earnings for the Midstream, Chemicals, and Marketing and Specialties segments.
Cash distributions from equity affiliates totaled $3 billion, including a record $1.6 billion from CPChem. We ended 2021 with a net debt to capital ratio of 34%. Our adjusted after-tax return on capital employed for the year was 9%.
Slide five shows the change in cash during the year. We started the year with $2.5 billion in cash. Cash from operations was $6 billion. This included a working capital benefit of $2.1 billion, mainly due to the receipt of tax refunds, as well as the impact of rising prices on our net payable position. During the year, we paid down $1.5 billion of debt.
In November, both S&P and Moody’s revised their outlooks from negative to stable. We are committed to further deleveraging as we continue to prioritize our strong investment grade credit ratings. We funded $1.9 billion of capital spending and returned $1.6 billion to shareholders through dividends. Our ending cash balance increased to $3.1 billion.
Slide six summarizes our fourth quarter results. Adjusted earnings were $1.3 billion or $2.94 per share. We generated operating cash flow of $1.8 billion, including a working capital benefit of $412 million and cash distributions from equity affiliates of $757 million.
Capital spending for the quarter was $597 million, $265 million was for growth projects, which included approximately $100 million for retail investments in the Marketing business. We paid $403 million in dividends.
Moving to slide seven, this slide highlights the change in adjusted results from the third quarter to the fourth quarter, a decrease of $105 million. Our adjusted effective income tax rate was 20% for the fourth quarter.
Slide eight shows our Midstream results. Fourth quarter adjusted pretax income was $668 million, an increase of $26 million from the previous quarter. Transportation contributed adjusted pretax income of $273 million, up $19 million from the prior quarter. The increase mainly reflects the recognition of deferred revenue.
NGL and other adjusted pretax income was $284 million, compared with $357 million in the third quarter. The decrease was primarily due to lower unrealized investment gains related to NOVONIX, partially offset by higher volumes at Sweeny Hub and favorable inventory impacts.
Our investment in NOVONIX is mark-to-market at the end of each reporting period. The total value of the investment, including foreign exchange impacts increased $146 million in the fourth quarter, compared to an increase of $224 million in the third quarter. The fractionators at the Sweeny Hub averaged a record 417,000 barrels per day and the Freeport LPG export facility loaded a record 45 cargoes in the fourth quarter.
DCP Midstream adjusted pretax income of $111 million, was up $80 million from the previous quarter, mainly due to favorable hedging impacts in the fourth quarter, compared to negative hedge results in the third quarter. The actual hedge benefit recognized in the fourth quarter amounted to approximately $50 million.
Turning to Chemicals on slide nine. Chemicals fourth quarter adjusted pretax income of $424 million was down $210 million from the third quarter. Olefins and Polyolefins adjusted pretax income was $405 million. The $208 million decrease from the previous quarter was primarily due to lower polyethylene margins, reduced sales volumes, as well as increased utility costs.
Global O&P utilization was 97% for the quarter. Adjusted pretax income for SA&S was $37 million, compared with $36 million in the third quarter. During the fourth quarter, we received $479 million in cash distributions from CPChem.
Turning to Refining on slide 10. Refining fourth quarter adjusted pretax income was $404 million, an improvement of $220 million from the third quarter, driven by higher realized margins and improved volumes. This was partially offset by higher costs.
Realized margins for the quarter increased by 35% to $11.60 per barrel. Impacts from lower market crack spreads were more than offset by lower RIN costs from a reduction in our estimated 2021 compliance year obligation and lower RIN prices. In addition, we had favorable inventory impacts and improved clean product differrentials.
Refining adjusted results reflect approximately $230 million related to the EPA’s proposed reduction of the RVO, of which about 75% applies to the first three quarters of the year. Pretax turnaround costs were $106 million, up from $81 million in the prior quarter. Crude utilization was 90% in the fourth quarter and clean product yield was 86%.
Slide 11 covers market capture. The 3:2:1 market crack for the fourth quarter was $17.93 per barrel, compared to $19.44 per barrel in the third quarter. Realized margin was $11.60 per barrel and resulted in an overall market capture of 65%.
Market capture in the previous quarter was 44%. Market capture is impacted by the configuration of our refineries. Our refineries are more heavily weighted toward distillate production and the market indicator.
During the quarter, the distillate crack increased $3.10 per barrel and the gasoline crack decreased $3.76 per barrel. Losses from secondary products of $1.88 per barrel improved $0.10 per barrel from the previous quarter, due to increased butane blending into gasoline.
Our feedstock advantage of $0.18 per barrel improved by $0.17 per barrel from the prior quarter. The other category reduced realized margins by $2.02 per barrel. This category includes RINs, freight costs, clean product realizations and inventory impacts.
Moving to Marketing and Specialties on slide 12. Adjusted fourth quarter pretax income was $499 million, compared with $547 million in the prior quarter. Marketing and other decreased $52 million from the prior quarter. This was primarily due to lower marketing fuel margins and volumes, as well as higher costs. Specialties generated fourth quarter adjusted pretax income of $97 million, up from $93 million in the prior quarter.
On slide 13, the Corporate and Other segment had adjusted pretax costs of $245 million, an increase of $15 million from the prior quarter. This was primarily due to higher employee-related costs and net interest expense.
Slide 14 shows the change in cash during the fourth quarter. We had another strong quarter for cash. This is the third consecutive quarter that our operating cash flow enabled us to return cash to shareholders, invest in the business, pay down debt, while increasing our cash balance.
This concludes my review of the financial and operating results. Next, I will 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 high-80s and pretax turnaround expenses to be between $120 million and $150 million. We anticipate first quarter Corporate and Other costs to come in between $230 million and $250 million pretax.
For 2022, we plan full year turnaround expenses to be between $800 million and $900 million pretax. We expect Corporate and Other costs to be in the range of $900 million to $950 million pretax for the year. We anticipate full year D&A of about $1.4 billion, and finally, we expect the effective income tax rate to be in the 20% to 25% range.
Now, we will open the line for questions.
Thank you. [Operator Instructions] Your first question will come from Neil Mehta with Goldman Sachs. Please go ahead.
Good morning, team. Greg, good morning. Greg and Kevin, first question for you on, how you are thinking about normalized cash flow. If I look at the back half of 2021, ex working capital, you put up almost $3 billion of cash flow, so annualized, close to $6 billion. I think a lot of us use $5 billion to $6 billion of sort of that normalized cash flow range. But Greg, you have been clear that you think it’s kind of closer to $6 billion to $7 billion. And so just your thoughts on whether that’s still how you are thinking about mid-cycle and the underlying buildup to that $6 billion to $7 billion, if you can kind of walk through the world of your different segments of how you get there would be great.
I will be happy to do that. I mean, I don’t think we really changed from our view of $6 billion to $7 billion. Of course, it’s nice to see $6 billion of cash last year. It just happened to occur in different buckets that you might expect from a traditional cycle.
So I think we have been signaling in the last couple of months. We are pretty constructive on the Refining business coming into 2022. And if you think about the rest of the businesses, they have actually performed at or better than mid-cycle all through the pandemic in 2020 and into 2021.
We remain pretty constructive on those businesses coming into 2022 at all. So really, for us, a wildcard has really been Refining and when has Refining recovered back to something approaching a mid-cycle.
But just to remember how it all builds up on an EBITDA basis kind of $4-ish billion in Refining, kind of $2 billion in Midstream, $2 billion in Chemicals and $1.5 billion, $1.6 billion in Marketing and Specialties, it pushes you to something like $9-ish billion of EBITDA, which translates to $6 billion to $7 billion of cash.
And so I think we are pretty comfortable that we are kind of still in that range. Obviously, we have had some outperformance. I mean, last year, all driven by great operations, fundamentally good control of their costs and then super margins.
Our Marketing and Specialties businesses, which we typically would say is, a $1.5 billion, $1.6 billion business was $2 billion. And of course, we have been investing in adding retail our joint ventures.
But I think it’s really great execution on the operations side, particularly in the U.S., but also in our European operations, where we saw good volumes, good margins across that and so I would say that we are probably on the upside of that.
So given $6 billion to $7 billion of cash flow, our first dollar is always going to go to sustaining capital, that’s $1 billion, dividend is $1.6 billion and then that leaves room for us. We can signal that the capital budget is going to be $2 billion or less, so we are $1.9 billion for this year.
That’s a deliberate signaling that for this year or next year, we are going to be very constrained on capital, that frees us up to pursue some debt repayment and get back to share repurchases, while doing a little bit of growth. And so I think we make that all balance as we think about that. Now Kevin or Jeff, if you want to add to that, please step in, I don’t…
No. I think you covered it all.
Okay.
Thanks, Greg. And that’s the logical follow-up for me, which is how you are thinking about share repurchases, again the focus has been to get the debt level lower. Looks like the ratings agencies are giving you the all clear at least that things are moving in the right direction. So what are the gating factors for you to begin a share repurchase program and how do you think about sizing it?
Well, we have always said the gating factor is getting cash flows back to something approaching a mid-cycle and making a dent in the debt repayment. So I think coming into April, we are going to pay another $1.5 billion-ish of debt off in April as it comes due.
So that’s $3 billion of the $4 billion. We have made a big dent in that. So I think that kind of post-April, that’s why I said that, I would be disappointed if by midyear, we are not back in a share repurchase mode at our company.
Perfect. Thanks, Greg.
Sure.
The next question will come from Phil Gresh with JPMorgan. Please go ahead.
Yes. Hello. My first question, just on one of the guidance items here on the Refining maintenance, $800 million to $900 million, just looking back, it looks like it’s the highest in the history of the company. And I was just curious, I mean, is there anything unique we should be thinking about there, I didn’t think 2020 or 2021 were too far below the historical norms? And then I guess bigger picture, when I think about your maintenance and what others have said, it seems like the industry might be kind of capped in terms of what utilization can be this year. So is this an environment where we are just going to see margins get pressured higher to keep up with demand?
So let me just take a high level and then I will let Bob come in and talk about it since it’s his business. But if you look 2012 through 2019, we kind of averaged about $5.25 billion in terms of total turnaround expense.
And there’s -- we did push some of 2020 and 2021 into 2022. I think probably a lot of the people did that in the industry as we were trying to conserve cash and protecting the balance sheet. So it’s a big number, Phil, there’s no question. But I will let Bob speak to the specifics and what we are doing there.
Yeah. I think, Greg, hit on it pretty good. The last couple of years were going to be lower turnaround years anyway with this 2022 always going to be a bit of a larger turnaround. We have got two refineries, both Ferndale and Billings, and when they take their turnaround their entire facility turnaround, they are coming, you see -- you kind of got to go back five years to find them in the cycle. So that causes a little bit of lumpiness in it.
And then, to your second question, I really -- we would agree that a lot of people managed their turnarounds and maintenance work out of 2020 and 2021. Some of that’s running the lower utilizations. We made our catalyst in hydro traders and hydrocrackers that last longer, so were able to stretch those runs.
We put a lot of work into making sure we could do it from a mechanical integrity standpoint. But now those things are coming due, right? You can’t do that forever, and for us this year, it’s a pretty heavy lift across the system. And I suspect we are not the only ones that are going to see that.
Okay. Great. Thanks. Thanks for that color. Just one more on the Refining business, Needle Coke is a unique business to Phillips 66 versus the other refiners. I was curious it’s a bit of an opaque market, but could you talk about what you are seeing in the fundamentals of that business, kind of how it finished out 2021 and how you see it progressing in 2022 and beyond? Thanks.
Sure. So, as you may know, Needle Coke is used to make graphite electrodes, which internally is used production of steel, electric arc furnaces, which are actually a cleaner technology than blast furnaces and we use Needle Coke also to make anodes for lithium-ion batteries.
The past two years, we have seen a weaker Needle Coke market with steel producers running off high inventories. But we do see some slow strengthening last this -- end of this year, last year and this year as well.
If you listen to steel production, which is a leading indicator, they had a record year last year, even as Needle Coke markets lagged, because of the high inventories. The market seems to have mixed opinions about steel production this year. Some steel producers think it will continue to increase, some think it will come off.
Either way, we have seen good demand from both steel producers and anode producers, and we expect that market to continue to gradually increase. We think with the refinery utilization coming back up and lower graphite electrodes that it will be a slightly strengthening market.
Great. Thank you.
The next question will come from Roger Read with Wells Fargo. Please go ahead.
Yeah. Thank you and good morning.
Good morning, Roger.
Hi, Roger.
Good morning. I’d like to start off kind of on your comments about the -- getting back to share repos. Maybe what are some of the markers you would want to see and kind of tagging on with Phil’s question about maybe a little higher spending on the turnaround side? Is there a timing issue with those turnarounds where you would want to get past a certain level or is it bigger picture on the balance sheet for and overall cash flows when you will feel comfortable?
Yeah. Well, I think, we are kind of back to the question on Refining and when does Refining get to mid-cycle cracks? I mean, in 4Q, we are 11.60 realized cracks. So, I mean, that’s the highest quarterly crack that we have seen in Refining since the fourth quarter of 2018.
So there are some things that are in that number, obviously. But as we look coming into 2022, where constructive supply and demand, there’s been a lot of supply that’s come off the market, we think there’s new supply coming on, but it’s going to be staged. It’s not all going to hit when people think it’s going to hit because it always takes longer to come on.
So from that standpoint, we are constructive on the demand side. What we see with each successive wave of COVID, the impacts to demand are less and less, and so I am not sure when that moment in time as we transition from pandemic to endemic, but that could happen next year.
But regardless, we see the demand impacts less and less from each successive wave of COVID. Prior to the current variant, we were seeing gasoline demand kind of back at 2019 levels. There’s disciplined demand above 2019 levels. Jet was recovering nicely.
So as we move into 2022, we are constructive around the demand side. We talked about the turnaround activity and what impact that could have ultimately on utilizations and so we just see everything balancing out towards -- we get back towards more of a mid-cycle crack in Refining.
And so, once we get Refining there, I think, we feel pretty comfortable that we are going to have sufficient cash flow, cover our sustaining capital, our dividend, pay down some debt, get back share repurchases and fund the growth program that we have this year, which is about $900 million in growth. Kevin, if you want to add anything to that.
No. I think that’s very complete. Just in terms of the debt pay down detail, we have a $450 million term loan maturity in April. We have $1 billion notes maturing in April and we intend to take care of both of those at maturity, and then what happens after that, we just have flexibility. We still have other callable debt available if we need to. But we will -- with that taken care of and if cash flows back at mid-cycle levels, we would have a lot of flexibility.
I think we paid $3 billion of the $4 billion that we borrowed during 2020 down. I think that demonstrates our commitment to paying down debt and returning the balance sheet over a couple of year period to something that resembles kind of pre-COVID levels, let’s say, $12 billion on a consolidated basis. So, I think, we are pretty comfortable in that construct, Roger.
Okay. Appreciate it. Other question I had sort of the unrelated follow-up. As you look at setting everything up on the renewable diesel side, any progress or increased comfort level in terms of the feedstock side of that, I mean, that seems to be one of the biggest questions we get coming in is, what is our comfort level that each of the companies will be able to supply what you need to maintain a healthy margin in that business and the returns that you are targeting?
Hey, Roger. It’s Brian. We don’t see any issue with the feedstock availability. Although, it may be challenging for those that maybe are less commercial, have less logistics experience. We think between increased acreage and yield, switching from biodiesel, better aggregation of used cooking oil, we will have plenty of feedstock to produce renewable diesel.
Prices may vary over time and that’s to be expected. At Rodeo, we are on the water so we have access to both domestic and foreign feedstock. And we also sit on the U.S.’ greatest demand center in California. So feel good there.
Our commercial organization has been working on feedstock for quite a while. We have offices around the world. We have storage in Asia and Europe and in U.S. We have good relationships with vegetable oil producers. You heard our announcement in our investment in Shell Rock Soy processing.
We purchased for the startup of Rodeo. We purchased soybean oil, canola oil, distilled corn oil since last April. We have strong relationships with producers and aggregators of used cooking oil. In fact, with used cooking oil, we have been in that market for over four years supplying Humber used cooking oil from around the world, currently 12 different countries.
So I think Rodeo Renewed will have a maximum optionality in its system and then we will use a linear program to decide what the best and most cost effective feedstock is based on not just CI, but price, credit generation to the sales market and logistics.
It sounds like its open for an MLP there. All right. Thank you.
The next question will come from Ryan Todd with Piper Sandler. Please go ahead.
Hi. Thanks. Maybe one on European Refining, as a refiner with some exposure to European refining, can you talk about the impact of high nat gas prices that you are seeing on Refining economics over there and in a broader sense in that part of the world. Do you expect high nat gas prices to impact European utilization rates to the benefit of U.S. refiners this year?
Yeah. This is Bob. I think that’s absolutely right. We look at what goes on in our operations and we have got a very complex and strong refinery over there in the impact of high natural gas prices on us and then we translate that to some of the simpler refineries in Central Europe. It’s got to be really tough for them to be making money right now and I am sure we are going to see that.
We know that clean product yield out of a bunch of those refineries is down, because they are not buying hydrogen or buying natural gas to make hydrogen to hydrotreat, because we see the high sulfur stuff showing up in the market, which is somewhat good for us. It’s putting pressure on the sour crudes, which will be good for us in the long-term. So I think high natural gas prices are going to continue for a while in Europe and it is really going to strain kind of that bottom quartile of refiners that are left.
As Bob pointed out, if the Europeans are running more sweet crude, it kind of widens that sour sweet dip, which is beneficial to us. The utilization comes off on those refineries because they can’t afford to run. That’s good for the U.S. as well, because we will be able to export products to Europe. So it would be good for our businesses as well.
Great. Thanks. And then maybe a follow-up on the last question before this, I mean, you now have a couple of quarters under your belt producing renewables you saw there in California at a pretty decent level. I mean, can you talk about what you have learned from your operations, both in product placement, as well as feedstock acquisition there, as you think about preparation for the -- for kind of the full project completion later on? And then as we have seen feedstock spreads narrow in the back half of year and headline, how about spreads has [ph] improved. Any comment on what you have seen in the profitability of your production there?
Well, the profitability between Q3 and Q4 has strengthened. There’s a lot of things to think about when you are thinking about the renewable diesel margins, you have to think about feedstock, the renewable diesel price, the credits. You have to think about logistics. So there’s a lot of pieces to it. We will have a linear program for renewables as well.
The key to renewable production is finding as many feedstocks, as many suppliers as you can and having the logistics to get it to the plant, which is what we have been working on. We have set up a global organization to do that and we are working hard.
In renewable diesel, the key for us is getting the renewable diesel to the end-user. That’s the key to keep more of the margin that way. So in part, our purchase of our commercial fleet fueling business was enabled that to -- for us to get some of that product to end users. You will continue to see those type of things.
We have taken all the stores in California that we have, and we have converted those renewable diesel as well. So we are going to have much renewable diesel as we can to the end-user and we are going to have as bigger feedstock slate as we can for the plant and we will optimize through our linear program.
I might add to that that being able to operate 250 out there on renewable feedstocks instead of hydrocarbon-based feedstocks has really given us a good opportunity to -- for the operators and staff to learn, because it is very different and it runs different than there are different characteristics to handling it and getting it in the unit and dealing with it.
So it’s been a great warm-up for us for the Rodeo Renewed project that’s yet to come and just, I think, raises our confidence level and our ability to be able to run really hard right out of the gate with that unit.
You want to talk about the pathways, the CI approval, et cetera?
Yeah. So we started up the unit after the last turnaround on basically clean soybean oil. And since, and Brian mentioned it earlier, we have been able to establish pathways. So in California, you run new feedstocks, you get provisional CI number for them and then you have to go through, I’d say, a pretty lengthy bureaucratic process to qualify your other feedstock.
So since we have done that, we have been able to qualify not only the soybean oil, but the distillers corn oil, we are working on. We have gotten a pathway on canola oil. I think that’s yet -- that process will keep repeating itself as we find more and more feedstocks ahead of Rodeo Renewed coming up in 2024 or early 2024, that really allow us to take advantage of the lower CI material right away.
I guess, just another key learning is how you get through that process and navigate that process in California.
Like everything else, you get better at it the second time.
Right.
Perfect. Thanks, guys.
The next question will come from Doug Leggate with Bank of America. Please go ahead.
Thanks, guys. I have got two questions that I hope can add some color for everybody. I guess my first one, Kevin, is on the balance sheet. I was looking back at your share price, it seems like a horrible memory now. But your share price pretty much got cut in half twice last and during the 2020 period, and obviously, you did not buy back stock when that happened, given the circumstances. So my question is why carry $10 billion of net debt rather than work the balance sheet down to a level where we know these corrections are going to happen occasionally in this business to allow you to take advantage of that? What’s the philosophy behind the buybacks in the recovery versus building the balance sheet during the recovery and buying back during corrections?
Yeah. Doug, I think, it’s really a -- it is a bit of a balancing, trying to meet multiple priorities. So we think about an optimum capital structure in terms of cost of capital, right? So too little debt is increasing cost of capital and so you have got that component to it. We have got other opportunities that we want to be able to fund.
And bear in mind also that, as we are growing the business and we are seeing that in the non-Refining segments, as we are growing the business, we are actually, we are effectively strengthening our overall financial condition, because on a debt-to-EBITDA basis, we are continuing to improve from that standpoint.
And obviously, we don’t like the fact that we weren’t buying shares at $40, but that was -- we were not in a position to do so and so we had to just accept that. And so it’s really around finding that optimum capital structure that will give us sufficient flexibility through the cycle, albeit you have always got more flexibility. The lower the debt balance, obviously, that provides added flexibility.
But at what cost is that? And so it’s having the optimum structure to where we have got adequate flexibility. We can be -- stick with our sort of capital allocation framework, so 60% reinvestment in the business, 40% cash returns to shareholders between the dividend and buybacks over an extended time period, recognizing that year-over-year that will fluctuate.
So it’s really just trying to balance through all of that. I am not sure going too much further down on debt than our sort of stated objectives, is going to bias a whole lot in that context. So I still feel pretty good with how we are laying out our objectives.
I appreciate the answer. I guess, it’s more of a net debt question, because obviously, its 2020 hindsight is perfect, but it kind of gets back to this. I wonder if COVID has reset everybody’s view of what volatility looks like. So, but I appreciate the answer. My follow-up is, something I really value from you guys periodically is your view on the net capacity outlook. And I guess, my question is, are we getting to a point now where the mid-cycle Refining outlook has been reset higher, much like it did in the mid-2000s? I don’t want to say golden age, but something of that nature. And here’s my point, gas prices are up, that’s probably structural for international players, net additions disclosures like demand with IMO. I am just wondering, are you guys thinking along those lines? How do you see the net additions, price additions and subtractions in terms of impacting that mid-cycle view?
Yeah. Doug, I think, we have seen a total of about 4.5 million barrels a day of Refining rationalization that’s been announced and much of that has already occurred. When you look at last year, it was the first year in at least 30 years where there was more capacity rationalized out of the global fleet than there was capacity added and so we are seeing that benefit. As we look forward, there’s still pressure with higher natural gas prices in Europe on that -- those unit’s profitability. So we see that continuing to occur.
We have also seen COVID delays, challenges getting labor into execute new capacity additions, so they are getting spread out. We have seen a reduction of capital spending and concerns over energy transition. So it’s definitely impacting the supply side of the equation and we are seeing demand come back.
As Greg mentioned, gasoline was above 2019 levels before this recent COVID hit, diesel comfortably above, jet’s been coming back aggressively and so we think jet demand by late this year could be back at 2019 levels as well. So the demand’s still in the system and the supply is more constrained than what we have seen historically.
The next question is from Theresa Chen with Barclays. Please go ahead.
Hi, there. Thanks for taking my question. First, Kevin, I just wanted to follow-up on your comment about the adjustments from the lower RVO for 2021 out of the Refining results. So just to be clear, the $404 million of adjusted EBT, did that include the $230 million?
Yes. It does, Theresa. So the $404 million includes the $230 million. It applies to the full year. And so if you think about my additional comment was, if you think about that in terms of the quarter, as you could say, three quarters of that $230 million would apply to the first three quarters of the year and if you are doing any kind of normalization around that.
Okay. So, that you presumably would not get that revaluation over and over again, so the clean number for the quarter would be $174 million?
If you -- yes. If you back out the full $230 million. Yeah.
Okay. Great. Thank you. And then, I also wanted to follow-up on one of Brian’s comments about the fuel fleet that you bought in California as you seek to place barrels to the end user for all of your renewable diesel production. Is this something that you expect to grow in terms of your footprint and the vertical integration as incremental renewable diesel will hit the state over time to insulate your position there or is it something that you were thinking of doing all along? I would love to understand your strategy more here.
Yeah. Theresa, that’s exactly right. Our goal is to be able, at some point, to get the entire 50,000 barrels of diesel that we make to the end-user. That may not be possible but we will see. We may export some of that depending on markets, but this is just one step.
As I said, we upgraded all the stores to renewable diesel. We are looking at a lot of different opportunities to also get diesel to the end-user. But the goal is to get it to the end-user that way. We keep all of the margin and we think that’s the best path.
Thank you so much.
The next question is from Manav Gupta with Credit Suisse. Please go ahead.
Hi guys. This is a question, which we get a lot of investors, so don’t shoot the messenger. Your partner has gone ahead and made a statement that they don’t really want to be in the business of JV Refining. You have a very profitable JV, which has worked very well for you over the years and that has resulted in a lot of speculation. If you keep one refinery they keep one, they sell you both, you sell them both. There are multiple scenarios there or just keep the status quo, if you could comment a little on that situation?
Take that Bob. Yeah, actually…
Yeah. And we are seeing. I -- all I can tell you is, we continue to work really well with our partner on our joint venture, WRB for Wood River and Border. As you pointed out, it’s been a very good partnership since 2007, stood the test of time.
They seem to like us as an operator. They have been a great partner to work with and give us good insights on things and their world has changed. But for now, we continue to work together to run WRB and invest in those two facilities as needed both of them.
Perfect. And my follow-up quick question is when you look at the segments here, the Gulf Coast operating cost was a little higher and so was the DD&A. I am assuming these are just like one-times and as the refinery closes, your op costs will actually trend down sequentially, not up and so for the DD&A. If you could just comment on that one-times, I mean, they look like one-times from the alliance on the Gulf Coast results?
Yeah. You are exactly right. There’s a lot of noise in 4Q and it is -- there are -- we still have all the people in the fourth quarter, because we worked through redeploying some and all that. So we had costs in the fourth quarter, and obviously, no volume to go in the first quarter. So we will see those costs trend off very quickly in the first quarter.
On a dollar per basis -- barrel basis in the Gulf Coast, all our refineries are on base costs, ex-turnarounds are about the same cost per barrel. So you won’t see a big change in that metric. But the absolute cost, controllable costs in the Gulf Coast will go down.
Hi, Manav. It’s Kevin. Just on the D&A, we did as you suspected, associated with the alliance conversion, we impaired some assets that flows through the D&A line. So that is one-time in nature.
Thank you so much for taking my questions and a great quarter.
The next question will come from Paul Cheng with Scotiabank. Please go ahead.
Hey, guys. Good morning.
Good morning Paul.
Good morning.
Two questions for you. I think the first one is for Kevin. I think in your prepared remarks you talked about the inventory benefit in NGL and also the refining that help the quarter. Can you quantify how to get those number? And also I believe that the deferred tax -- deferred revenue you recognize in the transportation, if you can quantify that also? Maybe that -- after that then I asked the second question.
Yeah. Paul, on the deferred revenue, it’s basically the variance quarter-over-quarter equates to the deferred revenue essentially. So that is the way to think about it. But I would say, with deferred revenue, that is no, I don’t think of that as a sort of one-time item, because the nature of those contracts on the pipelines, we are either going to get the volumes and the revenues recognized as you get the volumes or if there’s a shortfall in volumes, we still collect the cash and then we have makeup rights, or ultimately, recognize the deferred revenue.
So that’s a phenomena that you see going period-to-period. So it’s not a -- I don’t think it as a true inventory impacts both in the midst -- we have inventory impacts every period. And that’s not something we typically quantify unless it was excessively large in terms of the impact. So we typically don’t quantify those.
Okay. That’s fine. And that at least that in Refining, which region is the inventory impact?
No. It’s going to show up across all areas.
Okay. The second question, Greg, just I think before the pandemic, I think, in the past that you are sort of looking at long-term CapEx in the range of $2.5 billion to $3 billion kind of range, that talking about $1 billion to $2 billion of the -- maybe the growth CapEx. Now since then, of course, the outlook for the investment opportunity in the Midstream has changed, so you are probably not going to spend that much money. So once that your debt is back to a comfortable level and you start to be more in the growth phase, what is the capital allocation we should look at on the longer term basis? And also, maybe on a side question on PCP, is there any way to restructure that structure, I mean, you say $35 million, $40 million a quarter business. It seems like, yes, not causing you a problem, but it’s also not adding a lot of value. I mean, does it really fit into a long-term portfolio for you?
Okay. Paul, I think, you are up to five questions now, but I will try my best to -- at least I will answer one by one, how about that? So, first of all, we -- I mean, historically, we have used $1.5 billion to $2.5 billion is growth CapEx.
So I think that for many reasons, the need to be structured around debt repayment and get back to share repurchases. We purposely signaled total CapEx budgets of $2 billion or less for this year and kind of next year. We will see what happens going forward.
But I do think we want to get the balance sheet back to something over the next two years approaching pre-COVID, so call it, $12 billion. We are going to get back to share repurchases. I mean, we have been on share repurchases and it’s time to step back into those.
And so, I think, for all the right reasons, we want to keep capital constrained across the portfolio over the next couple of years. And to your [Audio Gap] we just don’t think those investable opportunities that will hit our return hurdles are going to be there in the next two years in the Midstream business.
And we will see where renewables goes and where renewables takes us. But right now, the biggest project in front of us is Rodeo Renewed circa $850 million project. So, I mean, that in itself is almost a megaproject by any standard. So I think there’s still big things going on around the portfolio in terms of growth and then you add on CPChem and the two megaprojects they are looking at.
So there are certainly lots of growth still around the portfolio, allows us to be very structured about how we think about capital allocation. But to your point, the whole idea is to free up more cash for debt repayment and getting back into share repurchases. Kevin, if you want to take DCP, I will let you take it.
Thanks. So, Paul, I mean, you are right that with DCP, we are looking at, you take out all the hedging noise, you are probably a $50 million, $60 million per quarter of earnings generation and a pretty consistent distribution that comes along with that.
While you could say, we are structurally challenged. It’s been a JV we have had in place for over 20 years. It’s been a very successful JV. The ownership has changed with -- as the owners -- with the M&A type activity over that time period.
But nonetheless, it has continued to be successful for us. It does give us some nice integration through our own Midstream business. So DCP volumes, we jointly own the Santel SunHills pipelines with DCP and NGL volumes through that system come into Sweeny and into our fracs and so we have the benefit of that integration.
So while a different structure might be a more efficient way of looking at that business, it’s not something that we have to get done. There’s nothing compelling that tells us we must have a different solution.
And the reality is when you get into these kind of arrangements that have been placed for a long period of time, it can be pretty hard to exit for any party when you look at the tax considerations and all of that.
So it’s a little bit like the Synovus question earlier. We actually feel that the JV has been very successful. It does what we want it to do and we will take it from there. We are always open to alternatives as we are with most of our portfolio, but it’s continued to work well for us.
The next question is from Matthew Blair with Tudor, Pickering, Holt. Please go ahead.
Hey. Good morning. Could you shed some more light on this British Airways SAS deal? How should we think about the economic impact to PSX here? Is it like a take-or-pay arrangement or maybe something else? And then, also, why do you think we are seeing these offtake deals in SAS, but not really in RD?
So I will take the shot at the first one. So the Humber Refinery entered into this deal to supply sustainable aviation fuel to British Airways. It’s a small volume. We don’t run a lot of renewable feedstock at Humber yet. We are working on a lot of things in Humber to reduce the carbon intensity of the fuels that come from that plant.
So we entered into this with British Airways really to get the partnership going and to understand their needs and they can understand what we can do and we can grow this business over time and be a good supplier. We are supplier to British Airways anyway. So this just kind of extends our reach there.
So it’s not large and material yet, but it really signals that in Europe with British Airways that we are going to expand that business as we expand our ability to run used cooking oils and other renewable feedstocks in Humber.
Yeah. I think that maybe, and Mark, if you want to add on to this, but if you think about Humber, and even once we get Rodeo Renewed. There is a certain part of the yield that’s going to be sustainable aviation fuel and I think the challenge for us is how do we think about that yield, how we push that yield structure to make more sustainable aviation fuel in the future.
Yeah. I think the big difference is, there’s not the regulatory incentives there for SAS yet. We think they will come, but we also see airlines making commitments and so there’s a demand pull for SAS out there that we will work to supply. But to shift that optimization wholesale away from renewable diesel into SAS there has to be a financial incentive, but it is sort of a co-product at this point that we can make commitments on.
And the only difference is in overseas in our Hamburg plant, the reason we were able to make that deal is because that scheme, the European scheme is different from the U.S. scheme, which treats renewable diesel, renewable gasoline and renewable jet fuel the same.
So that was why that deal was done there and that’s why deals haven’t been done in the United States yet. But we expect that as part of the Build Back Better plan, that we will get some incentive and over time, we will either get more incentive or airlines we will make commitments to pay more for the SAF.
Yeah. And I think it’s just the nature of how the market is going to work. When you think about the airline business, I mean, their only option today to decarbonize the sustainable aviation fuel. We don’t think hydrogen is going to work in planes. Batteries aren’t going to work in long-haul planes.
And so, I think, they are anxious to work with the industry in developing sustainable aviation fuels and I think what you are going to see is going to be contractual relationships developed so that they have access to the molecules that are going to be there.
Thanks for all the color. I will leave it there.
The next question is from Jason Gabelman with Cowen. Please go ahead.
Yeah. Hey. Thanks for taking my questions. I wanted to ask about the build diversify and M&A outlook on the Marketing and Chemicals business segments. Midstream, given that you are going to be consolidating PSXP, do you expect to be selling some of those non-core assets or are you in a stronger position to acquire Midstream assets now that you have this larger portfolio? And the Chemicals build versus buy question, in light of the fact that you are still evaluating two world-scale crackers. And then my second question is just, I think you mentioned Rodeo CapEx is going to be $850 million, if I heard you correctly, which is a bit higher than what you previously guided to. I think you had previously said something like $750 million. I just want to confirm that’s correct. Thanks.
Okay. Do you want to start?
Sure. I think on the build versus buy in Chemicals, I think, that we at CPChem level, they have always scanned the horizon, looking for opportunities to acquire assets, but it’s an environment that’s tough to acquire.
Things are really highly valued and they have got a long history of organic growth through true partnerships and been very successful in doing that. And that’s what’s driving both the U.S. Gulf Coast II project and the ROPP project.
And we are looking forward to an FID on U.S. Gulf Coast II mid-summer, late summer timeframe this year. We are taking a tough look at the economics to make sure that it meets the economic hurdles that we have in place, but we are optimistic that it well -- will, but we are working with EPC contractors now to develop that whole package to bring forward.
And then the ROPP project is about a year later. It’s already cleared front-end engineering design and so it’s well on its way to an FID sometime next year. So we continue to see opportunities organic that are more attractive than any acquisition opportunities in the Chemical space.
Yeah. I might just comment on the Marketing and Specialties. That business is consolidating, particularly the retail marketing in the U.S. And we are seeing many of our long time business partners.
They may be second generation or third generation businesses and for family estate planning. They want to exit or maybe the current generation doesn’t want to take over. And so it’s creating those opportunities.
So we ensure that we continue to have access to those markets long-term and so that’s what’s driving a lot of what we are thinking. I think Brian did a really nice job of talking about renewable diesel and making sure we are capturing all the value we can.
I think one of the things we have been frustrated with RINs is, we have never been able to explain what we think is some value leakage in the RINs and so we want to make sure that we are going to capture that full value chain around the new diesel side of that. So, I think that maybe is an important point as you think about what we are trying to do in the Marketing and Specialties space around that.
We always look at buy versus build. I think that certainly is an opportunity to think about that, particularly in businesses that are going to consolidate, for instance, like Midstream. I still think Midstream will have some consolidation.
And to your point, as we roll out PSXP, we have a full suite of assets kind of within our control, then I think we have the chance to really think about how we optimize our Midstream and particularly, our NGL-oriented portfolio around that. Tim, if you want to add anything on that on Midstream, please?
Greg, I mean, you covered at the high level. We are all about creating value. So we are always going to look at that portfolio and how we maximize that value. That can include buying, building or divesting. But that’s just part of stewarding the capital that we have got in the business that we are running.
We have reached the end of today’s conference call. I will now turn the call back over to Jeff.
Thank you, Sia. And we thank all of you for your interest in Phillips 66. If you have further questions on today’s call, please call Shannon or me. Thank you.
Thank you, ladies and gentlemen. This concludes today’s conference call. You may now disconnect.