Good morning, and welcome to the fourth quarter 2021 Phillips 66 earnings conference call. My name is Thea, and I will be your operator for today's call. At this time, all participants are in 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 filing. With that, I'll 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 specialties, demonstrating the strength of our diversified portfolio. For the third quarter in a row, we saw improved refining performance. Looking ahead, we're 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 25x better than the U.S. manufacturing average. Last year, our strong cash flow generation allowed us to invest $1.9 billion back into the business, return $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'll prioritize shareholder returns and debt repayment. In October, we increased the quarterly dividend to $0.92 per share. We remain committed to a secure, competitive and growing dividend. We'd like to resume share repurchases this year and are on our path towards getting back to pre-COVID debt levels over the next couple of years. We're taking steps to position Phillips 66 for the long-term competitiveness. Across our businesses, we're assessing opportunities for permanent cost reductions. Mark and Kevin are leading this initiative and will provide additional details on the first quarter call in April. We're 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 one and scope two emissions by 30% and scope three emissions by 15% compared to 2019 levels. With that, I'll 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 IV 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 has 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 multi-year agreement with British Airways to supply sustainable aviation fuel produced by our Humber Refinery beginning this year. For 2022, we'll 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 disciplined capital allocation and an emphasis on returns. Now, I'll 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 specialty 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 pre-tax income was $668 million, an increase of $26 million from the previous quarter. Transportation contributed adjusted pre-tax income of $273 million, up $19 million from the prior quarter. The increase mainly reflects the recognition of deferred revenue. NGL and other adjusted pre-tax 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 with 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 cargos in the fourth quarter. DCP Midstream adjusted pre-tax 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 amounts to approximately $50 million. Turning to chemicals on slide nine. Chemicals' fourth quarter adjusted pre-tax income of $424 million was down $210 million from the third quarter. Olefins and polyolefins adjusted pre-tax 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 pre-tax 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 pre-tax 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 differentials. 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. Pre-tax 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 three-two-one 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 than 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 pre-tax 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 pre-tax income of $97 million, up from $93 million in the prior quarter. On slide 13, the corporate and other segment had adjusted pre-tax 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'll cover a few outlook items for the first quarter and the full year. In Chemicals, we expect the first quarter global O&P utilization rate to be in the mid-90s%. In Refining, we expect the first quarter worldwide crude utilization rate to be in the high 80s% and pre-tax 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 pre-tax. For 2022, we plan full-year turnaround expenses to be between $800 million and $900 million pre-tax. We expect corporate and other costs to be in the range of $900 million-$950 million pre-tax for the year. We anticipate full-year DD&A of about $1.4 billion. Finally, we expect the effective income tax rate to be in the 20%-25% range. Now we will open the line for questions. Thank you. We will now begin the question-and-answer session. As we open the call for questions, as a courtesy to all participants, please limit yourself to one question and a follow-up. If you have a question, please press star and the number one on your touchtone phone. If you wish to be removed from the queue, please press the pound key. If you are using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star one on your touchtone phone. Your first question will come from Neil Mehta with Goldman Sachs. Please go ahead. Good morning, team. Good morning. Greg. Good morning. Greg and Kevin, first question for you on how you're 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-$6 billion as sort of that normalized cash flow range. But Greg, you've been clear that you think it's kind of closer to $6 billion-$7 billion. Just your thoughts on whether that's still how you're thinking about mid-cycle and the underlying build up to that $6 billion-$7 billion, if you can kind of walk through the world of your different segments of how you get there, would be great. I'd be happy to do that. I mean, I don't think we really changed from our view of $6 billion-$7 billion. Of course, it's nice to see $6 billion of cash last year. It just happened to occur in different buckets as you might expect from a traditional mid-cycle. I think we've been signaling in the last couple of months, we're pretty constructive, the refining business coming into 2022. If you think about the rest of the businesses, they've actually performed at or better than mid-cycle all through the pandemic in 2020 and into 2021, and we remain pretty constructive on those businesses coming into 2022 at all. Really for us, the wild card has really been refining. When does refining recover back to something approaching a mid-cycle? Just to remember how it all builds up on an EBITDA basis, kind of $4 billion. In refining kind of $2 billion in midstream, $2 billion in chemicals, and $1.5 billion-$1.6 billion in marketing and specialties, pushes you to something like $9-ish billion of EBITDA, which translates to $6 billion-$7 billion of cash. I think we're pretty comfortable that we're kind of still in that range. Obviously, we've had some outperformance. I mean, CPChem had a blowout year last year, all driven by great operations, fundamentally good control of their costs and then super margins. Our marketing specialty businesses, which we typically would say it's a $1.5, $1.6 business, was, you know, $2 billion. Of course, we've been investing in adding retail through our joint ventures. I think it was really great execution on the operations side, particularly in the US, but also in our European operations, where we saw good volumes, good margins across that. I would say that you were probably on the upside of that. Given $6 billion-$7 billion of cash flow our first dollar is always gonna go to sustaining capital. That's $1 billion. Dividend's $1.6 billion, and then that leaves room for us. We can signal that the capital budget's gonna be $2 billion or less, so we're $1.9 billion for this year. That's a deliberate signaling that for this year, next year, we're gonna 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. I you know, I think we make that all balance, you know, as we think about that. Now, Kevin or Jeff, if you wanna add to that, please step in or- No, I think you covered it all. Good. Thanks, Greg. That's the logical follow-up for me, which is how you're 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. What are the gating factors for you to begin a share repurchase program, and how do you think about sizing it? Well, we've always said the gating factor is getting, you know, cash flows back to something approaching a mid-cycle and making a dent in the debt repayment. I think coming into April, you're gonna pay another $1.5 billion-ish of debt off in April as it comes due. That's three of the $4 billion. We've made a big dent in that. I think that, you know, kind of post-April, that's why I said that I would be disappointed if by mid-year we're not back in a share repurchase mode at our company. Perfect. Thanks, Greg. Yes, sir. The next question will come from Phil Gresh with JP Morgan. Please go ahead. Yes, hello. My first question, just on one of the guidance items here on the refining maintenance, the $800 million-$900 million. Just looking back, it looks like it's the highest in the history of the company. 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. 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. Is this an environment where we're just gonna see margins get pressured higher to keep up with demand? Let me just take a high level, and then I'll let Bob Herman come in and talk about it since it's his business. If you look 2012-2019, we kind of average about $5.25 in terms of total turnaround expense. We did push some of 2020 and 2021 into 2022. I think probably a lot of the people did that in industries who were trying to conserve cash and protecting the balance sheet. It's a big number, Phil. There's no question. I'll let Bob speak to the specifics and what we're 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 just 2022 always gonna be a bit of a larger turnaround. We got two refineries, both Ferndale and Billings, that when they take their turnarounds, they're an entire facility turnaround, and they're coming due. So you kinda gotta 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, we would agree that a lot of people managed their turnarounds and maintenance work out of 2020 and 2021. Some of that's running lower utilizations. We made our catalyst and the hydrotreaters and hydrocrackers last longer, so we were able to stretch those runs. We put a lot of work into making sure we could do it from a mechanical integrity standpoint. Now those things are coming due, right? You can't do that forever. For us this year, it's a pretty heavy lift across the system, and I suspect we're not the only ones that are gonna 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're 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. As you may know, needle coke is used to make graphite electrodes, which in turn are used in production of steel, electric arc furnaces, which are actually cleaner technology than blast furnaces, and we use needle coke also to make anodes for lithium-ion batteries. In the past two years, we've seen a weaker needle coke market with steel producers running off high inventories. We do see some slow strengthening at the end of 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'll continue to increase. Some think it'll come off. Either way, you know, we've seen good demand from both steel producers and anode producers, and we expect that market to continue to gradually increase. We think, with refinery utilization coming back up and lower graphite electrodes, that it'll 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. Good morning. Morning, Roger. Morning, Roger. 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'd wanna see? Kind of tagging on with Phil's question about, you know, maybe a little higher spending on the turnaround side, is there a timing issue with those turnarounds where you'd wanna get past a certain level or is it bigger picture on the balance sheet for and overall cash flows when you'll feel comfortable? Yeah. Well, I think we're kind of back to the question on refining and when does refining get to mid-cycle type cracks. I mean, in 4Q, we're $11.60 realized crack. So I mean, that's the highest quarterly crack that we've seen in refining since the fourth quarter of 2018. There's some things that are in that number, obviously. As we look coming into 2022 we're constructive supply and demand. There's been a lot of supply that's come off the market. You know, we think there's new supply coming on, but it's gonna be staged. It's not all gonna hit when people think it's gonna hit because it always takes longer for it to come on. So from that standpoint, we're constructive on the demand side. You know, what we see with each successive wave of COVID, the impacts on demand are less and less. I'm not sure when that moment in time, as we transition from pandemic to endemic, but that could happen next year. Regardless, we see the demand impacts less and less from each successive wave of COVID. You know, prior to the current variant we were seeing gasoline demand kind of back at 2019 levels. There's diesel demand above 2019 levels. Jet was recovering nicely. As we move into 2022, we're constructive around the demand side. We talked about the turnaround activity and what impact that could have ultimately on utilizations. We just see everything balancing out towards more of a mid-cycle crack in refining. Once we get refining there, I think we feel pretty comfortable that we're gonna have sufficient cash flow, cover our sustaining capital, our dividend, pay down some debt, give back share repurchases, and fund the growth program that we have this year, which is about $900 million in growth. Kevin, if you wanna 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 a $1 billion notes maturing in April, and we intend to take care of both of those at maturity. Then what happens after that, we just have flexibility. We still have other callable debt available if we need to, but with that taken care of and if cash flow is back at mid-cycle levels, we're gonna have a lot of flexibility. I think we paid three 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 year periods is something that resembles kind of pre-COVID levels of, say, $12 billion on a consolidated basis. We're pretty comfortable in that construct, Roger. Okay. I 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, you know, 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're 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 yields switching from biodiesel, better aggregation of used cooking oil, we'll have plenty of feedstock to produce renewable diesel. Prices may vary over time, and that's to be expected. At Rodeo, we're on the water, so we have access to both domestic and foreign feedstock. We also sit on the U.S.'s greatest demand center, California, so feel good there. Our commercial organization's been working on feedstock for quite a while. We have offices around the world. We have storage in Asia and Europe and in the U.S. We have good relationships with vegetable oil producers. You know, you heard our announcement in our investment in Shell Rock Soy Processing. We've purchased for the startup of Rodeo, we've purchased soybean oil, canola oil, distillers corn oil since last April. We have strong relationships with tallow producers and aggregators of used cooking oil. In fact, with the used cooking oil, we've been in that market for over four years, supplying Humber used cooking oil from around the world, currently 12 different countries. I think Rodeo Renewed will have a maximum optionality in its system, and then we'll 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. Sounds like something for an MLP there. All right. Thank you. The next question will come from Ryan Todd with Piper Sandler. Please go ahead. Sure. 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 you're 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've got a very complex and strong refinery over there, in the impact of high natural gas prices on us. Then if we translate that to some of the simpler refineries in Central Europe, it's gotta be really tough for them to be making money right now. I'm sure we're gonna see that. We know that clean product yields out of a bunch of those refineries is down because they're 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. I think high natural gas prices are, you know, they're gonna continue for a while in Europe, and it is really gonna 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'll be able to export products to Europe to be good for our businesses as well. Great. Thanks. Then maybe a follow-up on the last question before this. I mean, you now have a couple of quarters under your belt producing renewable diesel there in California at a pretty decent level. I mean, can you talk about what you've learned from your operations both in product placement as well as feedstock acquisition there as you think about preparation for kind of the full project completion later on? As we've seen feedstock spreads narrow in the back half of the year and headline HOBO spread has improved, any comment on what you've seen in the profitability of your production there? Well, you know, the profitability between Q3 and Q4 has strengthened. There's a lot of things to think about when you're 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'll 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, you know, what we've been working on. We've set up a global organization to do that, and we're working hard. In renewable diesel, the key for us is getting the renewable diesel to the end user. That's the key. We keep more of the margin that way. In part, our purchase of our commercial fleet fueling business was enabled for us to get some of that product to end users. You'll continue to see those type of things. We've taken all the stores in California that we have, and we've converted those to renewable diesel as well. We're gonna have as much renewable diesel as we can to the end user, and we're gonna have as big a feedstock slate as we can for the plant, and we'll optimize through our linear program. I might add to that being able to operate 250 out there on renewable feedstocks instead of hydrocarbon-based feedstocks has really given us a good opportunity for the operators and staff to learn because it is very different and it runs different and there are different characteristics to handling it and getting it in the unit and dealing with it. 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. Can we talk about the pathways, the CI approval, et cetera? Yeah. You know, we started up the unit after the last turnaround on basically clean soybean oil. Since then, Brian mentioned it earlier, we've been able to establish pathways. In California, you run new feedstocks, you get a 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. Since we've done that, we've been able to qualify not only the soybean oil, but the distillers corn oil we're working on. We've gotten a pathway on canola oil. I think that's it. That process will keep repeating itself as we find more and more feedstocks ahead of Rodeo Renewed coming up in early 2024, that really allow us to take advantage of the lower CI material right away. I think it's 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, I'd say. Perfect. Thanks, guys. The next question will come from Doug Leggate with Bank of America. Please go ahead. Thanks, fellas. I've 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 just looking back at your share price. It seems like a horrible memory now, but your share price pretty much got cut in half twice in during the 2020 period. Obviously, you did not buy back stock when that happened, given the circumstances. 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 gonna 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 bit of a balancing, trying to meet multiple priorities. We think about an optimum capital structure in terms of cost of capital, right? Too little debt is increasing cost of capital. You've got that component to it. We've got other opportunities that we want to be able to fund. Bear in mind also that as we are growing the business, we're seeing that in the non-refining segments, as we're growing the business, we're effectively strengthening our overall financial condition because on a debt-to-EBITDA basis, we're continuing to improve from that standpoint. Obviously, we don't like the fact that we weren't buying shares at $40, but that was it. We were not in a position to do so. We had to just accept that. It's really around finding that optimum capital structure that will give us sufficient flexibility through the cycle, albeit you've always got more flexibility. The lower the debt balance, obviously that provides added flexibility, but at what cost is that? It's having the optimum structure to where we've got adequate flexibility. We can stick with our sort of capital allocation framework. 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. It's really just trying to balance through all of that. I'm not sure going too much further down on debt than our sort of stated objectives is going to buy us a whole lot in that context. I still feel pretty good with how we're laying out our objectives. I appreciate the answer. I guess it's more of a net debt question because obviously it's 20/20 hindsight is perfect. It's kind of gets back to this, I wonder if COVID has reset everybody's view of what volatility looks like. I appreciate the answer. My follow-up is something I really value from you guys periodically is your view on the net capacity outlook. 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. Here's my point. Gas prices are up. That's probably structural for international players. Net additions disclosures, light demand with IMO. I'm just wondering, are you guys thinking along those lines? How do you see the net additions, capacity additions, and subtractions in terms of impacting that mid-cycle view? Yeah, Doug, I think we've 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. We are seeing that benefit. As we look forward, there's still pressure with higher natural gas prices in Europe on those units' profitability. We see that continuing to occur. We've also seen, you know, COVID delays, challenges getting labor in to execute new capacity additions, so they're getting spread out. We've seen a reduction of capital spending and concerns over energy transition. It's definitely impacting the supply side of the equation. We are seeing demand come back. As Greg mentioned, gasoline was above 19 levels before this recent COVID hit. Diesel comfortably above. Jet's been coming back aggressively. We think jet demand by late this year could be back at 19 levels as well. 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. Thank you for taking my questions. 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. Just to be clear, the $404 of adjusted EBIT, did that include the $230? Yes, it does, Theresa. The $404 includes the $230. It applies to the full year. My additional comment was, if you think about that in terms of the quarters, you could say three quarters of that $230 would apply to the first three quarters of the year, and if you're doing any kind of normalization around that. Okay. But you presumably would not get that revaluation over and over again. The clean number for the quarter would be $174? Yes, if you back out the full $230. Okay, great. Thank you. 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 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? 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. We'll 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're 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 the margin, and we think that's the best bet. Thank you so much. The next question is from Manav Gupta with Credit Suisse. Please go ahead. Hey, 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 here or just keep the status quo. If you could comment a little on that situation. Take that, Bob. Okay. You can shoot him. Yeah. Next time we see him. All I can tell you is we continue to work really well with our partner on our joint venture, WRB for Wood River and Borger. 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've been a great partner to work with and give us good insights on things. Their world has changed. For now, we continue to work together to run WRB and invest in those two facilities as needed to extract more value out of both of them. Perfect. A follow-up quick question here is when you look at the segments here, the Gulf Coast operating cost was a little higher, and so was the DD&A. I'm 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're exactly right. There's a lot of noise in 4Q, and we still had all the people in the fourth quarter 'cause we worked through redeploying some and all that. So we had costs in the fourth quarter and obviously no volume to go with it. So we'll see those costs trend off very quickly in the first quarter. On a dollar per barrel basis in the Gulf Coast, all our refineries are on the 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 costs in controllable costs in the Gulf Coast will go down. 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. 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. Two questions, please. 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 helped the quarter. Can you quantify how to get those numbers? Also I believe that the deferred tax, deferred revenue you recognized in the transportation, if you can quantify that also. Maybe then after that, I ask the second question. Yeah, Paul. On the deferred revenue, it's basically the variance quarter over quarter equates to the deferred revenue essentially. That is the way to think about it. But I would say with deferred revenue, I don't think of that as a sort of one-time item because the nature of those contracts on the pipelines, we're either gonna get the volumes and the revenues recognized as you get the volumes, or if there's a shortfall on volumes, we still collect the cash, and then there's either make up rights or ultimately they close out and we then recognize the deferred revenue. So that's a phenomenon that you see going period to period. I don't think of it as a true one-time item. We had inventory impacts both in the midstream and in refining, but 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. Can you tell us at least that in refining which region is the inventory impact? No, it's gonna show up across all areas. Okay. The second question, Greg, just I think before the pandemic, I think in the past that you sort of looking at long-term CapEx in the range of $2.5 billion-$3 billion kind of range, that, talking about $1 billion-$2 billion dollar of the, maybe the growth CapEx. Now, since then, of course, that, the outlook for the investment opportunity in the midstream had changed, so you're probably not going to spend that much money. Once 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 DCP, is there any way to restructure that structure? I mean, $35-$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're up to five questions now. I'll try my best to start. At least answer the ones I want to. How about that? First of all, we did. I mean, historically, we've used more than $0.5-$2.5 billion as growth CapEx. I think that for many reasons, pandemic one of them, the need to be structured around debt repayment and get back share repurchases. We've purposely signaled total CapEx budgets of $2 billion or less for this year and kind of next year. We'll see what happens going forward. I do think we wanna get the balance sheet back to something for the next two years approaching, you know, pre-COVID, so call it $12 billion. We wanna get back to share repurchases. I mean, we've been out of share repurchases, and it's time to step back into those. I think for all the right reasons, we wanna keep capital constrained, you know, across the portfolio for the next couple of years. To your point certainly Midstream, 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. We'll see where renewables goes and where renewables takes us. Right now, the biggest project in front of us is Rodeo Renewed, you know, circa $850 million project. I mean, that in itself is almost a mega project by any standard. I think there's still big things going on around the portfolio in terms of growth. Then you add on CPChem and the two mega projects they're looking at. There's certainly lots of growth still around the portfolio, allows us to be very structured about how we think about capital allocation. To your point, the whole idea is to free up more cash for debt repayment and getting back into share repurchases. You know, Kevin, if you wanna take DCP, I'll let you take it. Thanks. So Paul, I mean, you're right that with DCP, we're looking at you take out all the hedging noise, you're probably $50-$60 million per quarter of earnings generation and a pretty consistent distribution that comes along with that. While you could say we're structurally challenged, it's been a JV we've had in place for over 20 years. It's been a very successful JV. The ownership has changed with, as the owners have, with the M&A type activity over that time period. Nonetheless, it has continued to be successful for us. It does give us some nice integration through our own Midstream business. DCP volumes, we jointly own the Sand Hills Southern Hills pipelines with DCP and NGL volumes through that system come into Sweeny and into our fracs. We have the benefit of that integration. 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. The reality is, when you get into these kind of arrangements that have been in place 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. It's a little bit like the Cenovus question earlier. We actually feel that the JV has been very successful. It does what we want it to do, and we'll take it from there. We're 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 SAF deal? How should we think about the economic impact to PSX here? Is it like a take or pay arrangement or maybe something else? Then also, you know, why do you think we're seeing these offtake deals in SAF but not really in RD? I’ll take the shot at the first one. You know, 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’re working on a lot of things in Humber to reduce the carbon intensity of the fuels that come from that plant. 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’re a supplier to British Airways anyway, so this just kind of extends our reach there. It's not large in material yet, but it really signals that in Europe with British Airways, that we're 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, you might add on to this, but if you think about Humber and even once we get Rodeo Renewed, there's a certain part of the yield that's going to be sustainable aviation fuel. I think the challenge for us is how do we think about that yield and 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 SAF yet. We think they'll come, but we also see airlines making commitments, and so there's a demand pull for SAF out there that we will work to supply. To shift that optimization wholesale away from renewable diesel into SAF, there has to be a financial incentive. It is sort of a co-product at this point that we can make commitments on. The only difference is overseas, in our Humber 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. That was why that deal was done there, and that's why deals haven't been done in the United States yet. We expect that, as part of the Build Back Better plan, that we'll get some incentive, and over time, we'll either get more incentive or airlines will make commitments to pay more for the SAF. I think it's just the nature of how the market's gonna work. When you think about, you know, the airline business, I mean, their only option today to decarbonize is sustainable aviation fuel. We don't think hydrogen's gonna work in planes. Batteries aren't gonna work in long-haul planes. I think they're anxious to work with the industry in developing sustainable aviation fuels. I think what you're gonna see is there are gonna be contractual relationships developed, so that they have access to the molecules that are gonna be there. Thanks for all the color. I'll 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 versus buy and M&A outlook on the marketing and chemicals business segments. Midstream, given that you're 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? The chemicals build versus buy question, in light of the fact that you're still evaluating two world scale crackers. 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 wanna confirm that's correct. Thanks. You wanna start? Sure. I think on the build versus buy in chemicals, I think that we, you know, at CPChem level, they've always, you know, scanned the horizon looking for opportunities to acquire assets, but it's an environment that's tough to acquire. Things are really highly valued. They've had a long history of organic growth through partnerships and been very successful in doing that. That's what's driving both the U.S. Gulf Coast II project and the RLPP project. We're looking forward to an FID on U.S. Gulf Coast II, you know, midsummer, late summer timeframe this year. We're taking a tough look at the economics to make sure that it meets the economic hurdles that we have in place. We're optimistic that it will, but we're working with EPC contractors now to develop that whole package to bring forward. The RLPP 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. 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 specialties. It is that business is consolidating, particularly the retail marketing in the U.S. We're seeing many of our longtime business partners, they may be second or third generation businesses, and for family estate planning, they wanna exit, or maybe the current generation doesn't wanna take over, and it's creating those opportunities. We wanna ensure that we continue to have access to those markets long term. That's what's driving a lot of what we're thinking. I think Brian did a really nice job of talking about renewable diesel and making sure we're capturing all the value we can. I think one of the things we've been frustrated with RINs is we've never been able to explain what we think is some value leakage in the RINs. We wanna make sure that we're gonna capture that full value chain around the renewable diesel side of that. I think that maybe is an important point as you think about what we're trying to do in the marketing specialty space around that. We always look at buy versus build. I think that the you know certainly is an opportunity to think about that, particularly in businesses that are gonna consolidate, for instance, like midstream. I still think midstream will have some consolidation. To your point, as we roll out PSXP, and we have that 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 wanna add anything on that, on midstream, please. Yeah, Greg, I mean, you covered it at the high level. We're about creating value, so we're always gonna look at the portfolio on how we maximize that value. That can include buying, building, or divesting. But that's just part of stewarding the capital that we've got and the business that we're running. We have reached the end of today's conference call. I will now turn the call back over to Jeff. Thank you, Thea, and 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.