Welcome to the Second Quarter 2021 Phillips 66 Earnings Conference Call. My name is Hillary, 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 afternoon, and welcome to Phillips 66 Second 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'll turn the call over to Greg. Thanks, Jeff. Good afternoon, everyone, and thank you for joining us today. In the second quarter, we had adjusted earnings of $329 million. We generated operating cash flow of $1.7 billion. Excluding working capital, operating cash flow was $910 million. With the benefit of our diversified portfolio, we generated cash flow in excess of capital spending and dividends during the quarter. We returned $394 million to shareholders through dividends in the quarter. Since we formed as a company, we've returned over $28 billion to shareholders. A secure, competitive dividend will continue to be a top priority for our company. We anticipate a return to dividend growth as cash flow recovers. We're committed to disciplined capital allocation, focusing on debt repayment in the near term to support a conservative balance sheet and maintain our strong investment-grade credit ratings. In July, the Phillips 66 Board of Directors appointed Denise Cade and Doug Terreson to serve as independent directors. We continue to work on board refreshment, recognizing the value of diversity in terms of gender, age, race, ethnicity, tenure, professional experiences, and perspectives. We'd like to highlight our recent 2021 sustainability report that can be accessed on our website. We think it's one of our best ones yet. Our commitment to sustainability is based on operating excellence, environmental stewardship, social responsibility, and financial performance led by strong corporate governance. We expanded our commitment to environmental responsibility, setting a goal for all of our refineries to achieve top third energy efficiency by 2030. We modified our compensation program to add additional environmental goals. As previously communicated, we will establish meaningful and achievable greenhouse gas emission reduction targets later this year. With that, I'll turn the call over to Mark to provide some additional comments. Thanks, Greg. Good afternoon, and thanks to everyone on the call for joining us today. Continued improved demand across CPChem's product lines and a resilient operating recovery from the first quarter winter storms contributed record quarterly earnings in our chemicals segment. Marketing and Specialties reported strong results as demand increased in many of our key domestic regions. Our midstream segment recovered well from the first quarter winter storms to report solid results. Headwinds continued in our refining segment as RIN-adjusted refined product cracks only improved modestly and historically low market capture contributed to continued losses. As more people across the globe are vaccinated, we expect continued economic recovery and further improvement in global refined product demand. In addition, permanent refinery closure announcements have increased to over 3.7 million bpd globally, with additional closure announcements expected. In midstream, Phillips 66 Partners continued construction of the C2G Pipeline. The project is backed by long-term commitments and is expected to be operational in the fourth quarter of this year. At the Sweeny Hub, we recently resumed construction of Frac 4, which will add 150,000 bpd of capacity. Upon completion, which is expected in the fourth quarter of 2022, total Sweeny Hub fractionation capacity will increase to 550,000 bpd. The fracs are all supported by long-term commitments. CPChem continues to develop two world-scale petrochemical facilities on the U.S. Gulf Coast and in Ras Laffan, Qatar. We expect a final investment decision for the U.S. Gulf Coast project next year. The Ras Laffan petrochemical project is progressing with front-end engineering and design as planned. Both projects are in partnership with Qatar Petroleum. In addition, CPChem began construction of its second world-scale unit to produce 1-hexene, utilizing CPChem's proprietary technology. 1-hexene is used for high-performance polyethylene manufacturing and is common in a variety of everyday products, including packaging for food, consumer products, and pharmaceuticals. The unit, located in Old Ocean, Texas, will have a capacity of 266,000 metric tons per year and is expected to start up in 2023. In May, CPChem was recognized by the Plastics Industry Association for being among the top 2021 industry innovators in sustainability. The award recognizes CPChem's launch of Marlex Anew Circular Polyethylene, which uses advanced recycling technology to convert plastic waste into high-quality raw materials. We continue to advance our Rodeo Renewed project at the San Francisco refinery. In July, we reached full production rates of 8,000 bpd of renewable diesel from the hydrotreater conversion. Subject to permitting and approvals, full conversion of the facility is expected in early 2024. Upon completion, Rodeo will have over 50,000 bpd of renewable fuel production capacity. The conversion will reduce emissions from the facility and produce lower carbon transportation fuels. Rodeo, combined with our portfolio of other renewable fuels projects, has the potential to supply 1 billion gallons of renewable fuels per year. In marketing, we're converting 600 branded retail sites in California to sell renewable diesel produced by the Rodeo facility. In Switzerland, our co-op retail joint venture continues to add hydrogen fueling stations. Through our joint venture, we're exploring hydrogen as a fuel option for heavy-duty vehicles to support European low-carbon goals and growing demand for sustainable fuels. We're moving forward and preparing for the future while maintaining our focus on safe, reliable operations and attractive shareholder returns. Now, I'll turn the call over to Kevin to review the financial results. Thank you, Mark. Hello, everyone. Starting with an overview on slide four we summarize our second quarter results. We reported earnings of $296 million. Excluding special items, we had adjusted earnings of $329 million or $0.74 per share. We generated operating cash flow of $1.7 billion, including a working capital benefit of $833 million and cash distributions from equity affiliates of $612 million. Capital spending for the quarter was $380 million, including $179 million for growth projects. We paid $394 million in dividends. Moving to slide five. This slide shows the change in adjusted results from the first quarter to the second quarter, an increase of $838 million. Pre-tax income improved across all segments, with the largest contribution from chemicals. Our adjusted effective income tax rate was 19%. Slide six shows our midstream results. Second quarter adjusted pre-tax income was $316 million, an increase of $40 million from the previous quarter. Transportation contributed adjusted pre-tax income of $224 million, up $18 million from the previous quarter. The increase was due to improved volumes from higher refinery utilization, partially offset by higher costs due to the timing of maintenance and asset integrity work. NGL and other adjusted pre-tax income was $83 million. The $47 million increase from the prior quarter was mainly due to lower operating costs and higher volumes, reflecting recovery from the winter storms. The Sweeny Fractionation Complex averaged 380,000 bpd, and the Freeport LPG export facility loaded a record 42 cargoes in the second quarter. DCP Midstream adjusted pre-tax income of $9 million was down $25 million from the previous quarter, mainly due to lower mark-to-market hedging results from higher natural gas and NGL prices. Turning to chemicals on slide seven. Second quarter adjusted pre-tax income was $657 million, up $473 million from the first quarter. This is the highest quarterly earnings for chemicals since the joint venture was formed in 2000. Olefins and polyolefins adjusted pre-tax income was $593 million. The $419 million increase from the previous quarter was driven by strong demand, tight supplies, and recovery from the winter storms that contributed to higher margins and lower utility costs. The industry chain margin increased over $0.17 per pound to a record $0.62 per pound. Global O&P utilization was 102% for the quarter. Adjusted pre-tax income for SA&S increased $55 million. The increase primarily reflects improved margins due to tight industry supplies following the winter storms, as well as lower turnaround costs. During the second quarter, we received $322 million in cash distributions from CPChem. Turning to refining on Slide eight. Refining second quarter adjusted pre-tax loss was $706 million, an improvement of $320 million from the first quarter. The improvement was driven by lower utility and turnaround costs and higher volumes. This was partially offset by lower realized margins. Improved market crack spreads were more than offset by higher RIN costs, lower electricity sales in the Texas market, decreased secondary product margins, lower clean product differentials, and inventory impacts. Pre-tax turnaround costs were $118 million, down from $192 million in the prior quarter. Crude utilization was 88%, compared with 74% last quarter. The second quarter clean product yield was 82%. Slide nine covers market capture. The 3-2-1 market crack for the second quarter was $17.76 per barrel, compared to $13.23 per barrel in the first quarter. Realized margin was $3.92 per barrel and resulted in an overall market capture of 22%. Market capture in the previous quarter was 33%. 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 gasoline crack improved $5.68 per barrel, while the distillate crack increased $2.20 per barrel. Losses from secondary products of $2.38 per barrel were $1.09 per barrel higher than the previous quarter as crude prices strengthened. Feedstock costs improved $0.36 per barrel compared to the prior quarter. The other category reduced realized margins by $7.84 per barrel. This category includes RINs, freight costs, clean product realizations, and inventory impacts. Moving to marketing and specialties on Slide 10. Adjusted second quarter pre-tax income was $479 million, compared with $290 million in the prior quarter. Marketing and other increased to $181 million due to higher domestic margins and volumes, reflecting strong demand in key markets. Refined product exports in the second quarter were 216,000 bpd. Specialties generated second quarter adjusted pre-tax income of $87 million, up from $79 million in the prior quarter. Slide 11 shows the change in cash for the quarter. We started the quarter with a $1.4 billion cash balance. Cash from operations was $1.7 billion. This included a working capital benefit of $833 million. In June, we received a $1.1 billion U.S. federal income tax refund, which is reflected in working capital. Cash from operations excluding working capital was $910 million, which more than covered $380 million of capital spend and $394 million for the dividend. The other category includes a $90 million loan to our WRB joint venture. Our ending cash balance was $2.2 billion. This concludes my review of the financial and operating results. Next, I'll cover a few outlook items. In Chemicals, we expect the third quarter global O&P utilization rate to be in the mid-90s%. In Refining, crude utilization will be adjusted according to market conditions. In July, utilization averaged around 90%. We expect third quarter pre-tax turnaround expenses to be between $120 million and $150 million. We anticipate third quarter corporate and other costs to come in between $240 million and $250 million pre-tax. 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 then 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 then one on your touchtone phone. Your first question comes from the line of Neil Mehta with Goldman Sachs. Good morning, team. Thanks for taking questions. The first one is just on chemicals. Mark, this might be for you. Kevin indicated that the indicator was $0.62, which is very robust and above mid-cycle in Q2. How do you see it playing out in July and August so far? Just any thoughts on what the mid-cycle number has been? I think you guys have been in the $0.25 camp, if I remember. Is that view changed in light of recent margin strength? Yeah. Thanks, Neil. It's a great question. We're still consistent on our mid-cycle margin projection. Of course, we're well above that today. As we look out into the third quarter, we're seeing the strength continue in the third quarter. We've got cost increases on the table that are being negotiated as we speak. Even if things went forward just as they are today, we're still at record margins, and we think that that can carry into third quarter. There's a lot of strength in the marketplace, particularly in North America and in Europe. Asia's still kind of lagging, but starting to perk up a little bit. The real story is the fundamental economic resurgence in the U.S., in North America and in Europe. We believe that there's some upside that'll offset some headwinds out in the future as the rest of the global economy kicks in. Now we're at record margins. Nobody believes those are sustainable for the long term. However, I think we can go from something at the record level to something that's still pretty robust. We see seasonal downturn typically in the fourth quarter, but we've also seen conditions where we can kind of carry through when there's strong enough marketing momentum, and there may be those kind of conditions now. We're particularly focused on high-density polyethylene, and that's still pretty tight in the marketplace. The inventories have not recovered to where CPChem would be comfortable operating, and it's unusual to be there this time of year with hurricane season. We typically want to be a little higher in inventories going into hurricane season. There's a number of factors that could lead to sustaining this momentum into the third quarter and beyond into the fourth quarter. We see the world economy kicking in about the same time additional capacity is coming on, say, first half of next year. There's some good fundamentals out there, and I think it's still got some legs based on the demand that will come to bear as the world economy fully recovers from COVID. Neil, we talk about mid-cycle kind of being the 2012 to 2019 average. If you look at the IHS polyethylene full chain margin, it's averaged about $0.30 per pound. Okay. $0.30 per pound. Okay. That's all great. Then to follow up, Greg and Jeff, this is for you. It's just thoughts on the refining side of the equation. If you told me the refining system was running at these type of levels, I would've thought that Phillips 66 would've been making pre-tax profits in the refining system. So, is the U.S. refining system running too hard? How are you guys thinking about your own utilization as you get into the fall? Yeah. This is Bob, I'll take the question. I think when you look back over the last quarter, I think there were plenty of market signals there for us to run at the utilization rates we were at. There's a lot of moving parts, in particular the cost of RINs, that just continued to increase throughout the quarter. We take a pretty good hit in refining for the full cost of those RINs. I think we would've all expected maybe on a global basis, Europe and Asia demand to tick back a little better than it did. I think the RIN-adjusted margins that we saw in the second quarter, really across our system, are very representative of a global market. Until we start seeing recovery, particularly in Europe, because we seem to see product flowing out of Europe into North America and South America, we won't really see RINs get back to where we would like to see them. I think the second piece for us in particular is our kit is more geared towards heavy crudes making diesel, and certainly for the second quarter, it was a gasoline-driven market without much differential on heavy crudes. We've seen those widen out here now in July to a much more respectable level. We think it's headed in the right direction, but I think all that added up to being challenged in the second quarter to turn a 90%-type utilization number into a profit. Brian, you want to comment on what we're seeing today in the market? I think in terms of the heavy diffs and the sour diffs, we've seen them start to expand. LLS to Mars is two Ls wider since the beginning of the year. WTI to Maya is three Ls wider since the beginning of the year. I think we have some tailwinds that are going to help us in the second quarter. We expect distillate cracks to perform as we get toward wintertime. All in all, I think we've also seen actually markets overseas come back. We have marketing in Europe, and we've seen Europe, Germany, where we market 90%-95% of demand. Austria, where we market 100% of demand. We've seen those markets come back as well. As Bob said, if the overseas markets start to come back, that'll help the U.S. cracks, and we should see some profitability in Q3. One thing I might add is if you look at the IEA, EIA, OPEC projections, we were kind of shy of 95 million bpd in 2Q, projected to get to 99.5 million bpd by the end of the year. Expectations for demand to continue to improve in the back half of the year. That's great, guys. Thank you. Your next question comes from the line of Roger Read with Wells Fargo. Hey, good morning or afternoon, as the case may be, I guess now. Jumping back to refining here, I guess one of the questions is, it's obvious that things should improve, but is there anything internally that Phillips has done or would plan to do to help out on the margin front? Just thinking of any additional changes within your own system or anything else that might be there part of the Phillips Advantage Program that was laid out almost two years ago now. Roger, I think there's two answers to that question. One internally. We expected tough operating conditions for a good part of this year. Recovery's been slower than we expected, but we went into this year trying to reduce some of our heavy maintenance expenses and adjusting turnarounds and all that. The guidance Kevin just gave for the third quarter is fairly light for us. I think that helps heading into third quarter profitability. You can translate that as we're available to run. If the cracks are there, we're going to be able to run pretty hard in the third quarter and make money. Around the AdvantEdge66 program that we laid out. A lot of that is built around margin enhancement, margin improvement. I would say we ran pretty well in the second quarter and using all those tools that are in our toolkit. The value chain optimization activities that went on in the second quarter were pretty robust. We did a lot of things that we haven't done before or needed to do before, such as we ran a lot of resid down into our Sweeny refinery, where typically we'd be running Maya or some of the heavy Canadians. The profitability really wasn't there. Optimizing around high sulfur resids into our system is just one example of where we're at kind of running the circuits. We're pretty happy with the results we're seeing on the operating front. A lot of our initiatives in refining are around being able to operate well, operate better, operate safer with a smaller environmental footprint, and we're seeing value come out of all those initiatives. They don't necessarily translate directly to the bottom line where you can see them, but over time, they're paying dividends. Roger, I think when I think about kind of Q2 and maybe even Q1, we've had quite a bit of planned FCC downtime this year. If you look at our yields relative to historical yields, we're probably down 2%. We're just simply going to run better the third quarter and fourth quarter. I think Bob's got things tuned up that we're ready to do that. I think that's one of the things that we're focusing on right now also. Okay, great. Thanks. One thing that was definitely nice this quarter, generating enough cash flow to cover all the outflows. I don't know, Kevin, this question is for you, but as you look, budgeting for the back half of the year, things are as they are today. I think that we've pretty much turned the corner on the COVID world and Phillips will be in a position to improve the balance sheet, start taking some of the debt down as we go through the next, say, two to four quarters. Yeah. Roger, certainly would expect to be able to do that. Obviously, we're not back at mid-cycle cash generation yet, which is really going to be our key marker in terms of truly being able to get the balance sheet back to where we need it to be. It's certainly a nice improvement from where we've been and with the cash balance, and if we continue to build that over the course of the year, we should be able to start making some inroads into that next year. As you know, as we've talked about before, we have a lot of flexibility around debt reduction, given the profile of the maturities that we have starting next year and some of the callable debt that we have in place. A lot of flexibility on that front. Great. Thank you. Yeah. Thanks, Roger. Your next question comes from the line of Doug Leggate with Bank of America. Thank you. Good afternoon, everybody. James, I wonder if I could ask you how, when you go through a cycle like this, and obviously a downturn, one imagines that you're stress testing all the assets in the portfolio. I guess it's kind of a follow-up to Roger's question. Do you see any weak links in the portfolio today that you think might be revisited in terms of portfolio structure, specifically on the refining side? I'm obviously thinking specifically about the Atlantic Basin. Yeah, Doug. Bob, I guess I would say that we spend a fair amount of time every year stress testing and looking at every one of our assets and where do we think the future of that asset lies. In a bigger picture context, too, not just the refining asset, but the rest of our value chain around it, right? How much marketing are we supplying in the area? We've got midstream assets, commercials trading around many of our assets, particularly around the coast. We look at a much more holistic picture, and quite frankly, we have a deck that we think is a long-term deck, considering what we think the future holds for liquid fuels, and we look at our assets in that context. They are assets at the end of the day, and so we're always looking to upgrade or find more ways to make money on any given asset from year to year. Fine. We will watch with interest how that evolves. I guess my follow-up may be for Kevin. Slide nine, you give a fairly clear description of how you realize margin has evolved this quarter. The 784 delta, can you maybe walk us through how much of that, maybe you can dig into a little bit more detail as to how much of that is truly transitory that we should expect to reverse? I'll leave it there. Thanks. Yeah. Doug, the largest single element within that 784 other is the RIN cost that, as Bob referenced earlier, is that expense is borne by refining. It is half or slightly more than half of the total within that other. Most of the other items in there. Well, RIN is always in there. Obviously, RIN's costs were particularly high during the quarter. Product differentials, which is the difference between the market indicator and the actual product realizations, that one can move around and go both directions on us. During the quarter, those differentials, we were not seeing the value for some of those premium products that often can be a benefit to us in the quarter. That's one that can move around and come back the other direction. The other component that's also in there, again, it can go both directions, is inventory impacts. Inventory was a hurt to earnings in refining in this particular quarter. That can move in both directions. Kevin, just to be clear, the configuration, so your different slate and product mix, that's not in configuration, that's in other, or how should we think about that? I always thought it was in configuration. No. The configuration reflects the 3-2-1. 2/3 gasoline, 1/3 distillate in the market indicator versus what we actually produce by way of gasoline and distillate. In other, you've got the actual pricing for those products, including whether it's premium gasoline and other premium products that can often be an uplift relative to the standard market indicator. In this period, they were not. Great stuff. Appreciate the explanation. Thank you. Okay. Your next question comes from the line of Phil Gresh with JPMorgan. Yes, hey, good afternoon. Greg, in the past, you always have referenced normalized earnings potential across the various areas of the portfolio. I'm curious how you think about refining's normalized EBITDA potential now that we've kind of gone through this COVID cycle. Is there anything that, having gone through this, that has changed your view? I think there's a $4 billion EBITDA number that you've thought about in the past. No, I think as I was saying, 2019, we laid out a $4 billion EBITDA number, and that at the time was kind of a 12-19 average EBITDA for our refining business. I don't think we're ready to sound a retreat yet on mid-cycle and refining. It's been, if you go back all the way back to the first quarter of 2020, that's the last time we actually made money as a company. There's no question there's been a lot of stress put on a lot of companies in our industry. I think we're constructive, particularly as we come in the back half of the year around demand. This has been a story of vaccinations, efficiency, lockdowns, and people trying to get back to some semblance of normal. That all translates directly into the demand that we see for our products. There's no question I think the U.S. has probably led in terms of demand recovery through this cycle. We've seen the impacts of Europe coming to the U.S. We've seen the impacts of not being able to export as much as we'd like to South America and places. I think as that world returns to normal, we've got a good shot at getting back to something that looks more like a mid-cycle. I think we said on the last call, we really need to see that 3-2-1 crack on a RIN-adjusted basis get back to about $12. I think we'll see the appropriate kind of market captures around that, and we'll be able to generate something around $4 billion. Jeff, I don't know if you want to add anything on that? Yeah, I think you guys have hit on the demand side of the equation. We are seeing refining rationalization, 3.7 million bpd of announced closures, 800,000 bpd of temporary outages that could become more permanent. We're up to about 1.7 million bpd of capacity that's been announced as considering either terminals or other types of service or potential shutdowns. That rationalization is a big piece of it as well. I think we're expecting more closures to be announced. Got it. Okay. In the press release, there's a mention of returning to dividend growth as cash flow recovers. I was hoping maybe you could lay out the priorities in terms of where you want that balance sheet leverage to get to before you would reconsider dividend growth. Kevin, just quickly, I think you said $1.1 billion for the tax refund in the second quarter. Is it still $1.5 billion for the year? In terms of the tax refund, you're right that it's about $1.5 billion total. We received $1.1 billion. There's another $350 million or thereabouts, but we don't expect the remainder to be a 2021 cash item. That will roll into next year. For a variety of reasons, that's not going to be cash this year, although it still will realize itself over time for us on that. In terms of dividend growth, I think we go back to the earlier comments around as cash generation recovers to something around about mid-cycle and we're in a position to pay down debt, we're making progress on paying down debt. We've got sort of clear line of sight to our ability to continue to do that and get the balance sheet back to where we want it to be. We should feel comfortable on some of the other capital allocation priorities, and increasing the dividend is one of those. I think it's a little bit of a long-winded way of saying we don't need to get to all we want to get to on the balance sheet before we make a decision on the dividend. We just need to be very comfortable that the structure is there, the cash generation is there, we're making the progress we need to make, and therefore, we'll be able to signal that in terms of our confidence to shareholders with the dividend. I think it's important. I think, overriding, we do want to protect the BBB+ AM Best rating. We think a lot about that. I think a milepost is starting to approach mid-cycle earnings for our company, as you know, $67 billion of cash flow at mid-cycle. That gives us plenty of cover to do the things we need to do. I think we've said in previous calls, we kind of expect CapEx for the next couple of years to be $2 billion or less. You think in the context of $6 billion-$7 billion of cash flow at total capital program of $2 billion and one-sixth dividend, I think we'll have plenty of room to do the things we want to do around bringing the balance sheet into order, thinking about capital return to our shareholders through dividend increases and share repurchases. Thanks a lot. Thank you. Your next question comes from the line of Paul Cheng with Scotiabank. Hey, guys. Good afternoon. Hi, Paul. Two questions. Greg, I think if I look at your NGL business this quarter, your EBITDA around $135 million. In 2019, the average quarterly EBITDA is about $170 million. We have the Frac 2 and Frac 3 come on stream and actually have the full operation, which probably should at least contribute $30 million-$40 million a quarter in the EBITDA, if not more. Trying to reconcile that. If the market condition really changed that much or that gets that much worse because NGL price is actually very good in the second quarter, maybe someone can help us on that. The second question will be just a real quick one. On the renewable fuel plant conversion, just want to see if there's a permit status that you can provide. Also that the last two years you guys have been trying to rebrand the work process and go for digitization. Just want to see if you can give an update on where we are on that. Is that pretty much that done with what you guys aimed from two years ago? I think at the time that the cost-saving target was pretty high, but with the pandemic, everything all get messed up. Yes, very difficult to reconcile. Maybe that you can give us some update. Okay. Let's start with the NGL. We got a lot of time here. Let's go, Tim. Follow this. Stay on your NGL question. I tell you what, first thing I would say is in 2019, I wish we were back in that macro. That was a good time with regard to the overall supply-demand fundamentals. Global demand was where you wanted it to be on really all of our midstream products, whether it was crude products and NGLs. Fundamentally, there are big changes in the market. When you look specifically at 2021, let me just highlight two things for you there that have reared their head. The biggest one that's had the biggest impact is Winter Storm Uri. When you look at Uri, it impacted our fracs significantly down there. Mainly not from the standpoint of damaging the units or any issues there, even though we did have some costs with the units, it was on utilities. Our utility bill was significant. From that standpoint, that's going to be hard to claw back for the rest of this year. On a positive note, I'd just tell you structurally, we like the NGL business. Demand's been very robust, to support chemicals growth both locally and globally. NGL production is ramping up. We still see about 1 million bbl in rejection at this point in time. Overall demand is really good in that space. Our LPG exports have been in a record clip. Overall, the fundamentals feel good, but it was a big cost hit as well as loss production hit that we had initially in 1Q, which really on a year-to-date basis stays with us. The last thing I'd just cover in 2Q, the overall structure in NGLs has jumped up significantly, as you probably are well aware, propanes, butanes, and ethane. You're at about $0.86, $0.87 on a gallon basis for NGL on a composite. In 2019 it was $0.37. It's gone up, and with that, we've seen an impact on some mark-to-market we have on some of our inventory. That's there. That usually turns into a timing issue. Just nonetheless, that shows up in the results in 2Q. How big is that impact on the mark-to-market in the second quarter? I'm going to guesstimate right now, I don't have the number right in front of me, it's around $10 million-$11 million. Right. Thank you. Bob, I think your second question was around the permitting status that Rodeo Renewed and the conversion out there of the refinery to running renewable fuel. We continue to develop the environmental impact statement with Contra Costa County. I would characterize that has gone about as well as it could, better than we expected. We're essentially done writing the permit. It's in review right now internally with the county, and we would expect them to probably sometime this month, release the permit to begin the public comment period. That would be pretty much right on our timeline, maybe a little bit ahead. So far it's been a good cooperative process with the regulators and their permit writers. We're encouraged and pretty happy where we are. We continue the outreach with all the other stakeholders in Contra Costa County and Northern California to make sure everybody understands what that project's going to do for the Bay Area and for California in general. So far so good. Digitization. Third piece, I think, was a question around the AdvantEdge66 and cost reductions and you're right, in a year like 2020, it's hard to see it, but I would say we've been able to deliver within bounds of the environment on both sides of the equation. We've had good optimization opportunities around reduced utilization in our refineries and our ability to get down as low as we did and to make jet go away and all those, I think, were much easier because of some of the efforts we had. The second piece I would say is, at the height of COVID when we had to social distance and we had to use alternative work approaches and everything else, our early jump into digitalization allowed our people to get a lot more done without human contact. Really was a dividend to us upfront in our ability to keep supporting the operators who were on the units while minimizing contact with the outside world. The third piece is we were able to hold the line on cost quite well throughout last year. In fact, we saw cost reductions in many of kind of our bigger cost items, caps and chems and those sorts of things that are a big piece of our operating budget. We applied some of the learnings that we got through AdvantEdge66 to those and I think we got sustainable longer-term price reductions there that will continue to pay out throughout this year. Full steam ahead on all our initiatives there, particularly in refining. Paul, I might just come in and just say, we're never done on the controllable cost side of our business. There's more work we've got to do in terms of continuing to address costs. That's what you do in a commodity business. When I look at the controllable cost through the first six months of this year relative to the first six months of last year, we're up about $300 million. Almost all that's energy costs in Q1. If you adjust for the energy component, we're holding the cost savings we were able to achieve last year. That's not good enough. There's more work for us to do around the controllable cost side of it. Hopefully you got all those questions answered. Thanks, Paul. Your next question comes from the line of Theresa Chen with Barclays. Hi there. Thanks for taking my questions. I guess first, just on the topic of global refining capacity and closures going forward, I'm curious to hear about your outlook for the European market, in general, given your exposure there. During the quarter, the macro data looked weak for a good portion. Now we're seeing some strengthening there and seeing news of operators restarting units and calling back workers. Just curious to hear about how you see that evolving in the closures landscape. I think Europe has been one of the most challenged market in the first half of the year. Lower margins and lower complexity. I think the demand has been slow to recover there. We are seeing some improvement. It looks like one of the more challenging regions. I think we've seen continued weakness in Latin American refining utilization as well. That could be a challenged area also. I think there was an expectation for a stronger summer than what we've actually had. As we come into the fall, that's typically where we see more closure announcement activity. I would say, and we point this out, the weakness in Europe has translated to weakness in the U.S. on our refining margins. We've seen typically 100,000 bbl of diesel imports into the U.S. This year, we've seen 200,000 bbl of diesel imports into the U.S. from Europe. We expect as Europe comes back from COVID lockdown, that those increased barrels will stop. We saw high imports of gasoline from Europe as well. We believe that that will stop too as Europe comes back from lockdowns. We've seen it already taper off. All those things, when the refining complex comes back in Europe and COVID lockdowns decrease, we'll see the U.S. also strengthen. Got it. Just on the crude side, can you talk to us about your medium to long-term outlook for WCS differentials in light of Enbridge's Line 3 replacement project coming online in fourth quarter? Should that, all else equal, narrow the differentials to the MidCon? Subsequently, when we think about Capline reversal happening later on, can there be a situation where you see the St. James market being flooded with incremental heavy barrels, which could actually help your Gulf Coast facilities? While the MidCon would be a little weaker with narrower, structurally narrower WCS spreads, and how do we see that thematic development playing out? I would say on the WCS, we have seen differentials come off quite a bit. We've got 4.5 million bbl of aid to leave Canada currently. We have about 4.4 million bbl of pipeline egress of another 100,000 bbl on rail. What we've seen, which is something a little different from what we've seen the past couple of years, is we've seen the WCS differential on the Gulf Coast weaken. It's weakened about $2.5 over the past couple of quarters. When that weakens, so does the Hardisty WCS differential, which you have to have in order to get the barrels to the Gulf Coast. One of the reasons the Gulf Coast is weakening is because low exports means that you have to have a weaker differential on WCS to get that WCS exported out of the U.S. As you said, Theresa, you have Enbridge coming online in next quarter four. We would think that that would firm up differentials a bit. Don't forget, in the wintertime, we add diluent to the crude, and that also increases the volume of crude that has to move. Our view, our forecast is that you'll see a differential somewhere between $12.5 and $13.5 off of WTI, going forward. Thank you. Your next question comes from the line of Manav Gupta with Credit Suisse. Hey, guys. I wanted to focus on the Rodeo conversion. We are seeing two trends out there. One are guys who are not building a pre-treat and their cost is varying between $1-$1.50 a gallon. There are guys who are building the pre-treat and their cost is varying between $3-$3.50 a gallon. You make five standard deviations from it. You are the only one who's building a pre-treat, and your cost is $1 a gallon. Help us understand what is special about this plan. I'm not trying to question. I'm sure you'll get there. Why is it so unique that you can pull this off and nobody else can? Manav, I agree with you. We will get there. What really sets up Rodeo completely differently, one is it's a full plant conversion, so we have all the kit available. We have two very high-pressure hydrocrackers that we can put into service. To convert those units from where they are today to being able to run renewable Diesel is actually a very low cost part of the project. Most of the cost of that project is in either the logistics piece and then the big chunk is the pre-treaters themselves. I think that's what allows us to be able to have a unique position of building a project that's going to be at an installed cost of about $1 a gallon, which you're right, is lower than anybody else. It is because if there was a refinery that was custom-built to be able to be converted to renewable feedstocks, Rodeo is it, since it's very unusual to have two hydrocrackers and excess hydrogen capacity on site between our own hydrogen plant and that of our third-party supplier that is built at the site. We've kind of got a perfect storm there. We're spending money to get all the logistics right, a little bit of metalling up in the hydrocrackers and in the pre-treatment unit, and we'll be ready to go. Perfect, sir. I have just one quick follow-up. I think the pandemic somewhere changed the nature of people as when it comes to the use of plastics, and that could somewhere be permanent. I'm just trying to understand, you have these two crackers which you have kind of put on a back burner. You can bring them forward, FID them. I'm just trying to understand, let's say you do decide that from the point of FID, how long will it take to get the first one and the second one? If this change is permanent and the demand for plastics is in an upcycle, you can capture part of it. Well, I believe we agree that the fundamentals have improved dramatically since we initiated these projects. As I noted earlier, the U.S. Gulf Coast 1, we're looking at FID next year, the Qatar project is about 1 year behind that. You can target about four years from FID to start up. We don't try to market time these investments, that we do believe that window is a particularly good window to pursue something. We've got our foot forward on these. We are ready to move, and we're working with contractors to make sure that we're getting the capital cost right. Clearly, the global markets are improving, but there's still some disruption in the world economy, and we'd like to see a little clearer path to a fully resolved economic recovery from COVID, get the Delta variant and any other variants behind us. We are leaning in and ready to move with FID on that project next year. Thank you so much for taking my questions. Your next question comes from the line of Matthew Blair with Tudor, Pickering, Holt. Hey, good morning. Thanks for taking my questions here. First is on chems. Could you share some color on the PE inventory picture? The industry data shows that PE inventories have really ballooned up to new highs, but your release talks about tight supplies. LyondellBasell and Dow also say the inventory's pretty tight. I was hoping you could just explain the disconnect there. Well, one of the disconnects, Matthew, is looking at just the gross inventories versus the days of sales of inventories because demand has increased almost 6% in North America. That's important. You also have to parse it out by kind of polyethylene because high density, linear low density, low density all have different inventory levels and different applications. We're heavily exposed to high density, and high density is particularly tight supply now and uncomfortably tight. It's been building. CPChem ran at 102% of their capacity in the second quarter, so they really delivered from an operational excellence perspective. Much of that went into rebuilding those inventories. Even though they had such a strong quarter, a lot of that production went into inventory, and they're still not where they would comfortably be heading into a hurricane season. They like to be prepared for that. They don't plan to have a hurricane, but they're prepared if there are hurricanes to impact that. I think that's where you're seeing the tightness. It's really from a day of sales perspective with the high growth in demand in North America as well as where we are in the weather cycles in North America. Sounds good. California LCFS data showed that combined RD and biodiesel blend rates in the state were about 35% in Q1. It seems like that number is only going to move higher going forward. I was wondering, are you feeling the pinch on placing your diesel out of the L.A. refinery? What are your long-term options here? No. Most of our diesel in the Los Angeles refinery goes out of state, out of California. That's not an issue for us there, Matthew. Got it. Thank you. Your next question comes from the line of Jason Gabelman with Cowen. Thanks for taking my questions. I wanted to ask two specific to the quarter on refining earnings related to RINs. It seems like marketing earnings increased a decent amount this quarter, and refining is still kind of in the doldrums in part due to RINs. I understand there's some accounting and value split between the RIN benefit in marketing versus the cost in refining. Can you just talk about maybe how RINs benefited marketing this quarter and how much of your RIN exposure is being minimized by blending and pass through to consumers? The second question, just also on the quarter quickly. Co-product realizations I know were a relatively larger than normal headwind. How's that looking 3Q quarter to date so far? Thanks. Matthew, this is Brian. Jason, this is Brian. I'll start off on the RINs question. Our view is that the RINs are in the crack. It's a cost that refining pays and the value of the crack is passed on to the consumer who pays for the RIN at the pump. Marketing doesn't see any benefit from the RINs per se. There may be some leakage in that chain, but marketing doesn't really see any benefit. Marketing did have a really very strong quarter in Q2, and a large part of that was we had kind of the right portfolio in the right places. We saw demand jump up in March and again in June. We have a strong presence in the Rockies and in the MidCon, where there were less COVID lockdowns and more movement. We added, as you know, retail in late 2019 and also in 2020 on the West Coast. That retail has done better than previous. We also added retail this year in the MidCon and Rockies. That retail is doing better than previous. Finally, I'd add that we've been reimaging the stores for the past three years. We're up to 85% of the stores reimaged. We've seen a 2%-3% jump in volumes and margins in those stores as well. We've done a lot of things to help our portfolios in the right spots. I think that's where we saw the value in marketing in Q2. I think on the secondary products within refining, they typically get squeezed in a rising oil price environment and improve in a declining oil price environment. We're kind of four quarters in a row of rising oil prices here. I think that's the biggest variable driving that secondary product margin. Yeah, I would agree 100% with Jeff. Usually we hit this time of year, too, we start seeing a little help in those secondary products because some of the coke we make ends up in the asphalt market then this time of year, right as people are out fixing roads and bridges and all those things. That's offset a little bit with we quit blending butane in the back half of the second quarter. It comes back again in September. There's a lot of moving parts in there. I would think this is kind of the maximum we would see for this type of oil price. Your next question comes from the line of Ryan Todd with Piper Sandler. Good, thanks. Maybe just a couple of quick questions on the renewable diesel business. Having ramped the Rodeo hydrotreater to the near-term target capacity of 8,000 bpd, can you speak to any learnings or takeaways you have from getting to that critical milestone and what you're seeing from kind of a margin or profitability point of view? Maybe a follow-up, can you talk about what it entails to convert your marketing locations to market renewable diesel, what the capital cost is associated with this, and how you envision kind of the marketing effort of RD to play out as the Rodeo conversion fully ramps up over the next few years? Yes. Well, I'll take the first question there. As we came out of turnaround and started up the Rodeo hydrotreater and renewable service, it actually came up, it ran really well. We had almost a full quarter of running at low rates. We still had a project to get the rail infrastructure finished so that we could supply 9,000 bpd to make the 8,000 bpd of renewable diesel. We're learning how the catalyst reacts and what the actual kinetics are around running bean oil. It's a little bit of a learning for the ultimate project of converting the refinery. These projects really are two very separate things in that there was no real work to do to convert 250 to bean oil. It was a matter of changing the catalyst at a regularly scheduled turnaround and then being able to run it. It's helpful. I think the bigger picture there is it's very helpful to our commercial organization to learn how to source renewable feedstocks, the logistics of getting them there, some of the peculiarities around transporting it. Those sorts of things all set us up to be a lot more nimble and ready for when we go from 8,000 bpd to 50,000 bpd with the renewable conversion. I think probably the best thing to come out of it is we did not see anything that made us stop and think about the project to convert the rest of the refinery that we needed to go back and think about our design. Pretty much operating as expected. I would add to Bob, we got that plant up 2.5 months earlier than we thought. 9,000 bbl into the plant, high conversion rate, just kind of a great asset so far. We've firmed up over 50% of the feedstock for the plant going forward. We've run soybean, but we've also run other vegetable oils there, so we've got some experience running other vegetable oils. We're looking at international feed as well. We've started converting the stores, as you mentioned. It's low capital to convert the stores. We'll have all 600 stores converted by the end of the year, and that will allow us to run volumes equal to three quarters of more of the RD that we're producing currently. Great. Thank you. This does conclude today's conference call. You may now disconnect.