Welcome to the Third Quarter 2020 Phillips 66 Earnings Conference Call. My name is David, 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 the 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 the Phillips 66 Third Quarter Earnings Conference Call. Participants on today's call will include Greg Garland, Chairman and CEO; Kevin Mitchell, EVP and CFO; Bob Herman, EVP, Refining; Brian Mandell, EVP, Marketing and Commercial; and Tim Roberts, EVP of Midstream. Today's presentation material can be found on the Investor Relations section of the Phillips 66 website, along with supplemental financial and operating information. Slide 2 contains our safe harbor statement. We will be making forward-looking statements during the 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 Garland for opening remarks.

Okay. Thanks, Jeff, and good morning, everyone, and thank you for joining us today. Our diversified integrated portfolio, strong balance sheet, and disciplined capital allocation enable us to navigate through this challenging market environment. In the third quarter, we delivered improved results in our Midstream, Chemicals, and Marketing businesses. We had an adjusted loss of $1 million or $0.01 per share and generated $795 million of operating cash flow, excluding working capital. We're proud of our employees and how they continue to step up to the challenges of 2020, including the pandemic, the West Coast fires, and Gulf Coast hurricanes. Most recently, our people responded to the storms by helping their families, their neighbors, and safeguarding our assets. Through our employees' commitment to operating excellence, our facilities were secured and sustained minimal damage. Our company has provided $7 million in assistance to our employees and contributions to communities across the Gulf Coast to help those affected by the storms. Our employees continue to execute our strategy with an unwavering focus on operating excellence in what has been a very uncertain and challenging environment. Our year-to-date safety results are exceeding last year's industry-leading performance despite the current challenges. Every day, we strive toward a zero incident, zero accident workplace and to keep our people healthy and safe. In the third quarter, we returned $393 million to our shareholders through dividends. We remain committed to a secure, competitive, and growing dividend. Since we formed the company, we returned over $27 billion to shareholders through dividends, share repurchases, and exchanges. In the near term, our focus is on ensuring the financial and operational strength of our company and overcoming this period of market weakness. We expect to exceed the $500 million in cost reductions and the $700 million in consolidated capital spending reductions announced earlier this year. We will continue to maintain disciplined capital allocation with a focus on long-term value creation for our shareholders. We're executing our growth strategy and achieved a major milestone with the completion of the Sweeny Hub Phase 2 expansion. We completed the two new 150,000 barrel a day fractionators at the Sweeny Hub, bringing the site's total fractionation capacity to 400,000 barrels per day. Frac 2 reached full rates in September, and Frac 3 started operations in October. Both fractionators have operated at rates exceeding design capacity. The fractionators are supported by long-term customer commitments. Phillips 66 Partners continued construction on the C2G pipeline, connecting its Clemens storage caverns to petrochemical facilities in the Corpus Christi area. The project is backed by long-term commitments and is expected to be completed in mid-2021. At the South Texas Gateway Terminal, the first stock and 5.1 million barrels of storage capacity have been commissioned. Terminal operations are expected to ramp up through the end of this year as additional phases of construction are finished. We expect the project to be completed in the first quarter of 2021 with a total storage capacity of 8.6 million barrels and up to 800,000 barrels per day of export capacity. Phillips 66 Partners owns a 25% interest in the terminal. As we wrap up our major projects in execution this year, we expect that total capital spending for 2021 will be $2 billion or less. We look forward to sharing the details of our 2021 capital program with you in December, applying the approval of our Board. Phillips 66 recognizes the climate challenge and is making investments to competitively position the company for a more carbon future. Recently, we announced plans to reconfigure our San Francisco Refinery in Rodeo, California, into the world's largest renewable fuels facility to meet the growing demand for renewable energy. The plant will no longer produce fuels from crude oil, but instead, it will have the flexibility to run used cooking oil, fats, greases, and other feedstocks. Upon completion in early 2024, the facility will have over 50,000 barrels per day or 800 million gallons per year of renewable fuel production capacity. This capital-efficient investment is expected to deliver strong returns. The conversion is expected to reduce the plant's greenhouse gas emissions by 50% and help California meet its low carbon objectives. Earlier this month, CPChem announced its first commercial scale production of polyethylene from recycled mixed waste plastics. This development is an important milestone, further demonstrating CPChem's commitment to proactively help the world find sustainable solutions, including the elimination of plastics waste in the environment. We have a dual challenge of providing affordable, abundant, reliable energy to the world and also addressing the global climate challenge. Our company is committed to both while continuing to deliver shareholder returns. So with that, I'll turn the call over to Kevin to review the financials.

Thank you, Greg. Hello, everyone. Starting with an overview on slide 4, we summarize our financial results. We reported a third quarter loss of $799 million. We had special items amounting to an after-tax loss of $798 million, including impairments related to the planned conversion of the San Francisco refinery to a renewable fuels facility as well as the cancellation of the Red Oak pipeline project. Excluding special items, we had an adjusted loss of $1 million or $0.01 per share. Operating cash flow was $795 million, excluding working capital. Adjusted capital spending for the quarter was $549 million, including $347 million for group projects. We returned $393 million to shareholders through dividends. Moving to slide 5. This slide shows the change in adjusted results from the second quarter to the third quarter, an improvement of $323 million. Adjusted pretax results across all segments were improved, except refining. The income tax benefit was mainly driven by bonus depreciation on assets recently completed and the ability under the CARES Act to carry back net operating losses to previous periods. Slide 6 shows our midstream results. Third quarter adjusted pretax income was $354 million, an increase of $109 million from the previous quarter. Transportation-adjusted pretax income was $202 million, up $72 million from the previous quarter. The increase was due to higher pipeline and terminal volumes supported by recovering demand. Third quarter results reflect a ramp-up of volumes on the Gray Oak pipeline and the start-up of South Texas Gateway Terminal. NGL and other delivered adjusted pretax income of $102 million. The $19 million increase from the prior quarter was due to higher Sweeny Hub volumes and inventory impacts. At the Sweeny Hub, the Freeport LPG export facility averaged 12 cargoes per month, and Frac 1 averaged 120,000 barrels per day. DCP Midstream adjusted pretax income of $50 million was up $18 million from the previous quarter, reflecting hedging impacts. Turning to Chemicals on slide 7. Third quarter adjusted pretax income was $132 million, up $43 million from the second quarter. Olefins and polyolefins' adjusted pretax income was $148 million. The $42 million increase from the previous quarter is due to higher polyethylene margins driven by improved sales prices, partially offset by lower polyethylene volumes and higher operating costs. Global O&P utilization was 94%, reflecting downtime at US Gulf Coast facilities. CPChem proactively shut down facilities in preparation for the storms that made landfall in the third quarter. The facility sustained minimal damage and has returned to normal operations. Adjusted pretax income for SA&S decreased $6 million, primarily due to lower margins, partially offset by higher volumes. During the third quarter, we received $112 million in cash distributions from CPChem. Turning to Refining on slide 8. Refining third quarter adjusted pretax loss was $970 million, down from an adjusted pretax loss of $867 million last quarter. The decrease was due to lower realized margins partially offset by higher volumes. Realized margins for the quarter decreased by 32% to $1.78 per barrel. The decrease reflects tightening crude spreads and the absence of the steep contango market structure experienced in the second quarter. In addition, secondary product margins were lower due to rising crude prices. Crude utilization was 77% compared with 75% last quarter. Improved utilization reflects increased refining runs in the Central Corridor and West Coast regions, partially offset by downtime at Gulf Coast refineries. We shut the Lake Charles refinery in late August and the Alliance refinery in mid-September in preparation for hurricanes Laura and Sally. Lake Charles downtime was extended due to third-party power supply issues following Hurricane Laura, and restart was further delayed by Hurricane Delta. The Lake Charles refinery has safely resumed operations, and Alliance remains down for planned turnaround activity. Pretax turnaround costs were $41 million, in line with the prior quarter. The third quarter green product yield was 85%. Slide 9 covers market capture. The 3:2:1 market crack for the third quarter was $8.17 per barrel compared to $7.47 per barrel in the second quarter. Realized margin was $1.78 per barrel and resulted in an overall market capture of 22%. Market capture in the previous quarter was 35%. Market capture is impacted by refinery configuration. We make less gasoline and more distillate than premised in the 3:2:1 market crack. During the quarter, the distillate crack decreased $2.46 per barrel, and the gasoline crack improved $2.27 per barrel. Losses from secondary products of $1.80 per barrel increased $0.85 per barrel from the previous quarter due to rising crude prices. Losses from feedstock were $0.35 per barrel compared with $0.67 per barrel last quarter. The other category reduced realized margins by $2.77 per barrel. This category includes RINs, freight costs, clean product realizations, and inventory impacts. Moving to Marketing and Specialties on slide 10. Adjusted third quarter pretax income was $417 million, $124 million higher than the second quarter. Marketing and other increased $107 million due to higher margins and volumes. The marketing business captured strong margins during the quarter and benefited from recovering demand. Specialties increased $17 million due to higher finished lubricants volumes. We reimaged 284 domestic branded sites during the third quarter, bringing the total to approximately 5,000 since the start of the program. In our international marketing business, we reimaged 31 European sites, bringing the total to 143 since the program's inception. Refined product exports in the third quarter were 139,000 barrels per day, a decrease from the prior quarter. On slide 11, the Corporate and Other segment had adjusted pretax costs of $213 million, a decrease of $11 million from the prior quarter. The improvement is primarily due to lower employee-related expenses, partially offset by higher net interest expense. Slide 12 shows the change in cash for the quarter. We started the quarter with $1.9 billion in cash on our balance sheet. Cash from operations was $795 million, excluding working capital. There was a working capital use of $304 million driven by an increase in tax receivables. Our net debt issuances were $70 million. Adjusted capital spending was $549 million. We expect full year 2020 adjusted capital to be approximately $2.9 billion. We returned $393 million to shareholders through dividends. Our ending cash balance was $1.5 billion. We remain focused on conserving cash and maintaining strong liquidity in the current environment. At September 30, we had $7 billion of committed liquidity, reflecting $1.5 billion of cash plus available capacity on our credit facilities of $5 billion at Phillips 66 and $0.5 billion of Phillips 66 Partners. This concludes my review of the financial and operating results. Next, I'll cover a few outlook items. In Chemicals, we expect the fourth quarter global O&P utilization rate to be in the mid-90s. In Refining, crude utilization will be adjusted according to market conditions. In October, utilization has been in the mid-60% range, impacted by downtime at the Lake Charles and Alliance refineries. We expect fourth quarter pretax turnaround expenses to be between $80 million and $100 million. We anticipate fourth quarter Corporate and Other costs to come in between $220 million and $230 million pretax. With that, we'll now open the line for questions.

Your first question comes from Neil Mehta from Goldman Sachs. Please go ahead; your line is open.

Thanks so much, guys, and good morning. My opening question is around the balance sheet and the dividend outlook from here. I think the message today is that you guys view the dividend as sustainable, but can you just talk to that? And then can you also just give us some flavor, maybe this is for Kevin, about conversations with the ratings agencies about credit, and how do you feel about where your balance sheet position is right now?

Let me address the first part, and then Kevin will take the second. Neil, one thing I've learned is to never say never in this business. However, all the actions we've taken so far—reducing costs, cutting back on capital expenditures, and boosting our liquidity—have been aimed at protecting the dividend. Looking at the third quarter, we've managed to cover both our capital expenditures and our dividend with cash. We're quite confident that if conditions remain steady, our first dollar will go toward capital expenditures at $1 billion, and our second dollar will support the dividend at $1.6 billion, which allows us to sustain both our capital investments and the dividend with our cash. This reflects one of the key strengths of the PSX portfolio and its diversified nature. Now, I'll turn it over to Kevin to discuss the balance sheet and our expectations there.

Yes. So we've consistently expressed our objective to maintain a strong balance sheet, keep that financial flexibility, and that's reflected in our credit ratings, A3 at Moody's and BBB+ at S&P. As you would expect, this year with a couple of debt issuances that we've done, we've had plenty of opportunity to have conversations with the rating agencies. Those have gone well. Our ratings have stayed where they are. We've had no actions, and we still have a stable outlook on the current rating. So we feel good about that. In the event that we need to go to the balance sheet, we feel pretty comfortable that we still have decent capacity without having a detrimental impact on the overall health of the balance sheet. So you think from a long-term standpoint, our objective is to have a solid investment-grade credit rating, and we're clearly there at this point. We've added some debt. We've also talked about a 30% debt-to-capital ratio. We're above that right now. I think as we come through this current situation, then we were able to get debt back down, we'd anticipate that over time, we'd like to see ourselves back in around about that range. But we've always said that's not an absolute target. The real objective is to maintain solid investment-grade credit ratings, and we're comfortably there, and we feel good that we can stay there.

Great. And a follow-up is just around marketing. It was a strong quarter there. Just any flavor in terms of what drove the outperformance? And real time, what are you seeing for demand in the markets that you serve?

Thanks, Neil. Yeah, we're very happy with the marketing earnings in Q3 versus Q2. We were up 40% on margins in the U.S. and 16% on volume. Overseas, we were up 23% on margins and volumes as well. I think a number of things. If you look at Q2, underlying commodity flat prices came off hard in April, and it was up in May and June. And as you know, flat prices are inversely correlated to marketing margins. So that helped our margins a good bit. Also, the volumes, of course, were up in Q3 versus Q2 when COVID was more fierce during the Q2 time period. Currently, we're seeing gasoline off about 10% in the U.S. And when we talked to our large truck stop customers, they say that until recently, diesel demand was back up to pre-COVID levels, but they've started to see it come off a bit, 3%, 4% type levels. Overseas, we were back up to 100% of demand peak-COVID levels. Currently, with lockdowns tightening just a bit, we're seeing those levels come off just a few percentage points, but happy with where we've gotten to from the lows in early Q2.

One thing I might add is that we've seen strength on the West Coast. The port of LA is up 13% year-on-year. We are also seeing PADD 5 diesel demand increase year-on-year. There is some strength, especially on the West Coast.

Yes, hi. Good afternoon. Just want to start with the question on refining here. Some of your peers are acknowledging that the U.S. industry needs to close 1 million barrels a day of capacity in order to balance the market. You guys have, obviously, taken some action here with Rodeo. I'm curious how you think about the U.S. refining industry, the amount of capacity that needs to close? And with respect to the existing system as it stands and where utilization is, how do you think about your individual refineries and whether it makes sense to have a temporary idling or permanent idling at some point for another refinery? Thank you.

Yes, Neil, it's Bob. I believe we can agree that there needs to be continued rationalization between the U.S. and European refining systems. In the U.S., refineries vary significantly; some are very strong while others may have weaknesses. Nonetheless, the U.S. refining system remains the most complex and lowest-cost, aside from a few large facilities in the Middle East. As demand balances out over time, the U.S. is well-positioned to be a strong player. We will see increased export activity over time to Latin America, South America, and West Africa. However, there will still be some assets that will need to phase out, as we've already seen on both coasts. Additionally, some landlocked refineries may face challenges as crude differentials in the U.S. remain tight. Jeff, do you have any data on closures so far?

Yeah. We've been tracking announced refinery closures. And in fact, we've had to revise it three times this week. I think we're up to almost 2 million barrels a day of announced closures globally. There's another 700,000 barrels a day of temporary closures and then another 700,000 barrels a day of refineries that have talked about a potential of converting into terminals or other activities. So 3 million to 3.5 million barrels a day globally. It's kind of split regionally with equal parts of U.S., Europe, and Asia. We've even seen an Australia refinery that's been announced closure earlier today. And as you listen to many of the integrated oil companies, they've made comments on planning to further reduce their exposure in the downstream. So we're moving rapidly through rationalization. I think as we watch diesel inventories come off really hard over the last few weeks here, I think that's a little bit of this tunnel for margins to improve. And with margins improving, utilization will come back as the market dictates. But until that kind of happens, I don't think we'll see it. The growth in GDP numbers this last week, I think, are a really good barometer that says diesel demand should continue to strengthen into the winter and the normal cold season, and the burning of heating oil in the North is going to be a help. So I think we might be in a position to see some upward movement for a couple of months. But I think it's setting ourselves up that as we get to spring and look forward into next year's gasoline season that we do have a real chance of returning to a lot more normalcy in the margin structure and then utilization.

Okay. Great. Thank you for all that. Just a follow-up on your own refining performance here in the quarter and the pace of margin normalization, how do you think about, I guess, the capture rates that you've been seeing this quarter and last quarter? Obviously, hurricane effects. Kevin, you called out a number of factors in the other bucket that were headwinds here in the quarter. So how do you think about the sensitivity of capture rates to the overall margin profile? And as we move forward, if margins get better, captures get better and things like that versus maybe some one-off items that may have happened in the quarter?

I view the capture rate as being influenced by cracks in the $6 to $8 range, which covers costs. The crude differentials are where we earn our revenue in refining, but we have experienced very tight differentials across our system, making it difficult to see significant crack expansion. Additionally, when utilization and cracks are low, the fixed portion of the barrel, which is around 11% or 12% that we don't convert to clean product, shows a more considerable impact at an $8 margin compared to a $15 margin. These factors significantly limit our ability to capture margins.

Yes, thanks. Good morning. I guess I'd maybe like change the direction a little bit from refining to the midstream. Greg, probably a question for you. But one of the pushbacks we get is with E&P is changing behavior, maybe a little less production growth in coming years. You've built out a lot in the midstream. Can you kind of characterize for us how midstream should perform in a maybe more static or production growth market? And what your exposure would be to any sort of, let's say, reprice on tariffs or export fees and so forth?

Tim, I'll let you take that.

Yes, Roger, on that, a couple of things when you look at our portfolio specifically is that we've been in earnest trying to develop minimum volume commitments and make sure we get commitments. And so those have been very important for us with regard to long-term commitments, MDCs with good counterparties, investment-grade. So, that's been very helpful for our portfolio, especially on the third-parties. But then also as a sponsored MLP, we have quite a bit of exposure with regard to PSX. So that helps to also shore up some of our earnings volatility, you see. But also just on a fundamental basis, we do see that there will be basin growth. Yes, granted everyone's state of uncertainty and what's going on out there and they're retrenching a bit. But we still think there's going to be a call on managed shale with regard to global demand to support growth in that area over the next couple of years. And the other part I would say just when you look at our portfolio specifically, it's just really that we really participate in the crude side. But we've also got a good weighting with regard to the NGL space as well, which actually during this time has been rather resilient and supported by chemicals, global chemicals demand, growth, res com, and then subsequently also going into the motor fuel pool as well.

I think the average term across our portfolio is probably about eight years. And so we've got some time to ride through this. I do agree that the next one- to three-year period, there's going to be fewer investable opportunities in midstream, and this is going to become more of a run-well and optimized business for many people. I think you'll see some consolidation of midstream over the next couple of years. And so I think that the model going forward the next couple of years is going to be a little bit different than the model we've executed the last five years. The other thing I would say is somewhere around 80% probably across the portfolio is under minimum volume commitments. And so we think we're really set up well to ride through these next couple of years of our Midstream business and still deliver great performance in our midstream business.

Great. Thanks. And just a follow-up Kevin for you. The working capital related tax adjustment, can you kind of walk us through working capital expectations into the end of the year? Typically, I think Philips gets a pretty big pull on working capital. And then part on the tax, when would you expect to recover the actual tax receivable there?

Yes. Okay. So, on the tax component, as you see on the financial statement, a significant tax benefit on the income statement, but that's not turning into cash in the current year, that's flowing through the receivable. And on a year-to-date basis, we've increased our tax receivable by $1.2 billion, $1.3 billion year-to-date, and that, we would anticipate collecting next year post completion of our 2020 tax return and so we would expect that to turn into cash sometime in the second quarter of next year. From a broader working capital expectation going into the third quarter, you're going to see two dynamics going on. One is, to the extent that the current operating environment stays as it's been, which appears to be then from a tax standpoint, you'd still expect to be generating losses and so you'll have that negative effect on working capital. But we typically have an inventory draw in the fourth quarter and we anticipate that happening again this year. And so that will generate some positive cash from a working capital perspective.

Doug Leggate from Bank of America. Please go ahead. Your line is open.

Thank you. Good morning, everybody. I hope you are all doing well there. Greg, I wonder if I could just pick up on the comment you made there about a slightly different business model for the midstream than we've seen in the last five years. I wonder if I could ask you to elaborate on that with specific focus on your ownership structure of PSXP?

Well, I think that – I mean, first of all, I think that the upstream and the pace of drilling upstream will determine the pace of opportunities in midstream for any future growth. So we talked about that a lot, and so we'll see. I suspect we're in a period of stronger capital discipline from the upstream players in a mode of returning more capital to shareholders, which will by definition probably slow the growth of upstream. And conversely, that will limit the investable opportunities in midstream. So we recognize that. We're supportive of that. We think that's the right thing for the energy space long term in our country. For PSXP, it still highlights the value of our midstream business, and we like that. I think that it's a model that will continue to move forward. We evaluate alternative scenarios for PSXP, just like we do for any other asset in our portfolio as we move forward. But at this point in time, we still like the MLP structure. I think we would all acknowledge that the life cycle of an MLP has probably been shortened versus what it was maybe five years ago or six years ago. Kevin, I don't know, or Tim, if you want to add anything to that?

No, I think you covered that.

Okay. I don't want to elaborate too much on that. But when you see it trading with a 15% yield, Greg, would it make sense to buy that in at some point?

Yes, I think – well, for PSXP, certainly, I would say we're not happy with where the units are trading, and we look at that 15% yield and scratch our head a little bit, Doug. But I also think that PSXP has a bit – has that DAPL overhang. And I think that if you look at where the units are trading today, I think most people are priced in a complete shutdown of the pipeline. And so we're not there. But that's in the hands of someone else and a judge that, hopefully, I guess, year-end or early next year, we'll get a determination on that. So I don't know, Tim or Jeff, you want to add anything to that. But the overhang is what we're looking at right now.

That's right.

Thanks, guys. My follow-up is kind of a broad question. I don't know which one of you guys wants to answer this, but we got an election in three or four days in case you weren't aware. But what do you see as the principal risks to your business? Whether it would be tax? Whether it would be regulation? Whether it would be something like DAPL, just give us a quick summary as to how you're preparing for a potential change in administration?

Well, first of all, for clarity, I don't know how to answer that question. So I guess this falls to me to give an answer. So I think in a Democratic scenario, there's no question that from a regulatory standpoint, it's going to be a tougher environment for all kinds of infrastructure. But energy, in particular, our base case view is probably going to be something more like we saw eight years under the Obama, Biden administration than what we've seen for the last four years. I do think that infrastructure is going to be harder to permit. I think pipelines, in particular, will be harder to permit. So you can make a case that the existing pipes are probably worth more in the ground under that kind of scenario. I think with that question, corporate taxes are going to go up in that scenario, which, by the way, should help the MLP structure just in terms of relative cost of capital versus a C-corp. So we're looking at that. And then we'll see where we end up on climate and climate solutions. But I think that the odds are probably higher than have some sort of cost of carbon that emerges with time in a Democratic scenario versus the status quo. So that's kind of how we're thinking about it holistically and kind of the impacts to our business. Jeff, I don't know if you want to add anything?

It's well done.

Thank you. Good morning, guys.

Good morning.

Greg, if I can follow-up on that but string it to Europe. With the new climate law, how are you looking at your assets in Europe and what's the game plan? Do you need to fundamentally change how you operate the refining and also the retail operation?

Paul, I'm sorry, I missed the first part of that question.

The first part is that with the European Union going to a climate law, how is that going to change your operation? And what is the game plan for your European assets, whether that you need to fundamentally change the way how you operate, or do you have any view that under the new climate law, how those assets should be?

I’ll address that, Paul. First, there are aspirational goals, but there’s also the reality of what can be achieved within that timeframe. We believe that fossil fuels will remain significant in both transportation and power generation for many decades to come. However, that doesn’t mean we can’t make further progress on energy transition. For instance, we are exploring options like renewable diesel and looking at carbon capture and solar projects in Rodeo. We're also starting to add hydrogen fueling stations in Europe with our partner Coop in Switzerland and are part of the Giga Stack consortium in the UK, which focuses on green hydrogen. Additionally, we have offshore wind projects producing hydrogen for the industrial sector in the Humber area. Hydrogen is an area we continue to research, but we think it's a long-term development with transportation fuel potential. There are challenges in technology and cost, as green hydrogen is significantly more expensive than traditional methods. We are also advancing battery technology, working on next-generation batteries and solid oxide fuel cells in our R&D areas. We have a lot underway in the energy transition space, but our immediate focus is on moving towards lower carbon intensity fuels, such as the projects at Rodeo and Rise. In Humber, we're producing about 1,000 barrels of renewable diesel daily, with plans to increase that to 4,000 to 5,000 barrels per day soon. We expect a project in San Francisco to come onstream in the first quarter of next year. Would you like to discuss that further?

Yeah. So we've announced the big project at Rodeo, but before that comes on, while we're still running a fuels refinery there, we're converting one of our hydrocrackers to be able to run soybean-based oils to make our renewable diesel, and that unit will produce about 9,000 barrels a day at a very attractive capital efficiency on that project. And that sets us up to begin setting up our supply chains into Rodeo and our marketing chains on the other side of that for the renewable diesel out of Rodeo. The next step we'll take is the commercial agreement we have with Rise, who is building two renewable diesel facilities, one in Reno, one in Las Vegas, where we will supply the feedstocks and take all of the renewable diesel offtake, be able to put that into the California market. That's our next step forward in late 2020 and 2021. And then we would expect to have the permitting done sometime in 2022 and begin the conversion of the Rodeo refinery to eventually have the largest renewable diesel facility in the world and make about 50,000 barrels a day of renewable diesel. Feedstocks for that, our premise to be about 80% of the harder-to-process feedstock. So that's used cooking oil, fats, greases, and other feedstocks from a variety of sources around the world. And Rodeo is really uniquely positioned because, A, we sit in the California market where there's a high demand for lower carbon intensity fuels. And secondly, we have water access to the Far East to bring in all of these difficult-to-process renewable feedstocks. So the second piece is that it's a hydrocracking facility. We have two high-pressure hydrocrackers there that will be converted to both process renewable feedstocks and very capital efficient. At the end of the day, we will convert the facility and build the pretreatment facilities for a total capital cost of about $1 per gallon per year of capacity. That's 50% cheaper than anything else we've seen announced and sometimes three times cheaper than some of the competing projects we've seen in that. So we feel really good that by 2024, we will be a major player in renewable fuels in California and other places in the United States.

I think just to highlight, the $750 million to $800 million, that's one of the biggest projects we have in the portfolio at this time. So we're making a substantial investment there.

Hi, guys. You mentioned about 80% lower CI feedstock and 20%, most likely soybean and canola. Generally, in the current market, what kind of discounts are these lower CI, harder-to-process feedstock carrying versus the soybean oil? So, soybean oil is trading at $0.33 per pound, like where are these harder-to-process feedstocks trading at a discount to soybean oil?

I think, Manav, there's a fair amount of variance from region to region on the feedstocks and the transportation cost to get them from point A to point B. So I think the important thing is, is that we have the flexibility as we operate to pick the lowest cost feedstock in the market. And it's similar to high complexity refining, where you've got a lot of flexibility on what feedstocks and what yields you have. We're building in with the pretreating capability the flexibility to take advantage of the lowest cost, most optimal feedstock in order to produce the renewable diesel. So, we're, I think, well-positioned in that regard.

Okay. A quick follow-up is you initially mentioned the multiple storms that hit you both in chemicals as well as the refining part. Is there any kind of opportunity cost you lost out because of all these hurricanes, or can you just give us a sequence of like which are the facilities that did get impacted by subsequent hurricanes that hit the Gulf Coast?

Yes, I'll take a shot at that. With the first one, if you recall, it seems like a long time ago now, but on August 25th, we shut down the Lake Charles facility for Hurricane Laura and ended up being down all the whole month of September because of the power infrastructure in the General Lake Charles region that was essentially completely destroyed. We did not start restarting that facility until early October. And in fact, we didn't have full power back into the refinery to be able to operate as anything that we wanted to until October 5th. Unfortunately, then on October 9th, Hurricane Delta came essentially right back up the same path. And while it was a lower intensity storm, we still had to shut back down and essentially start over. Power infrastructure held up a little better in that timeframe. So, about the middle of October, we started restarting the Lake Charles facility. So, today, we're back up and running there. We've still got a few units left to start, but we will be market dictating the rate. But we'll – everything that we want to be up will be up and running here within the next week or 10 days at Lake Charles. In Alliance, we shut down September 13 for Hurricane Sally, which was originally pointed right at Alliance. We got lucky with that one and that, of course, moved off a little bit, and we did not take a direct hit. We chose to keep Alliance down because we had some maintenance planned for October anyway, and rather than restart and shut back down for that, we just moved the maintenance back up. Maybe fortuitous, maybe only in 2020, can you say being down is fortuitous, but Hurricane Zeta came right through that area two nights ago. And so, we were already down, obviously, and didn't have to shut back down for that one. Power was out again in the area. We expect to get power back today or tomorrow to Alliance. But we had pulled forward some work that we wanted to get done there that was difficult to do in future turnarounds, and we anticipate continuing to execute that work sort of through mid-December and then position ourselves to be ready to restart Alliance in the new year, assuming the market conditions are there and giving us the signal that we need to bring on more capacity. We have enough refining capacity in the Gulf Coast, obviously, to cover all of our marketing needs right now and any commitments that we have to our customers. And we'll – as we gave guidance earlier, we'll let the market tell us what utilization ought to be in the first quarter.

And, Manav, just to follow-up on chemicals. So CPChem took down several of their facilities on the Gulf Coast in anticipation of those storm events. They were probably more fortunate than that. They really were not impacted. So everything is back up and running normal now.

Hey. Good morning, everyone. Greg, do you have an update on whether that potential $0.05 PE increase for October is going through? And do you expect to see the normal seasonal impact in PE later in the quarter, or do you think that low inventories could provide some support on pricing?

Yeah. I'll let Tim answer that.

Yeah. It looks like at this point in time that, that increase is going to get pushed. There's been a really nice run-up up to this point in time, and demand has been good, but we think it's more due to seasonality than it is anything else, which is usually like this time of the year, you see a seasonal effect in demand in the chems business.

I think when you look at margins, we had full-time margins of $0.18 in Q1, $0.10 in Q2, and $0.19 in Q3 based on IHS Markit margin data. Currently, they're at $0.28 to $0.29, which is above the mid-cycle average. This improvement has been fueled by solid global demand, particularly in Asia, Europe, and North America. Additionally, there have been impacts from hurricanes, as at one point, about 20% of the U.S. ethylene capacity was offline due to Hurricane Laura. This situation also led to lower inventories in ethylene, which is generally beneficial for margins. Looking ahead to the fourth quarter, we anticipate some seasonal weakness or a slowdown in the petrochemical sector, but we remain quite optimistic about the outlook for petrochemicals next year.

Sounds good. And then, just turning to renewable diesel. So thanks for the update on the feedstocks. I wanted to ask about the permitting in California. Normally, that's kind of a challenge. Do you anticipate an easier route this time because of the nature of the facility? Could you just address that?

Yeah, I think so. You're correct. It is always difficult to permit anything in California. And it is a very rote process at the end of the day, and there are many steps that we have to go through. The biggest permit that we have to get is a land use permit in Contra Costa County, and that will require an environmental impact statement and go through all that work. We took a very different approach as a company on this particular project, in that we made sort of a full-court press with many stakeholders in the state of California the day before we announced. So we had multiple conversations in Sacramento, everywhere from Governor Newsom's office to Cal EPA to CARB to local legislators to the local Contra Costa County, Board of Supervisors. And I would say that we were met with great enthusiasm for this property across the board from those that are going to be responsible at the end of the day for actually permitting it. And in the meantime, the permit is in. It's been deemed complete by Contra Costa County, which really starts the process for them. So they will hire independent third party to do the environmental assessment of that, and that is all beginning. So we're there and ready to help support them through that. We haven't seen really any opposition at this point to the project. And I think as people are understanding more and more the benefits of us doing this project, as we mentioned, the environmental benefits and NOCs, SOCs, and greenhouse gas reductions, we think the permitting process will flow through. And it's kind of a normal timeline and look forward to getting that permit in early 2022.

Theresa Chen from Barclays. Please go ahead. Your line is open.

Hi. Going back to some of the earlier comments on supply rationalization in the market and just thinking about the overall demand-supply balance for refining capacity, how do you view the probability-weighted quantity of supply that is new supply that's coming into the market in the Middle East and Asia?

Yes. So there's about 1 million barrels a day scheduled for 2020, and highly likely that some of that gets pushed out into 2021. We're seeing a slowdown in activity from a COVID perspective and its impact on labor, as well as capital cost reductions in the industry. So I think those barrels are going to get pushed out as we look today, there's not a real reason to rush any of these projects into service.

Got it. And turning back to the West Coast, thank you for all the color on the renewable diesel projects and your thoughts around that. I was curious to hear how you view the whole electrification theme. Given the recently ordered ban from Newsom's office and the 9 other states in the U.S. considering similar orders as well as the legislation produced in Congress mandating on the federal level. Can you talk about your views on these aspirations maybe meeting wall of reality?

So yes, I'll take a stab, and then Bob can help me because he's pretty active in this area. But I think these are aspirational goals. And I think that – I think the sign post we're going to watch for is when billions, if not trillions of dollars start flowing in infrastructure investments around distribution, power generation, etcetera, that you could truly electrify the fleets. So I'm probably more bullish on low carbon fuel standards as we think about it moving from California, Oregon, Washington State to maybe to the East Coast. And so I think the near term, easier things to do in terms of renewables that can lower carbon intensity. Those make sense, and you can earn good returns doing those projects. And I think the electrification is going to take a long time to get there.

Yes. And I think we would agree with the AFPM has got a statement out there that we would stand behind solid with you and that Governor Newsom doesn't actually have the authority to do what his aspirational executive order played out. And you just think about the logistics of banning ICE in California, but there are these states around the call of Arizona, Nevada, and Oregon that have car dealerships, too. So it's hard to understand how this actually becomes a reality when there really isn't enough electricity in California today for base demand.

Hey, good morning, team. Thanks for taking my questions.

Good morning.

Good morning, Jeff. First one around Alberta production limits being lifted in December. Want to get you a sense of what you think that might have an impact on Canadian crude differentials? And how it might cause you to shift your feedstock sourcing strategy, given you guys are one of the largest importers of the Canadian crude?

Hi, Benny, this is Brian. Hey, on Canadian crude, until just a few weeks ago, it was it's 4.2 million barrels of pipeline capacity out of Canada, and there wasn't 4.2 million barrels of production with some core issues and Polaris pipeline issues. Now we're starting to see the production come back. We're starting to see more production than pipeline capacity. So our view is, over time, it will take some time, we think that the differentials will start to widen out to variable rail rates, which we see about $13.50 off of WTI. So that's good for us. Every dollar is about $100 million for Phillips 66. So we continue to watch that. Actually, you've seen the past few weeks, the differentials were under $10, and now, as of yesterday, $10.60, so they're already starting to expand.

Great. Thanks for the color, yes. My follow-up is maybe for Greg. Greg, you and your team have always had a longer perspective of the world, and that often translates into how you run the business. And I think in the past, you have guided us to think about Phillips 66 generating a mid-cycle EBITDA of about $9 billion. Recognizing it's uncertain times, but just wanted to get your thoughts and maybe a degree of confidence if that mid-cycle level EBITDA generation is still reasonable? And if it is, how do we get back there? Is it refining rationalization alone? Can it get back to us there? Thanks.

Yes. I think shorter term, we still got a little bit of an inventory overhang we've got to work through. I mean, directionally, inventories have been moving the right way. So we feel relatively good about that. But I think that we won't clean it up in Q4. We may get a shot at it in Q1. But certainly, we think as we approach the summer driving season in Q2 that we'll have an opportunity to see margins more normalized for us. So we're talking about CPChem. Essentially, the market margin is above mid-cycle today. Our Midstream business is going to continue to perform well. Our Marketing and Specialty businesses have been a very consistent EBITDA business. So the real question, Mark, on the PSX portfolio is when does refining get back to mid-cycle conditions? And so we probably got a shot at doing that kind of mid-year next year. So Jeff or Bob, do you want to add anything to that?

Yes, I would just add that at CPChem, the addition of U.S. Gulf Coast 1 came at a time when margins were declining. And so the earnings power of that facility has really not been shown in a mid-cycle margin environment. So, I think that will be supportive of higher contributions from CPChem.

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

Thank you for your interest in Phillips 66. Before I wrap up, I'd like to thank Brent Shaw for his significant contributions to the Investor Relations Group. Brent's been promoted to another role at Phillips 66, and I'd like to welcome Shannon Holy to the IR team. Thank you very much for your time today, and please call Shannon or me with any questions.

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