Welcome to the Second 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 a question-and-answer session. Please note that this conference is being recorded. I will now turn the call over to Jeff Dietert, Vice President, Investor Relations. Jeff, you may begin.

Good morning and welcome to Phillips 66's second quarter earnings conference call. Participants on today's call will include Greg Garland, Chairman and CEO; Kevin Mitchell, Executive Vice President and CFO; Bob Herman, EVP, Refining; Brian Mandell, EVP Marketing and Commercial; and Tim Roberts, EVP, Midstream. Today's presentation material can be found on the Investor Relations section of the Phillips 66 website, along with supplemental financial and operating information. Slide 2 contains our Safe Harbor statement. We will be making forward-looking statements during the presentation and our Q&A session. Actual results may differ materially from today's comments. Factors that could cause results to differ are included here, as well as in our SEC filings. With that, I'll turn the call over to Greg Garland.

Thanks, Jeff. Good morning, everyone, and thanks for joining us today. In the second quarter, we experienced the unprecedented disruption to our business from COVID-19, resulting in a challenging operating environment. Going into the second quarter, we anticipated demand for our products would be weak as states were under lockdown and people were working remotely. Across our businesses, we've seen demand recovery from the trough, although uncertainty remains for the second half of the year. We continue to focus on the wellbeing of our employees, their families, communities, maintaining safe and reliable operations and ensuring the financial and operational strength of our Company. Our business is an essential business, and we're committed to safely providing critical energy products and services for our customers. Phillips 66 implemented the appropriate steps to protect our workforce, consistent with CDC, national, state and local directives. We have safely and successfully operated our facilities in support of our commitment to provide essential services. During the quarter, we issued $2 billion of senior notes and increased our term loan capacity by $1 billion. We expect to exceed $500 million in cost reductions and reduce consolidated capital spending by $700 million this year. These actions protect the security of the dividend and our strong investment grade credit rating as we navigate this challenging business environment. We will continue to exercise disciplined capital allocation with the focus on long-term value creation for our shareholders. In the second quarter, we had an adjusted loss of $324 million or $0.74 per share. We generated $764 million of operating cash flow and returned $393 million to our shareholders through dividends. During the quarter, we achieve strong safety performance. We continue to strive toward a zero incident, zero accident workplace. We're executing our strategy and progressing major growth projects. The Gray Oak Pipeline commenced full operations from West Texas and the Eagle Ford to the Texas Gulf Coast, marking the completion of the project. Phillips 66 Partners has a 42.25% interest in Gray Oak Pipeline. Gray Oak connects to multiple refineries and export facilities in the Corpus Christi area, including the South Texas Gateway Terminal. The first dock and eight tanks totaling 3.4 million barrels of storage capacity have been commissioned. In July, the first crude oil tanker was loaded for export. Marine operations, including the second dock are expected to ramp up by 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 the 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. At the Sweeny Hub, we recently completed the planned tie-in work to integrate fracs 2 and 3 with the Freeport LPG export facility. The fracs will begin commissioning in the third quarter and start operations in the fourth quarter of 2020. Fracs are backed by long-term customer commitments. Upon completion, Sweeny Hub will have 400,000 barrels a day of fractionation capacity. Also at the Sweeny Hub, Phillips 66 Partners recently completed storage expansion at the Clemens Caverns from 9 million barrels to 16.5 million barrels in support of fracs 2 and 3 in the C2G Pipeline. In Marketing, the West Coast retail joint venture recently closed on a previously announced acquisition of 95 sites, bringing the total to approximately 680 sites. The joint venture enables increased long-term placement of our refinery production and increases our exposure to retail margins. In closing, I'd like to thank our employees for their focus on safe, reliable operations, for their demonstrating commitment and capability to be smart and agile, finding new ways of working together with a determined purpose towards value-creation and for living our values of safety, honor and commitment in what has been a very disruptive and challenging environment. With that, I'll turn the call over to Kevin to go through the financial results.

Thank you, Greg. Hello, everyone. Starting with an overview on slide 4, we summarize our financial results. We reported a second quarter loss of $141 million. We had special items amounting to $183 million. After excluding these items, we had an adjusted loss of $324 million or $0.74 per share. Operating cash flow was $764 million, which included a $94 million working capital benefit. Adjusted capital spending for the quarter was $901 million, including $684 million for growth projects. We returned $393 million to shareholders through dividends, and we ended the quarter with 437 million shares outstanding. Moving to slide 5, this slide highlights the change in pre-tax income by segment from the first quarter to the second quarter. During the period, adjusted earnings decreased $774 million, driven by lower results across all segments. Slide 6 shows our Midstream results. Second quarter adjusted pre-tax income was $245 million, a decrease of $215 million from the previous quarter. Transportation adjusted pre-tax income was $130 million, down $70 million from the previous quarter. The decrease was due to lower pipeline and terminal volumes, driven by lower refinery utilization. In addition, equity affiliate earnings decreased due to lower pipeline throughput volumes, consistent with lower U.S. oil production and reduced product demand. NGL and other delivered adjusted pre-tax income of $83 million. The $96 million decrease from the prior quarter was due to lower margins and volumes at the Sweeny Hub, as well as inventory impacts. The Freeport LPG export facility averaged 11 cargoes per month, and the fractionator ran at 92% utilization. Freeport from Frac 1 were down during part of the quarter as planned tie-in work was completed to integrate Fracs 2 and 3. DCP Midstream adjust the pre-tax income of $32 million was down $49 million from the previous quarter. The decrease reflects lower hedging impacts, driven by improved commodity prices. Turning to Chemicals on slide 7. Second quarter adjusted pre-tax income was $89 million, down $104 million from the first quarter. Olefins and Polyolefins adjusted pre-tax income was $106 million. The $87 million decrease from the previous quarter is due to lower polyethylene and normal alpha olefins margins, driven by lower sales prices and higher feedstock costs. This was partially offset by record polyethylene sales volumes. Global O&P utilization was 103%. Adjusted pre-tax income for SA&S decreased $1 million. During the second quarter, we received $272 million in cash distributions from CPChem. Turning to Refining on slide 8. Refining second quarter adjusted pre-tax loss was $867 million, down from an adjusted pre-tax loss of $401 million last quarter. The decrease was due to lower realized margins and volumes partially offset by lower turnaround costs. Realized margins for the quarter decreased by 63% to $2.60 per barrel. Lower Gulf Coast realized margins were due to clean product realizations in a rising price environment during the second quarter and inventory impacts. In the central corridor, lower realized margins reflect narrowing Canadian crude differentials. Crude utilization was 75%, compared with 83% last quarter. Refining runs were reduced due to lower clean product demand. Pre-tax turnaround costs were $38 million a decrease of $291 million from the previous quarter. The second quarter clean product yield was 83%. Slide 9 covers market capture. The 3:2:1 market crack for the second quarter was $7.47 per barrel, compared to $9.82 per barrel in the first quarter. Realized margin was $2.60 per barrel and resulted in an overall market capture of 35%. Market capture in the previous quarter was 72%. 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 $5.56 per barrel and the gasoline crack declined by $0.73 per barrel. Losses from secondary products of $0.95 per barrel improved $0.37 per barrel from the previous quarter due to lower crude prices. Losses from feedstock were $0.67 per barrel, a decline of $0.46 per barrel from the prior quarter due to narrowing Canadian crude differentials. The other category reduced realized margins by $2.22 per mile. This was $2.05 per barrel lower than the prior quarter, driven by lower clean product realizations. Moving to Marketing and Specialties on slide 10. Adjusted second quarter pretax income was $293 million, $195 million lower than the first quarter. Marketing and Other decreased $175 million. The decrease primarily reflects lower volumes, driven by COVID-19-related demand impacts as well as lower realized margins due to rising product prices in the quarter, compared with falling first quarter prices. Specialties decreased $20 million due to lower finished lubricants volumes. We reimaged 284 domestic branded sites during the second quarter, bringing the total to approximately 4,720 since the start of the program. In our international marketing business, we reimaged 29 European sites, bringing the total to approximately 120, since the program's inception. Refined product exports in the second quarter were 160,000 barrels per day, in line with the prior quarter. On slide 11, the Corporate and Other segment had adjusted pretax costs of $224 million, an increase of $27 million from the prior quarter. The increase is primarily due to higher net interest expense and employee-related expenses, partially offset by lower environmental expense. Slide 12 shows the change in cash for the year. We started the year with $1.6 billion in cash on our balance sheet. Cash from operations was $1.4 billion, excluding working capital. There is a working capital use of $425 million. Consolidated debt increased by $2.7 billion. Year-to-date, we issued $3.2 billion of debt, including $1 billion drawn on a term loan facility and $2 billion of senior notes. We paid off approximately $500 million of maturing debt. Year-to-date, adjusted capital spending is $1.8 billion. Capital spending will be significantly less in the second half of the year. We expect 2020 adjusted capital to be approximately $2.9 billion as we continue to optimize our capital program. We returned $1.2 billion to shareholders through $789 million of dividends and $443 million of share repurchases completed in the first quarter. Our ending cash balance was $1.9 billion. We're focused on conserving cash and maintaining strong liquidity in the current environment. At June 30th, we had $8.4 billion of liquidity, reflecting $1.9 billion of consolidated cash, $1 billion of undrawn term loan capacity and available credit facility capacity of $5 billion at Phillips 66 and $0.5 billion at Phillips 66 Partners. This concludes my review of the financial and operating results. Next, I'll cover a few outlook items. In Chemicals, we expect the third quarter global O&P utilization rates to be in the mid-90s. In Refining, crude utilization will be adjusted according to market conditions. In July, utilization has been in the low 80% range. We expect third quarter pretax turnaround expenses to be between $50 million and $70 million. We anticipate third quarter corporate and other costs to come in between $220 million and $230 million pretax. Finally, we are not providing effective tax rate guidance for 2020 due to the range of potential impacts the COVID-19 pandemic may have on our business. With that, we’ll now open the line for questions.

[Operator Instructions] Phil Gresh from JPMorgan. Please go ahead. Your line is open.

First question I had was digging into the refining margin performance a little bit deeper. In particular, looking at your slides, there were two areas that seemed like the biggest headwinds in the quarter. One was feedstock in the Atlantic Basin, and the other was this other category on the Gulf Coast. Kevin, I know you gave a little bit of color there already. But, anything additionally you could share about that result and whether some of that was perhaps temporary in nature. You talked about inventory impacts. So, yes, any additional color?

Yes. Phil, good morning. This is Bob. The other in the Gulf Coast really came down to two items in both through timing. So, about half of it was due to product realizations as we put product into the Colonial Pipeline and other pipelines. In a rising price environment, we tend not to capture all the crack. And that price environment where it's going the other way, we get a tail wind out of that. In this particular quarter, we had rapidly rising prices during the quarter and that hit us there. And then, the second was a pretty sizable inventory impact. In the Gulf Coast, we had two big turnarounds in the first quarter, Sweeny and Alliance, where we built a lot of inventory and then we pulled that inventory down, coming into the second quarter. So, if you add up those two items alone in the Gulf Coast -- it amounts to about $3 on the market capture. So, both of those really come back to a timing issue for us. On feedstock cost on the East Coast, again, it was a little bit of a timing issue with wind and waterborne barrels, land, particularly at Bayway in relationship to a very volatile crude market. So, we saw effective feedstock costs in the second quarter to be pretty high, coming into Bayway, just really from a timing between 1Q and even month-to-month in the quarter as crude really moved around.

But, Phil, in aggregate, that feedstock impact on Atlantic Basin was not that different to the Q1 impact. There's typically -- you see a negative on capture on feedstock in Atlantic Basin.

So, would you say that we're past that at this point as we look forward, or is it something that you still need to be thinking about?

I think, on -- inventory moves around on us all the time, and it's always hard to predict what's going to happen. Typically when prices are more stable, like we've been seeing the last couple of weeks, we tend to mute those kind of effects.

Okay. And my follow-up question would just be a bigger picture question on refining fundamentals. How are you guys envisioning the way the second half of the year might play out? Obviously, we do have soft crash spreads. Now here in July, utilization guidance for most companies is still reasonably low. Inventory is still needed to be worked down. And we're going to be slipping into the winter gasoline mode as well. So, a lot of moving pieces. But, I'm curious, your perspective, how you see this playing out?

Hey Phil. I think, it would be a question of demand going forward. We see demand on gasoline right now at about 15% off, much better than a 50% we’ve seen in April. On heating oil, we talked to our big -- customers, they're seeing about 8% demand disruption. And then, finally, the product that’s been hardest hit, jet, we're seeing about 50%. Number of us here in the room have been flying on commercial flights recently. And you can see the pickup on both, on the planes and in the airport. So, we are optimistic that that will get better as the year progresses. It's interesting, if to look at our 1,000 stores in Germany and Austria where Germany and Austria didn't have a hard second wave of COVID, we're seeing 95% demand on gasoline, 95% demand on distillate. So, again, we're optimistic, we can get through this wave of -- the second wave of COVID that we can push up our demand in the U.S. And I think that refiners will continue to run demand levels going forward.

I might add that we're coming up on the fall season and there's some seasonal impacts driving to and from schools is in rough numbers about 5% of demand, and there's probably a carryover impact on commuting as well. So, I think that will have an influence. We're expecting a strong planting season -- or excuse me harvest season this fall, as well to support distillate demand.

Neil Mehta from Goldman Sachs. Please go ahead. Your line is open.

Hi, team. Thanks for taking the question. I guess, the first question is about the integrated business model and the value of operating in multiple different businesses. I think, over the course of the cycle, we've definitely seen that. It's been a benefit for Phillips 66. But, Greg, curious on your perspective, especially in light of the fact you have one of your large competitors monetizing some parts of their business?

Well, you think about integrated model that we have, we still think that there's a value added model, Neil. I try not to let single points in times -- or single point pandemics really influence our long-term thinking around this. When we think about the ability to capture that value, starting with DCP, gas gathering, gas liquids, integrating through our fracs and LPG export and being able to take product in, into our chemicals business and then through the refining chain. We like that optionality that gives us in terms of investable opportunities. But certainly, the earnings streams that come out of those businesses are strong for us. So, we'll continue to think about this integrated business as a value add business for us. There's no question, the pandemic’s probably impacted all segments of this business. But, it's not unique to us, I would say.

Yes, very clear. And then, the follow-up is just your thoughts on Dakota Access, how it's likely to play out from here, the firm's decision on any -- on the ruling? And then, the bigger picture question around Midstream is relative to what was laid out at the November Analyst Day, what's changed and any quantification of what's changed would be helpful too?

This is Tim Roberts. On that data, let me address that first of all. Look, obviously, we're disappointed with the ruling that initially came out with regard to mandating and environmental impact study. And then subsequently, the federal ruling on that which they needed the permit, which then led to a potential shutdown on August 5th on the pipe. Fortunately, it's been appealed to the DC Circuit Court of Appeals. I think, you guys are aware of that. So we're waiting for that outcome currently, and there's been a stay put in place, while they're evaluating the case. So, it'll -- look, we think, at this point, the positions that we have are well founded, and certainly clearly disappointed by a position that's taken on our pipeline. It has run for three years, and it has run safely. And it’s truly the most economic and safe way to get hydrocarbons to the marketplace. So, it is a little bit frustrating on that point. Now, we’ll let the court play out at this point from there. One of the things that is also little bit -- we are challenged with a little bit is just the fact, the impact it's got on the region. When you look at it, both on the producers, from state, local governments, communities, people that work in the energy value chain and those that don't who support businesses in the energy space. They're really getting impacted by this. And so, to us, with COVID-19 going on with the pandemic, it’d be bad without a pandemic, but with the pandemic, we just feel this is going to be tough economically on some very specific regions of the country. With regard to the Midstream strategy, I think I’d just characterize this. Look, certainly the long haul transmission business, it’s been challenged a little bit, especially with COVID-19, the pandemic or shock. All those things have caused us to pause. And you've seen that through our actions like deferring a couple of our projects. We need more clarity. I think, our producers need more clarity, shippers need more clarity. So, we need to get a view on that. From a Midstream standpoint, if it's a good project, we're going to do it. And when you look at the diversity of our business in our Midstream space. Yes, we've got crude transportation; yes, we're in clean products, as far as terminals and moving product out of refineries. And then, subsequently, we're also deep in the NGL value chain. So, we look at all those. We’re not a one trick pony at this point. When you look at, we have ways to shift our investment through those three different very-specific businesses in our midstream business. So, yes, you may see us come off, we're certainly going to be a little more cautious as we look at transmission lines. But, that doesn't mean, we're not going to do those. We're going to make sure it makes sense. We've got people who are willing to make long-term commitments that are good solid counterparties. And hence the returns were shorter than we need. So, those happen. Of course, we're going to be interested in that. But if not, we will find other ways to pivot and build out our integration within our Company.

Neil, just to quantify the Midstream, we reported $2.26 billion of EBITDA in 2019. At the Investor Day, we highlighted projects that could take that to $3 billion by 2022. The projects that we have deferred represent about $300 million to $400 million of EBITDA that would scale that back. And so, I think that's one way of thinking about it. From a DAPL perspective, you can see from our historical disclosure, it contributes or has contributed about $250 million a year to PSXP. We own roughly 75% of PSXP at PSX. So, the PSX impact is in the ballpark of about $200 million a year.

Doug Terreson from Evercore ISI. Please go ahead. Your line is open.

Good morning, everybody.

Good morning.

So, financially, the pandemic has obviously reduced financial flexibility and led to higher debt levels at a lot of companies, Phillips 66 included. Simultaneously, economic growth is expected to recover. And as it does, my questions are, what are the likely implications for capital management, which has been a positive hallmark for you guys over the years? And specifically, how are you thinking about the balance between spending, shareholder distributions, et cetera given the changes in debt? So, the question is really about how you're thinking about financial priorities over the medium-term?

Yes. Well, so, our view is, mid-year next year, we'd probably get back to something approaching the mid-cycle for our Company. And as we do that and we can kind of get back to a normalized framework as we think about the 60-40 allocation. I think, the other thing I would say is, clearly, taking on $3 billion of debt. There's going to be some priority to debt repayment over the next two to three years. We've got the 364-day facility, it comes -- it’s a $1 billion, comes due in the first quarter of next year. And then, in 2022, we've got another $2 billion kind of a normal course debt coming due. So, you should think about us trying to pay between $1 billion to $3 billion of debt off in the next two to three years. As we start approaching mid-cycle conditions and certainly pick back up with share purchases. The other thing I would say is, our view is that investable opportunities in Midstream in '21 and '22 are probably going to be less than what we would have anticipated. That's going to free up more capital to put towards debt repayment and a shareholder distribution stuff. So, anyway, that's how I'm thinking about it at this moment in time.

Okay. That sounds good. And then, my second question is about refining and specifically, how you guys are thinking about closures of refining capacity over the next few years. And the reason that I ask is because, I think during the last cycle, [indiscernible] final tally of closures was about 6 million to 7 million barrels per day over the two to three years, following the trough in the cycle. And we have seen recent announcements of closures in Asia. We've got IMO [ph] related factors and current refining economics aren't great either. So, it seems like we could be in the early stages of going back to that closure track as well. So, just want to see how you're thinking about how the supply side could be affected by this factor in coming years, if you think it will be meaningful?

Hey Doug. It’s Bob here. I think we would agree with you that 2008-2009 is kind of a good go by and we would expect rationalization across the globe since it really is a global business. Even before the pandemic, we expected to see significant rationalization in Europe and some quite frankly in the U.S. And so, we've seen that, right? We've got PES that's down, and I think everybody could agree that's not coming back. We've got other temporary closures right now. Whether they come back, probably depends a lot on how long the COVID-19 hangs in there. I guess, our bigger view would be we expected several million barrels to rationalize across the globe, before this. The pandemic only pushes it forward, and we probably get it sooner than later. So, I think you'll see a lot of people make their moves early. And, it may not happen ratably here because I think people will run maybe as long as they can with these assets, but they're going to run up against either really expensive turnarounds or some kind of regulatory impact in some parts of the world. And that's going to make a decision for them, I think.

Doug, I think, the other thing I would add is not only rationalization of existing facilities, but delays in new capacity additions with the significant capital spending reductions that have been put in place with the COVID impact on challenges getting labor. As you will know, even in a good environment, these projects tend to get delayed, but in the environment we're in today, they're likely to get delayed even more significantly.

Roger Read from Wells Fargo. Please go ahead.

If I can get two questions, kind of small questions on Refining and then one on Chemicals. On Refining, what do you think is happening or what do you think needs to happen in exports to kind of bring the market back, thinking pretty specifically the Gulf Coast here? And then, on the crude supply side with WCS specifically, how you see that coming in? Because that was obviously a big headwind in Q2. Just curious how you think of that for the second half of the year?

This is Brian. On exports, if you look at Q1, Q1 exports, the gasoline and distillate were about little over 2.2 million barrels a day, which we would say is typical in Q2, little close to 1.6, which is about 30% off and in July, we're about 20% off. So, we're starting to come back and we can see that in the marketplace. We can see Mexico's having refinery problems. In June, they were down about 35% utilization. We think, July, they’re probably in the high 20s, with more problems. We can see them in the marketplace that coming in and out for spot barrels, they were just turned barrels before. We've even talked to some folks in the retail business who have said that some of their volumes have come back to pre-COVID level. So, we're seeing better demand -- for Phillips 66, we exported in Q2 160,000 barrels. That was the same amount we exported in Q1. Typically for us at Phillips 66, it’s more opportunistic, and we've had better opportunities domestically over the next couple of quarters.

I think, I might add on that. I think, if you look at the distillate inventory overhang, it’s mostly in the Gulf Coast at this point, right. That's where the barrels were sitting in that. We need to get those back into the export market to help clean up inventory levels in the business, right? That's the missing piece for Pad 3 I think.

I think the U.S. statistics, the DOE coming out weekly, that's kind of the most evident. But, if you look at Asian and European distillate inventories, they've come off their highs and are improving at a faster pace than what we're seeing in the U.S.

Brian, do you want to take WCS part of the question?

On WCS, we've seen differentials in Q1 to Q2, differentials came off about $9 and from Q2 to Q3, Q3 is kind of baked in for about two-thirds of it, we'll see another $2 off. For what we're seeing in Canada and for -- in August, we're seeing about 200,000 barrels offline for production maintenance and about another 200,000 barrels shut-in. That means that production -- pipeline takeaway is greater than production. So, that's what's kept the differential rather tight. We think that will change going on -- going next few months in September and October. We think that production will be greater than the pipeline capacity takeaway. And we'll see the differential start to widen closer to rail arms.

Okay, great. Thanks. And then, on the Chem side, I just wanted to understand, margins were obviously weak in the quarter but you ran at 103%. Sounds like margins are probably better Q3 but guidance is only in the mid 90s. So, I guess the way I think about it, why run so hard when things were weak but running less so when things look a little bit better? What kind of underwrote the decisions in Q2 or the market conditions in Q2 to pull such a high utilization? And should we think about you maybe build inventories that we can see sold later at better pricing?

Yes, not really building inventory in the Chemicals segment. So, if you go back to 2019, ethane’s [Technical Difficulty] margin was $0.22, it was $0.18 in the first quarter and got to $0.10 in the second quarter but actually troughed about $0.07 in May. And today, we're pushing kind of $0.16. As you look across to the U.S., Europe and Asia, we’re seeing rising prices. So, spot prices in the U.S. are up $0.08, contracts up $0.05, Europe contracts up $0.08 and Asia spot $0.055. And so, there's been really good price movement. Part of that reflects a rising crude price environment, part of that reflects just really strong demand for consumer products. And so, I would say, if you bifurcate kind of the petrochemicals business into consumer and durables, the consumer part is doing really well. The durables is still challenging, but improving. So, think automotive and others. And on the consumer side, which is mostly where CPChem is, market facing, there's kind of two trains that are going on. One is hygiene. And so, think about the wipes and the bleach and the detergent and the hand sanitizer and all that. And those products across the world continue to sell strongly. And the other is a term that chemicals guys are calling nesting that people aren't moving very far from the nest or staying home, they’re cooking more, they're using more disposables, they are using more trash bags or buying more bottled water that’s wrapped with plastic. They're buying -- doing home improvement projects, so polyethylene paint cans and garden chairs. They're trying to find things to do outside of the house. So, they're spending more money on kayaks and coolers and camping materials and things like that. It's all really positive for high density demand. So, I think we're constructive on the demand side. And I would say strong demand, weak to improving margins, and that’s where we're running into.

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

So, Kevin, I wonder if you could talk about your tolerance for debt on the balance sheet. Obviously, you're navigating the cycle but, but where does the balance sheet stock up in terms of relative priorities for use of cash, and what do you see as unnecessary headwind with the visibility of what sort of is going on so far?

Yes. So, I walk through the components of liquidity that we have available to us, we're still in good shape in terms of, if we need additional cash, we have availability through the different sources that I commented on earlier. But as you sort of look beyond that and as we start to come out the other side of this from a prioritization standpoint, what you're going to see is that pay-down of debt will be in the near term a priority from a capital allocation standpoint. And typically we don't talk about having to pay down debt as part of capital allocation construct. And it still works out okay for us because we've got the term loan, $1 billion on the term loan. That matures in the first quarter of next year. We also have $0.5 billion floating rate note maturity, also in the first quarter of next year. And then, as you go into 2022, there's a $2 billion of notes coming due and there is another $0.5 coming due in 2023. So, we have plenty of opportunity to deal with this over the coming sort of next couple of years or so. I think, if we're able to take care of the 2021 maturities, like $1.5 billion, I think we'll feel pretty comfortable with where the balance sheet is at that point. That will still have us a slightly higher debt than we had when we went into this. But, in the overall scheme of things, I think, we'll feel pretty comfortable with where that puts us.

Greg, I'm afraid, I'm going to take a bit of a different track given we’re three months ahead of the election -- I guess two months ahead of the election. The topic of carbon tax. We heard the majors articulate some support for the Baker-Shultz plan amongst others. But, it's appeared on the Democratic platform as a possibility that something that they might want to push a new legislative from setting. So I'm just wondering what PSX’s official position is on carbon tax and I'll leave it there. Thanks.

Yes. We haven't had an official position on a carbon tax, Doug, partly because we need to see what the policy really is and what does it look like. I would say that our view is that it really -- it needs to be done at Congress, they need to legislate climate program. We prefer that. So, obviously to having a patchwork of state and local regulations, which is a lot less efficient for us. There's a few key things that we would be looking for in any program. First of all, transparency is really important for people. And I'm talking about consumers to be able to understand the impact and the costs associated with any climate program. I think it needs to be companywide, economy wide and it's got to be applicable to all sources of emissions. And also, it's got to recognize that oil and gas is going to have a big role to play for many years to come. It really used to be market based, it's predictable and internationally competitive. So, given all those boundary conditions, certainly we would support something around a carbon tax if that's the preferred method that comes out of the Congress.

Paul Cheng from Scotiabank, please go ahead.

Couple of questions. Greg, in the past, you have talked about renewable diesel business and have some reservation, because of the government mandate and all that. Just curious that with the pandemic and everything going on and perhaps also have Democratic administration, does your view on that change? And if yes, how big is that business that you may be willing to -- or that you will be targeting or that you may like in the long haul.

I'm going to let Bob kind of talk about what we're doing in renewables, and then I'll come back and address that question specifically.

Okay. So, currently, we are in a renewables business, over at our Humber refinery for the last year or. So, we've been processing used cooking oil, co-processing it in our cat cracker there and making about a 1,000 barrels a day renewable diesel. We've actually got a project in flight right now to raise that to about 4,000 barrels a day. It's around the logistics to get it into the plant. We don't have any problem running it. And on the commercial front, right, we've committed to backing two renewable plants that are being built by a third-party in Nevada. So, we'll supply them feedstock and take 100% of the product off of those two plants. So, between those two, that's about 15,000 barrels a day of renewable diesel that we'll have at our disposal to meet the needs -- our own needs in California. In addition, we've got our project in progress at our San Francisco refinery that will convert a hydro treater to run renewable feedstocks, make about another 9,000 barrels a day or so of renewable diesel. Beyond that, we continue to do the engineering to understand what does it make sense to build more renewable capacity across our system. As you know, we had a big project at our Ferndale refinery up in Washington state to make 18,000 barrels a day of renewable diesel. We could not get permit, certainty in that environment up there. So, we canceled that project. But that hasn't stopped us from continuing to evaluate options on the West Coast, the Gulf Coast and at our other plants as to where does it make sense to do more renewables. Our fundamental belief is the renewable need is there and it's going to be there long term. So, we need to find a way to help and meet the demand of the market for renewable diesel in particular.

So, I think, our approach at this point has been to partner certainly and to use existing assets where we can in a capital light mode. So, I still worry about the credit and how that credit price gets set. But, as you watch what's happening, particularly on the West Coast, low carbon fuel standard, moving up the entire West Coast, maybe to the East Coast of the U.S., I think there's going to be a place in the portfolio for renewables.

Great. So, you have say some [indiscernible] how big is that business that you will be willing to assess in the long-term as a percentage, let's say for your overall asset and your cash flow, or do you think that this business is really just that niche and you don't want it to be too big?

Well, our current view is, we would probably either build or partner to cover about what we view is 80% of our requirements, and we probably remain exposed for credits for about 20%. And we haven't changed that strategy yet, Paul. But, that's kind of our current our current views in this market.

Justin Jenkins from Raymond James, please go ahead. Your line is open.

Thanks. Good morning, everyone. I want to follow-up on Neil's question about Dakota Access earlier. I'm curious that PSXP has to stand on its own financially in like the events that DAPL is shut down or would PSX be willing to entertain maybe some more supportive options than might otherwise be the case, just to the MLP?

Justin, it's Kevin. Yes. So, it's hard to speculate around activities that may or decisions that may or may not happen and how that will play out. But fundamentally, when you look at the MLP, it's got two levers at its disposal, right, in terms of helping its financial position. And then, one is the distribution; and two is the level of capital spending. And as you know, the capital spending is pretty high this year. But, a lot of those projects are coming to an end over the course of this year. And so, there'll be more flexibility, as you look into future years in terms of what CapEx needs to sit at the MLP. But, what I'd also say, as you step back and look at the PSXP, it is in a -- it goes into this in a very strong position. So, the MLP last year generated, at least almost $1.3 billion of EBITDA. It's got a strong balance sheet, strong credit rating. And that's a function of -- it was all the transactions that have taken place between PSX and PSXP over the last several years, they've all been done on a very fair basis, that both works for the MLP and for the sponsor. And at the same time, you sort of lay on a conservative financial strategy and policy around how we've managed the balance sheet at PSXP, and it's actually in a really good position. It's really hard to speculate around what other -- what sort of sponsor support might be provided on event that we don't know may happen around all of that. So, I think I'll probably just leave it there. One other comment though is, also bear in mind, DAPL is one asset, so PSXP is a great portfolio. It's predominantly fee-based driven assets. And while DAPL is a very -- it's significant asset, it's a good asset, it is just one asset within the broader portfolio. And so, we're pretty confident that PSXP will be able to work its way through this whole situation.

Understood. I appreciate the answer, Kevin. I think second question is just a quick one for you as well on the cash flow statement, JV distributions were pretty high. You mentioned the CPChem distribution, is a good chunk of that one time in nature?

Yes. I think, it's fair to look at -- what you probably want to look at CPChem on a year-to-date basis, the distributions were in Q1, and they were high in Q2. And so, it's probably more appropriate to think of it like that because it was an under -- in Q1 they under distributed from an earnings standpoint. And that's a big driver of that under distributed equity earnings benefit. It shows up on the cash flow statement.

Manav Gupta from Credit Suisse, Please go ahead. Your line is open.

Hey, guys, a quick question. You have a very light footprint and retail and wholesale operations, and trying to understand a little bit of follow-up to Roger’s question. Domestically, which are the regions where you're seeing the strongest demand recovery? And domestically, which are the regions where either gasoline is lagging versus the average? And are there regions you actually think where the demand may never recover like to the pre-pandemic levels?

We took a look at that earlier this morning, in fact, and we're seeing that 50% demand destruction of gasoline, actually that's the same in each of our pads that we’re operating in. We didn't see any difference in the pads that we're operating in. I would say that it's hard to say at this 10 seconds whether we'll see continued demand destruction. I know, on the West Coast, there have been companies that announced that we've got back to work for a while, schools, we don't know when they're going to get back to work. My guess would be that in the future, people will get back to work. There's something about being at the office and the exchange of ideas at the office that makes that a more positive way to work. So, I think this is somewhat short term. By the middle of next year, I think people will be back to work and will be normal, just like it has been.

And a quick follow-up question again on the Canadian side. You have expenses, you are one of the biggest buyers of Canadian crude. In terms of volumes versus, May or -- April or May, what kind of increase in volumes from Canada are you seeing at this point of time, versus just two or three months ago?

So, we've been importing from Canada roughly the same amount, a little over 500,000 barrels a day. We're limited on pipelines, logistics, and that’s kind of limits for Canada crude exported out of the West Coast.

Thank you.

Theresa Chen from Barclays, please go ahead. Your line is open.

Hi. Thank you for taking my question. So, first on the DAPL front. I understand that to PSX, end of the event of a shutdown will be roughly $200 million per year of EBITDA. Can you talk about potential offsets in your system if differentials do blow out, you can import and accrued by rail at Bayway and Ferndale?

So, currently, we move by rail to Bayway and Ferndale by 75,000 barrels a day. We think we can get another 75% maybe up to 120,000 barrels a day of additional crude to both refineries from the Bakken. We're taking a look at differentials. And as they get wider, we'll be in a position to move those extra barrels.

Got it. And Brian, a follow-up to Manav’s question on structural demand. So, when you talk about the markets where things have progressed more steadily and recovering to -- close to normal, 95% of demand in Germany and Austria, for example. So, are you seeing like plateauing at 95%? Is it continuing to recover, can you talk about 5% up to structural losses? How should we think about that?

I think that's still affect of COVID you can -- I mean, COVID is not gone in Germany and Austria, just like it isn't gone here in the U.S. So, we would expect that to get back to 100% at the point where we have some type of therapeutic or some kind of cure to COVID. But at current rate, that is instructional. People want to get out, they want to drive. So, we think it's just the lingering effects of COVID-19.

Prashant Rao from Citi, please go ahead. Your line is open.

Hi. Thanks for taking the question. Sort of a two-part, so I'll just leave at the one with the two parts to it, and they are both on Midstream. I kind of wanted to get a sense of -- it feels like there's a lot of moving parts here, but you've got Gray Oak with full operations, the tie-in work is done on Sweeney. Throughput volumes look like they are -- should at least pace product demand and crude demands are coming back up. So, it feels really like 2Q should be sort of a bottom for the year from where we stand right now. I wanted to get your sense on, if that's sort of a fair assumption. And then, from there, the second part, then if I think about sort of the trajectory of the snapback towards getting back to earnings levels, where we were, back half of last year, at least or 1Q of this year. How much of that is volume-driven and what's the -- how much of that is more margin driven? I know, the two are interrelated. But, if you could help us to sort of think about per Boe margin as the volumes come back, how that should trend and ultimately get you north of $400 million on earnings per quarter. Does that is -- that something that seems in scope for the back half of this year? So, those two parts, it would be helpful to get some color on both.

The first part, on that with regard to our systems and so forth, when you look at Gray Oak and all the activity that we've got going on, I can say that you're right. Second quarter, really does seem like it was the bottom at the trough. Obviously, it's a little tough to kind of go out with the second wave of the pandemic. Certainly, we're going to work our way through that. But, we've seen things progressively move up through the quarter. So that I would say is -- we feel that way currently. We've got a lot of activity going on. We have seen, for example on Gray Oak, I'm pleased to tell you that we're up and running. We have seen volumes have picked up, and we're near and we see global [ph] currently, which is good, which is not where we were in the middle of the quarter, for the second quarter. So, that's directionally going in the right direction. When we see overall volumes through our NGL system, all of them month-to-month are improving. So directionally, we feel pretty good that it's moving in the right direction. It's the length of time it takes to recover. We still think the middle of next year is when you see banks start normalize to a point, where we're back in mid cycle.

I think, maybe the only thing I'd add to that. As you think about kind of Gray Oak Fracs 2, 3, those are pretty much fixed fee. So, there's not a lot of commodity exposure there. Where we still have commodity exposure is really around the LPG export. And of course in the second quarter, we had some downtime for the tie-in. So, we ran the frac a little lighter and didn't give export barrels out and also the fees went down across the dock in the second quarter. But, we do think that we'll see some improvement in terms of get more volume across the dock and also some opportunities to increase dock fees. So that's where the big exposure is. And that's more than the $200 million, probably, if you think about it in the total scope, the opportunity set for us.

And I think, Prashant, as you know these projects are underwritten by long-term shipper commitments that support the investment and the return on these projects.

Ryan Todd, Simmons Energy, please go ahead. Your line is open.

Maybe a couple quick of follow-ups on Refining. Despite the idling of MPC’s Martinez Refinery, what those utilization rates are still kind of struggling from the trough of the downturn relative to other regions? Can you talk about maybe how regional demand fundamentals are driving the different recovery paths that you see for utilization rates in the Gulf Coast versus the West Coast or East Coast?

Yes. I think actually, if you look at our system across our different pads, we don't see that much difference in utilization. I think pads is pad. Right now, I think, in California in particular, right, if the conventional wisdom before the pandemic was we were refinery long in California sometimes for market balance, today, we're something above that. So, even with Martinez down, the demands of the market don't require the refining system out there really to be running harder than we currently are. We're in the low-80s across our system, and that's pretty constructive for California also.

Okay, thanks. And then, maybe on the marketing side. The retail results have been relative bright spot and they were again this quarter. I wanted to ask how the outlook is looking in the third quarter, as commodity prices have started to normalize or maybe you can speak to further opportunities to organically build on your West Coast retail JV from here?

Obviously, we completed most of the West Coast retail joint venture late last year, which is fortunate time for us. We've finished the rest earlier this month. So, we've taken back cash on the margins and the value driven by the West coast joint venture, and it's been about what we said it would be in about 50 million to 60 million barrels -- $50 million to $60 million a year in terms of EBITDA, for that joint venture. So, we're kind of happy about where it is. Of course, it's hard to tell during the COVID period but we think it's on track. And we'll continue to take a look at opportunities to grow that joint venture and opportunities to integrate into our business. We think integration is very important as Greg mentioned earlier, and we're looking for opportunities to integrate, particularly on the West Coast and even more particularly in the Middle America, where we have large refining business.

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

Thank you, David. Thank all of you for your interest in Phillips 66. If you have additional questions after today's call, please contact Brent or myself. Thank you.

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