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 in 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 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, and communities, maintaining safe and reliable operations, and ensuring the financial and operational strength of our Company. Our business is essential, and we're committed to safely providing critical energy products and services for our customers. Phillips 66 implemented 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 providing 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 a 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 achieved 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 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. 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 toward 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 was down during part of the quarter as planned tie-in work was completed to integrate Fracs 2 and 3. DCP Midstream adjusted 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.

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 additional 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 situation in the Gulf Coast mainly revolved around two timing-related factors. Approximately half of the impact was linked to product realizations as we utilized product in the Colonial Pipeline and other pipelines. In a rising price environment, we typically do not capture the full crack spread, while a declining price environment typically provides us with a benefit. This quarter, we experienced rapidly increasing prices that affected us. Additionally, we faced a significant inventory impact in the Gulf Coast due to two major turnarounds in the first quarter, Sweeny and Alliance, where we accumulated a lot of inventory, which we then reduced going into the second quarter. Altogether, these two factors account for around $3 on the market capture, and both stem from timing issues for us. Regarding feedstock costs on the East Coast, it was also a timing issue, particularly with wind and waterborne barrels, especially at Bayway in relation to a very volatile crude market. Consequently, we observed that feedstock costs in the second quarter were quite high when entering Bayway, primarily due to timing between the first quarter and even month-to-month fluctuations in the quarter as crude prices fluctuated.

But, Phil, overall, the impact of feedstock on the Atlantic Basin was not significantly different from what we saw in Q1. Typically, there is a negative effect on the capture of feedstock in the 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 believe that inventory fluctuates frequently, making it challenging to forecast future developments. Generally, when prices remain stable, like they have in recent weeks, we tend to dampen those 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 crack 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 for gasoline right now at about 15% off, much better than the 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 the planes and in the airport. So, we are optimistic that that will get better as the year progresses. It's interesting, if you 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 for gasoline, 95% demand for distillate. So, again, we're optimistic we can get through this wave of the second wave of COVID and 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 want to point out that we are approaching the fall season, which typically brings some seasonal effects related to school traffic, contributing roughly 5% to demand. Additionally, there may also be an ongoing impact on commuting patterns. We anticipate a robust harvest season this fall, which should help drive 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?

When considering our integrated model, we still believe that it adds value. I try not to let temporary events or pandemics influence our long-term strategy. We focus on capturing value through DCP, gas gathering, gas liquids, and integrating these processes through our fracs and LPG export, as well as into our chemicals business and refining chain. We appreciate the options this provides for investment opportunities. The earnings from these segments remain strong for us. We will continue to view our integrated business as a value-added operation. It's evident that the pandemic has affected all areas of our business, but this impact is not exclusive to us.

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 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. First, I want to address the recent ruling that requires an environmental impact study, which we find disappointing. The federal ruling required a permit that could potentially lead to a shutdown on August 5th for the pipeline. Thankfully, this has been appealed to the DC Circuit Court of Appeals, and we're currently awaiting that outcome. A stay has been put in place while the case is under review. We believe our positions are well-founded, and we're disappointed with the stance taken against our pipeline, which has operated safely for three years and is the most economical way to transport hydrocarbons. It's frustrating. We’ll let the court process unfold from here. Additionally, we are facing challenges due to the impact this situation is having on the region. It's affecting producers, state and local governments, communities, and businesses tied to the energy value chain and beyond. The ongoing COVID-19 pandemic exacerbates these economic challenges, particularly in specific areas of the country. Regarding our Midstream strategy, the long-haul transmission business has faced challenges due to the pandemic shock, leading us to pause on some projects. We need more clarity for ourselves and our shippers. If a project is solid, we will pursue it. We have a diverse Midstream business encompassing crude transportation, clean product terminals, and the NGL value chain, allowing us to shift investments across these areas. We will proceed cautiously with transmission lines, but we won’t shy away from good projects backed by long-term commitments from reliable partners. If those opportunities aren’t available, we will seek other ways to enhance our integration within the 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, 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, a $1 billion, that 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 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, the 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-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 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. Your line is open.

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. In the first quarter, our exports of gasoline and distillates averaged slightly over 2.2 million barrels per day, which is typical for the second quarter. In contrast, we've seen a decrease to around 1.6 million barrels per day, roughly 30% lower, and in July, we're about 20% off. However, we are beginning to recover, and that is becoming evident in the marketplace. Mexico is experiencing refinery issues, with utilization dropping to about 35% in June, likely remaining in the high 20s in July, along with additional complications. We’ve noticed their presence in the market, looking for spot barrels that were previously available. Retail contacts have indicated that some volumes have rebounded to pre-COVID levels. For Phillips 66, our exports in the second quarter totaled 160,000 barrels, consistent with the first quarter. Generally, our exports are opportunistic, and we see better domestic opportunities arising in the coming 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 observed a decrease in differentials of about $9 from Q1 to Q2. For Q3, we expect an additional decrease of around $2, which is somewhat anticipated. In Canada for August, approximately 200,000 barrels are offline due to production maintenance, with another 200,000 barrels shut in. This situation means that pipeline capacity is exceeding production, keeping the differential relatively tight. However, we expect this to change in the coming months of September and October, with production exceeding pipeline takeaway capacity, leading to a widening of the differential toward 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?

We haven't really built up inventory in the Chemicals segment. Back in 2019, ethane’s margin was $0.22. It dropped to $0.18 in the first quarter and fell to $0.10 in the second quarter, hitting a low of about $0.07 in May. Currently, we're around $0.16. In the U.S., Europe, and Asia, we're seeing increasing prices, with U.S. spot prices up $0.08, contracts up $0.05, European contracts up $0.08, and Asian spot prices up $0.055. This price movement is largely due to rising crude prices and strong demand for consumer products. When we look at the petrochemicals business, the consumer segment is performing quite well, while the durables segment is still facing challenges but showing improvement, particularly in areas like automotive. On the consumer side, which is primarily where CPChem operates, we see two trends. One is hygiene products—such as wipes, bleach, detergent, and hand sanitizer—continuing to sell well globally. The other is a trend referred to as nesting, where people are spending more time at home, cooking and using more disposables, trash bags, and plastic-wrapped bottled water. They are also engaging in home improvement projects, buying polyethylene paint cans and garden chairs, as well as spending on outdoor activities like kayaks, coolers, and camping gear. This suggests a positive outlook for high-density demand. Therefore, we're optimistic about demand, though margins remain weak to improving.

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 walked 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 going to take a slightly different approach considering we’re just a couple of months away from the election. Regarding the carbon tax, we have heard major companies express some support for the Baker-Shultz plan, among others. It's also appearing as a possibility on the Democratic platform for new legislation. I'm curious about PSX’s official stance on the carbon tax, and I'll stop there. Thank you.

We haven't taken an official stance on a carbon tax because we need to understand the specifics of the policy. Our perspective is that it should be legislated by Congress to establish a climate program, which we prefer over a fragmented system of state and local regulations that is less efficient for us. There are several key aspects we look for in any program. Transparency is crucial for consumers to grasp the impacts and costs associated with any climate initiative. It should be applicable across the entire company and economy, covering all sources of emissions. Additionally, it must acknowledge the significant role of oil and gas for many years ahead. It needs to be market-based, predictable, and competitive on an international scale. Given these considerations, we would support a carbon tax if that is the approach Congress decides to take.

Paul Cheng from Scotiabank, please go ahead.

I have a couple of questions. Greg, previously you mentioned your reservations about the renewable diesel business due to the government mandate. In light of the pandemic and the current Democratic administration, has your perspective shifted? If so, how significant do you think that business could be in the long run?

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.

Currently, we are involved in the renewables sector at our Humber refinery, where we've been processing used cooking oil for about a year. We are co-processing this in our cat cracker, producing approximately 1,000 barrels of renewable diesel daily. We are working on a project to increase that production to around 4,000 barrels a day, focused on logistics for getting the material into the plant, as we can easily run it. On the commercial side, we are supporting two renewable plants being developed by a third party in Nevada, providing feedstock and taking 100% of the output from these facilities. This will give us an additional 15,000 barrels a day of renewable diesel to fulfill our needs in California. Moreover, we have a project underway at our San Francisco refinery to convert a hydro treater for renewable feedstocks, expected to yield another 9,000 barrels a day of renewable diesel. Beyond these initiatives, we are continuing engineering efforts to determine the feasibility of expanding renewable capacity throughout our system. We also had a significant project planned at our Ferndale refinery in Washington state for 18,000 barrels a day of renewable diesel, but we had to cancel it due to permit uncertainties in that area. Nonetheless, we are still actively exploring options on the West Coast, Gulf Coast, and other facilities to expand our renewable efforts. We firmly believe that the demand for renewable energy is substantial and will persist in the long term, necessitating our commitment to meet the market's need for renewable diesel specifically.

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.

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 the event 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. It’s difficult to predict potential activities or decisions and their outcomes. However, fundamentally, the MLP has two main ways to improve its financial position: the distribution and the level of capital spending. This year, capital spending is quite high, but many of those projects will conclude by the end of the year. Consequently, there will be greater flexibility regarding CapEx in future years. On a broader note, PSXP is entering this situation from a solid standpoint. The MLP generated nearly $1.3 billion in EBITDA last year, has a robust balance sheet, and a strong credit rating. This reflects the fair dealings that have occurred between PSX and PSXP over the years, benefiting both parties. We have also implemented a conservative financial strategy to maintain the balance sheet at PSXP, putting it in a favorable position. It’s quite challenging to predict the nature of potential sponsor support given uncertainties. I'd like to emphasize that DAPL is just one asset; PSXP has a diverse portfolio primarily based on fee-driven assets. While DAPL is significant, it is one component of a larger portfolio. We are confident that PSXP will navigate this situation effectively.

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. It's reasonable to consider CPChem on a year-to-date basis. The distributions were high in the first quarter and especially in the second quarter. It's better to view it this way since there was an undershooting in the first quarter regarding earnings, which significantly contributed to the under-distributed equity earnings benefit. This is reflected in 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 point 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 kind of limits for Canada crude exported out of the West Coast.

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.

I believe that COVID is still a factor; it hasn't disappeared in Germany and Austria, just as it hasn't here in the U.S. We anticipate returning to 100% once we have a therapeutic solution or cure for COVID. However, at the current pace, this situation remains impactful. People are eager to go out and drive, so we think we're experiencing the ongoing effects of COVID-19.

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

Hi. Thank you for the question. It's a two-part inquiry, both concerning Midstream. I’d like to understand better the current situation. It seems like there are a lot of components to consider, but with Gray Oak fully operational and the tie-in work at Sweeney completed, throughput volumes appear to be aligning with product demand, and crude demands are on the rise. It seems that the second quarter should mark the lowest point for the year based on our current perspective. I would appreciate your thoughts on whether that is a reasonable assumption. The second part involves the path to returning to the earnings levels we saw in the latter half of last year or the first quarter of this year. To what extent is this rebound driven by volume compared to margin? I recognize the interrelation between the two. If you could provide insights on the per Boe margin trends as volumes return and how that could lead to exceeding $400 million in quarterly earnings, that would be helpful. Is this a plausible expectation for the latter half of this year? Your insights on both parts would be greatly appreciated.

Regarding our systems and related activities, particularly with Gray Oak, I can confirm that you are correct. The second quarter appeared to be the low point. Although it's challenging to navigate the second wave of the pandemic, we are confident that we will manage through it. We have observed gradual improvements throughout the quarter. Currently, we have a lot of ongoing activity, and I'm happy to report that Gray Oak is operational. We have noticed an increase in volumes, and our global situation is improving compared to the middle of the second quarter. Overall, the volumes in our NGL system are steadily rising month over month, and we feel optimistic about this trajectory. However, the duration of the recovery remains a concern. We believe that by the middle of next year, we will see banks start to normalize, bringing us back to a mid-cycle state.

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 fees. 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 getting 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.

Maybe a couple quick 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 a 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 a 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 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 Middle America, where we have large refining business.

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.