Welcome to the Q2 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 Q2 earnings conference call. Participants on today's call will include Greg Garland, Chairman and CEO; Kevin Mitchell, Executive Vice President and CFO; Robert Herman, EVP Refining; Brian Mandell, EVP Marketing and Commercial; and Timothy Roberts, EVP Midstream.
Today's presentation material can be found on the Investor Relations section of the Phillips 66 website, along with supplemental financial and operating information. Slide two contains our safe harbor statement.
We will be making forward-looking statements during the presentation and our Q&A session. Actual results may differ materially from today's comments. Factors that could cause actual results to differ are included here, as well as in our SEC filings. With that, I'll turn the call over to Greg Garland.
Thanks, Jeff. Good morning, everyone, and thanks for joining us today. In the Q2 , we experienced an unprecedented disruption to our business from COVID-19, resulting in a challenging operating environment. Going into the Q2 , 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 well-being 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 has implemented the appropriate steps to protect our workforce consistent with CDC, national, state, and local directives.
We have safely and successfully operate 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 a focus on long-term value creation for our shareholders. In the Q2 , 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 Q1 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 FRAC II and III with the Freeport LPG Export Terminal. The FRACs will begin commissioning in the Q3 and start operations in the Q4 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 a storage expansion at the Clemens Caverns from nine million barrels to 16.5 million barrels in support of FRAC II and III and the CDG 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 demonstrated 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 four, we summarize our financial results. We reported a Q2 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 five.
This slide highlights the change in pre-tax income by segment from the Q1 to the Q2 . During the period, adjusted earnings decreased $774 million, driven by lower results across all segments. Slide six shows our midstream results.
Q2 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.
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 and Frac 1 were 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 seven. Q2 adjusted pre-tax income was $89 million, down $104 million from the Q1 .
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 Q2 , we received $272 million in cash distributions from CPChem. Turning to refining on slide eight. Refining Q2 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 Q2 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 Q2 clean product yield was 83%. Slide nine covers market capture. The 3-2-1 market crack for the Q2 was $7.47 per barrel, compared to $9.82 per barrel in the Q1 . 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 barrel. 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 Q2 pre-tax income was $293 million, $195 million lower than the Q1.
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 Q1 prices. Specialties decreased $20 million due to lower finished lubricants volumes.
We re-imaged 284 domestic branded sites during the Q2 , 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 Q2 were 160,000 barrels per day, in line with the prior quarter.
On slide 11, the Corporate and other segment had adjusted pre-tax 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 was 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 Q1 . Our ending cash balance was $1.9 billion.
We are 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 a half billion dollars 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 Q3 global O&P utilization rate to be in the mid-90s. In refining, crude utilization will be adjusted according to market conditions. In July, utilization has been in the low 80% range. We expect Q3 pre-tax turnaround expenses to be between $50 and $70 million. We anticipate Q3 corporate and other costs to come in between $220 and $230 million pre-tax.
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.
Thank you. We will now begin the question-and-answer session. As we open the call for questions, as a courtesy to all participants, please limit yourself to one question and a follow-up. If you have a question, please press star then one on your touch-tone phone. If you wish to be removed from the queue, please press the pound key.
If you are using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star then one on your touch-tone phone. Phil Gresh from JPMorgan, please go ahead. Your line is open.
Yes. Hello.
Hello. Good morning.
Good morning. 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. Anything additional you could share about that result and whether some of that was perhaps temporary in nature? You talked about inventory impacts. Yes, any additional color?
Phil. Good morning. This is Robert. The other in the Gulf Coast really came down to two items and both really timing. 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. That price environment where it's going the other way, we get a tailwind out of that.
In this particular quarter, we had rapidly rising prices during the quarter, and that hit us there. The second was a pretty sizable inventory impact in the Gulf Coast. We had two big turnarounds in the Q1 at Sweeny and Alliance, where we built a lot of inventory, and then we pulled that inventory down coming into the Q2 .
If you add up those two items alone in the Gulf Coast, it amounts to about $3 on the market capture. 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 when did waterborne barrels land, particularly at Bayway, in relationship to a very volatile crude market.
We saw effective feedstock costs in the Q2 to be pretty high coming into Bayway, just really from a timing between one Q and even month to month in the quarter as crude really moved around.
Phil, in aggregate, that feedstock impact on Atlantic Basin was not that different to the Q1 impact.
Yeah.
There's typically you see a negative on capture on feedstock in Atlantic Basin.
Would you say that we're past that at this point as we look forward, or is it something we still need to be thinking about?
I think on inventory moves around on us all the time, 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. 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 from most companies is still reasonably low. Inventories still need to be worked down, and we're going to be flipping into the winter gasoline mode as well. A lot of moving pieces, but I'm curious of your perspective, how you see this playing out.
Hey, Phil. I think it'll be a question of demand going forward. We see demand on gasoline right now at about 15% off, much better than the 50% we were seeing in April. On heating oil, we've talked to our big truck stop customers. They're seeing about 8% demand destruction. Finally, the product that's been hardest hit yet, we're seeing about 50%.
A 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. 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-19, we're seeing 95% demand on gasoline, 95% demand on distillate.
Again, we're optimistic that we can get through this second wave of COVID, that we can push up our demand in the U.S. I think refiners will continue to run at demand levels going forward.
I think 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. 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. Greg, I'm 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 the integrated model that we have. We still think that it's a value-add 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 our LPG export, and being able to take product into our chemicals business and then through the refining chain, we like that optionality that gives us in terms of investable opportunities.
Certainly, the earning streams that come out of those businesses are strong for us. We'll continue to think about this integrated business as a value-add business for us. There's no question that the pandemic's probably impacted all segments of this business, but it's not unique to us, I would say.
Yeah. Very clear. The follow-up is just your thoughts on Dakota Access, and how it's likely to play out from here, the firm's position on the ruling. 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.
Okay, yeah. This is Timothy Roberts. On that DAPL, let me address that first of all. Look, obviously, we're disappointed with the ruling that initially came out with regard to mandating an environmental impact study. Subsequently, the further ruling on that, which vacated the permit, which then led to a potential shutdown on August 5th on the pipe. Fortunately, it's been appealed to the D.C. Circuit Court of Appeals.
I think you guys are aware of that. We're waiting for that outcome currently. There's been a stay put in place while they're evaluating the case. Look, we think at this point the position we have are well-founded and certainly clearly disappointed by a position that's taken on a pipeline that has run for three years and has run safely and is truly the most economic and safe way to get hydrocarbons to the marketplace.
It is a little bit frustrating on that point, but we'll let the court play out at this point from there. One of the things that is also are challenged with a little bit is just the fact of the impact it's got on the region. When you look at it, both on the producers from the 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. To us, with COVID-19 going on, with the pandemic, it'd be bad without a pandemic.
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 it as, look, certainly the long-haul transmission business feels like it's been challenged a little bit, especially with COVID-19, the pandemic, oil shock.
All those things have caused us to pause. You've seen that through our actions by deferring a couple of our projects. We need more clarity. I think our producers need more clarity. Shippers need more clarity. We need to get a view on that.
From a midstream standpoint, if it's a good project, we're going to do it. 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. Subsequently, we're also deep in the NGL value chain.
We look at all those. We're not a one-trick pony at this point. We do look at it, and we have ways to shift our investment through those three different, very specific businesses in our midstream business. Yes, you may see us come off. We're certainly going to be a little more cautious as we look at transmission lines. 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 it hits the return threshold that we need. If those happen, of course, we're going to be interested in that. 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-$400 million of EBITDA that would scale that back.
I think that's one way of thinking about it. From a DAPL perspective, you can see from our historical disclosure, it has contributed about $250 million a year to PSXP. We own roughly 75% of PSXP at PSX. 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.
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. 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?
Specifically, how are you thinking about the balance between spending shareholder distributions, et cetera, given the changes in debt? The question's really about how you're thinking about financial priorities over the medium term.
Well, our view is mid-year, next year, we probably get back to something approaching mid-cycle for our company. As we do that, then 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 2-3 years.
We've got the 364-day facility. It's $1 billion, comes due in the Q1 of next year. Then in 2022, we've got another $2 billion kind of normal course debt coming due. You should think about us trying to pay between $1 billion-$3 billion of debt off in the next two to three years. As we start approaching mid-cycle conditions, then certainly pick back up with share repurchases.
The other thing I would say is our view is that investable opportunities in midstream in 2021 and 2022 are probably going to be less than what we would've anticipated. That's going to free up more capital to put towards debt repayment and shareholder distribution and stuff. Anyway, that's how I'm thinking about it at this moment in time.
Okay. That sounds good. My second question is about refining, and specifically how you guys are thinking about closures of refining capacity over the next few years. The reason that I ask is because I think during the last cycle, IEA's final tally of closures was about six to seven million barrels per day over the two to three years following the trough in the cycle.
We have seen recent announcements of closures in Asia. We've got IMO-related factors, and current refining economics aren't great either. It seems like we could be in the early stages of going back to that closure track as well. I just wanted 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.
Okay. Hey, Doug, it's Robert. I think we would agree to you that 2008 and 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. 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.
I think you'll see a lot of people make their moves early. 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 well know, even in a good environment, these projects tend to get delayed. 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.
Yeah, thank you. Good morning.
Morning.
If I could 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? I'm thinking pretty specifically the Gulf Coast here.
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.
Hey, Doug, this is Brian. On exports, if you looked at Q1 exports for gasoline and distillate were about little over 2.2 million barrels a day, which we would say is typical. In Q2, close to 1.6, which is about 30% off. In July, we're about 20% off. We're starting to come back, and we can see that in the marketplace. We can see Mexico's having a lot of 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. They're coming in and out for spot barrels. They would just turn 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 levels. 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 last couple of quarters. I think I might add on that, too.
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 are sitting, and we need to get those back into the export market to help clean up inventory levels in the business. That's the missing piece for PADD 3, I think.
I think the U.S. statistics, the DOE coming out weekly, that's kind of the most evident. 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, you want to take WCS part of the question?
On WCS, we've seen differentials in Q1 to Q2. Differentials came off about $9. From Q2 to Q3 is kind of baked in for about two-thirds of it. We'll see another $2 off. What we're seeing in Canada 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 or pipeline takeaway is greater than production. That's what's kept the differential rather tight. We think that will change going in the 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 arbs.
Okay, great. Thanks. 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, guidance is only in the mid-90s. I guess the way I'm thinking about it, why run so hard when things were weak, but running less so when things looked a little bit better?
What kind of underwrote the decisions in Q2 or the market conditions in Q2 that pulled such a high utilization? Should we think about you maybe build inventories that we can see sold later at better pricing?
Yeah, not really building inventory in the chemicals chain. If you go back to 2019 at ethane, to high-density polyethylene chain margin was $0.22. It was $0.18 in the Q1 , and it got to $0.10 on the Q2 , but actually dropped about $0.07 in May. Today we're pushing kind of $0.16. As you look across the U.S., Europe, and Asia, we've seen rising prices.
Spot prices in the U.S. are up $0.08, contracts up $0.05. Europe contracts up $0.08, and Asia spots up $0.055. 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. 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. Think automotive and others. On the consumer side, which is mostly where CPChem is, market facing, there's kind of two trends that are going on. One is hygiene.
Think about the wipes and the bleach and the detergent and then the hand sanitizer and all that. Those products across the world continue to sell strongly. The other is a term that the chemicals guys are calling nesting, that people aren't moving very far from the nest. They're staying home, they're cooking more, they're using more disposables, they're using more trash bags. They're buying more bottled water that's wrapped with plastic.
They're doing home improvement projects, so polyethylene paint cans and garden sheds. 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, which is all really positive for high-density demand. I think we're constructive on the demand side, I'd say strong demand, weak to improving margins, and that's what we're running into.
Doug Leggate from Bank of America. Please go ahead. Your line is open.
Thanks. Good afternoon, everyone.
Good afternoon.
Kevin, I wonder if you could talk about your tolerance for debt on the balance sheet. Obviously, you're navigating the trough of the cycle, but where does the balance sheet stack up in terms of relative priorities for use of cash, and what do you see as the necessary headroom with the visibility of what walked through this morning so far?
Yeah. As I walked through the components of liquidity that we have available to us, we're still in a good shape in terms of if we need additional cash, we have availability through the different sources that I commented on earlier. As you 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. Typically, we don't talk about having to pay down debt as part of the capital allocation construct. It sort of works out okay for us because we've got the term loan, $1 billion on the term loan. That matures in the Q1 of next year.
We also have a half billion dollar floating rate note maturity also in the Q1 of next year. As you go into 2022, there's a $2 billion of notes coming due, and there's another half billion coming due in 2023. We have plenty of opportunity to deal with this over the coming next couple of years or so.
I think if we're able to take care of the 2021 maturities, that one and a half billion, I think we'll feel pretty comfortable with where the balance sheet is at that point. That will still have us at slightly higher debt than we had when we went into this. In the overall scheme of things, I think we'll feel pretty comfortable with where that puts us.
I appreciate the answer. Thanks, Kevin. Greg, I'm afraid I'm gonna take a bit of a different tack, given we're three months ahead of the election, I guess four months ahead of the election. The topic of carbon tax.
We've heard the majors articulate some support for the Baker Hughes plan amongst others, but it's appeared on the Democratic platform as a possibility that something that they might want to push in a new legislative setting. I'm just wondering what PSX official position is on a carbon tax, and I'll leave it there. Thanks.
Yeah. 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 needs to be done at Congress. They need to legislate a climate program. We prefer that, 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 cost associated with any climate program. I think it needs to be economy-wide, and it's got to be applicable to all sources of emissions.
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 needs to be market-based, it's predictable, and internationally competitive. 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. Your line is open.
Thank you. Good morning, guys. 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 they perhaps also have a Democratic administration. Is your view on that business change? 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 Robert kind of talk about what we're doing in renewables, and then I'll come back and address that question specifically.
Okay. Currently, we are in the 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 1,000 barrels a day of 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.
On the commercial front, right, we've committed to backing two renewable plants that are being built by a third party in Nevada. We'll supply them feedstock, and take 100% of the product off of those two plants. Between those two, that's about 15,000 barrels a day of renewable diesel that we'll have at our disposal to meet our own needs in California.
We've got a project in progress at our San Francisco refinery that will convert a hydrotreater 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 where 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, we canceled that project.
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, it's gonna be there long term.
We need to find a way to help meet the demand of the market for renewable diesel in particular. I think our approach at this point in time has been to partner, certainly, and to use existing assets where we can in a capital light mode, Paul. I still worry about the credit and how that credit price gets set.
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., and I think there's going to be a place in the portfolio for renewables.
Greg, do you have an idea, say, some kind of ceiling, how big is that business that you will be willing to accept in the long run as a percentage, let's say, for your overall asset or your cash flow? Or that you think that this business, I mean, is really just a niche and you don't want to be too big?
Well, our current view is that we would probably either build or partner to cover about what we view as 80% of our requirements, and we'd probably remain exposed for credits for about 20%. We haven't changed that strategy yet, Paul, but that's 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, does PSXP have to stand on its own financially in the unlikely event that DAPL is shut down? Would PSX be willing to entertain maybe some more supportive options than might otherwise be the case to help the MLP?
Hi, Justin, it's Kevin. Yeah. It's hard to speculate around activities that may or decisions that may or may not happen and how that will play out. Fundamentally, when you look at the MLP, it's got two levers at its disposal, right, in terms of helping its financial position. One is the distribution, and two is the level of capital spending.
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. There'll be more flexibility as you look into future years in terms of where CapEx needs to sit at the MLP. What I'd also say is you step back and look at PSXP, it goes into this in a very strong position.
The MLP last year generated was almost $1.3 billion of EBITDA. It's got a strong balance sheet, it's a strong credit rating, that's a function of you look at 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.
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 sort of sponsor support might be provided on an event that we don't know may happen around all of that. I think I'll probably just leave it there. One other comment, though, is also bear in mind, DAPL is one asset.
PSXP's got a great portfolio. It's predominantly fee-based driven assets. While DAPL is a very significant asset, it's a good asset. It is just one asset within the broader portfolio. 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?
Yeah.
Fair to look at, you probably want to look at CPChem on a year-to-date basis. The distributions were low in Q1, and they were high in Q2. It's probably more appropriate to think of it like that because in Q1, they under distributed from an earnings standpoint. That's the big driver of that undistributed equity earnings benefit that 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 wide footprint in retail and wholesale operations. I'm trying to understand a little bit of follow-up to Roger's question. Domestically, which are the regions where you are seeing the strongest demand recovery?
Domestically, which are the regions where either gasoline is lagging versus the average? Are there regions you actually think where the demand may never recover to the pre-pandemic levels?
Well, we took a look at that earlier this morning, in fact, and we're seeing that 15% demand destruction of gasoline. Actually, that's the same in each of our PADDs that we're operating in. We didn't see any difference in the PADDs 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 they're not 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. I think this is somewhat short-term.
By the middle of next year, I think people will be back to work, and it'll be normal, just like it has been.
A quick follow-up question again on the Canadian side. I mean, 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?
We've been importing from Canada roughly the same amount, a little over 500,000 barrels a day. We're limited on pipeline logistics, and that's kind of the 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. First on the DAPL front, understand that to PSX, in the event of a shutdown, it 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 crude by rail at Bayway and Ferndale?
Currently, we move by rail to Bayway and Ferndale about 70,000 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. As they get wider, we'll be in a position to move those extra barrels.
Got it. Brian, a follow-up to Manav's question on structural demand. 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. Are you seeing plateauing at 95%? Is it continuing to recover? Can you chalk that 5% up to structural losses? How should we think about that?
I think that's still effect of COVID. COVID's not gone in Germany and Austria, just like it isn't gone here in the U.S. We would expect that to get back to 100% at the point where we have some type of therapeutic or some kind of cure for COVID. At current rate, that isn't structural. People want to get out, they want to drive. 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. Mine's a sort of a two-parter, so I'll just leave it at the one with the two parts to it, and they're 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 in full operations.
The tie-in work is done on Sweeny. Throughput volumes look like they should at least pace product demand and crude demands are coming back up. 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.
Then from there, the second part then, if I think about sort of the trajectory, the snap back 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 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. Is that something that seems in scope for the back half of this year? Those two parts would be helpful to get some color on both. Thank you very much.
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. Q2 really does feel like it was the bottom, it's the trough.
Obviously, it's a little tough to kind of go out with this second wave of the pandemic. Certainly, we're going to work our way through that. 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, we're running. We have seen volumes have picked up, and we're near MVC levels currently, which is good, which is not where we were in the middle of the quarter, for the Q2 . That's directionally going in the right direction.
We see overall volumes through our NGL system, all of them are month-to-month are improving. 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 should see things start to normalize to a point where we're back in mid-cycle.
I think maybe the only other thing I'd add to that is, as you think about kind of Gray Oak Fracs 2, 3, those are pretty much fixed fee.
That's right.
Exposure there. Where we still have commodity exposure is really around the LPG export.
Yep.
Of course, in the Q2 , we had some downtime for the tie-in, so we ran the frac a little lighter and didn't get as many export barrels out. Also, the fees went down across the dock in the Q2 .
We do think that we'll see some improvement in terms of getting more volume across the dock and also some opportunity to increase dock fees. That's where the big exposure is. That's $100 million-$200 million probably, if you think about it in a total scope of the opportunity set for us.
Yeah. 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 from Simmons Energy. Please go ahead. Your line is open.
Great, thanks.
Good morning, Brian.
Morning. Maybe a couple quick follow-ups on refining. Despite the idling of MPC's Martinez Refinery, West Coast utilization rates are still kind of struggling from the troughs of the downturn relative to other regions.
Can you talk about maybe how regional demand fundamentals are driving a different recovery path that you see for utilization rates in the Gulf Coast versus the West Coast or East Coast?
Yeah, I think actually, if you look at our system across our different pads, we don't see that much difference in utilization, I think, PADD to PADD to PADD right now. In California in particular, right, if the conventional wisdom before the pandemic was we were a refinery long in California sometimes for market balance.
Today, we're something above that. 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 said we're in the low 80s across our system. That's pretty instructive for California also.
Okay. Thanks. Maybe on the marketing side, 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 Q3 as commodity prices have started to normalize. Maybe you can speak to further opportunities to inorganically build on your West Coast Retail JV from here.
I would say that we completed most of the West Coast Retail Joint Venture late last year, which was a fortunate time for us. We finished the rest earlier this month. We've taken back cast on the margins and on the value driven by the West Coast Joint Venture, and it's been about what we said it would be.
We're in about the $50 million-$60 million a year in terms of EBITDA for that Joint Venture. We're kind of happy about where it is. Of course, it's hard to tell during the COVID period. We think it's on track. 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. We're looking for opportunities to integrate, particularly on the West Coast and even more particularly in Mid-America where we have a 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.