Greetings, welcome to Valero Q2 earnings conference call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is being recorded. I would now like to turn the conference over to your host, Homer Bhullar, Vice President, Investor Relations.
Good morning, everyone, and welcome to Valero Energy Corporation Q2 2020 earnings conference call. With me today are Joe Gorder, our Chairman and CEO, Lane Riggs, our President and COO, Jason Fraser, our Executive Vice President and CFO, Gary Simmons, our Executive Vice President and Chief Commercial Officer, and several other members of Valero senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at valero.com. Attached to the earnings release are tables that provide additional financial information on our business segments. If you have any questions after reviewing these tables, please feel free to contact our investor relations team after the call. I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release.
In summary, it says that statements in the press release and on this conference call that state that company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our filings with the SEC. Now, I'll turn the call over to Joe for opening remarks.
Thanks, Homer. Good morning, everyone. This year has been challenging in many aspects. The COVID-19 pandemic and the ensuing global economic downturn has affected the health and livelihoods of so many people, and it's had a severe impact on all businesses, including ours. As troubling as our circumstances may be from time to time, it's gratifying to see individuals stepping up selflessly helping those in need, whether it be by providing healthcare to those that are sick or food to those that are hungry. In this regard, our team is doing its part. As you probably know, Valero is part of the country's critical infrastructure. As such, our team continues to operate our plants, providing the fuel that our country needs to keep critical supplies and first responders moving.
I'm proud that we have not laid off, furloughed, or reduced the compensation of any of our 10,000 dedicated employees who continue to give generously, volunteering their time and working courageously and tirelessly through this difficult period. Our employees are our greatest asset in the heart of our company. Their health, safety, and wellbeing remain among our top priorities, and we'll continue to take the steps necessary to keep them safe, whether they work in the field or at our headquarters. In response to the COVID-19 pandemic-imposed shutdown, we had to make important operational and financial decisions. When the stay-at-home orders were first issued, we reduced our refinery and ethanol plant throughput rates to match product supply with demand. We saw demand in April bottom out at 50% of normal demand for gasoline, 70% for diesel, and 30% for jet fuel relative to the same period last year.
As the stay-at-home orders and travel restrictions eased through most regions of the U.S. during the Q2 , we saw gasoline and diesel demand recover to 85%-90% of normal, and jet fuel recover to 50% of normal. We also saw a recovery in product exports to Latin America and Europe in June. As a result, we prudently increased refining and ethanol throughput rates in step with the increase in product demand. We also took prudent actions to maintain our financial strength. We lowered our 2020 capital budget by $400 million, raised $1.5 billion of debt at attractive rates, secured an additional credit facility, which remains undrawn, and temporarily suspended the stock buyback program beginning in mid-March this year.
Through all of this, we've honored our commitment to capital discipline and maintained our dividend as demonstrated by our board of directors approving a quarterly dividend of $0.98 per share earlier this month. Notwithstanding project deferrals this year, we continue to invest for earnings growth and are making progress on strategic projects under development. The St. Charles Alkylation Unit, which is designed to convert low-value feedstocks into a premium alkylate product, is on track to be completed in the Q4 of this year. The Diamond Pipeline expansion and the Pembroke Cogen project are expected to be completed in 2021, and the Port Arthur Coker project is expected to be completed in 2023. We remain committed to the expansion of our low-carbon renewable diesel business. The Diamond Green Diesel expansion project is expected to be completed in 2021.
This project is expected to increase annual renewable diesel production capacity by 400 million gallons per year, bringing the total capacity to 675 million gallons per year. In addition, the Diamond Green Diesel continues to make progress on the advanced engineering review for a potential new 400 million gallons per year renewable diesel plant at our Port Arthur, Texas facility. As we focus on the path to recovery with improving product demand, we remain steadfast in the execution of our strategy, pursuing excellence in our operations, investing for earnings growth with lower volatility, and honoring our commitment to stockholder returns. We continue to prioritize our investment-grade credit rating and non-discretionary uses of capital, including sustaining capital expenditures and our dividend. This uncompromising focus on capital discipline and execution has served us well in the current pandemic-imposed downturn, and it should continue to position Valero well through the recovery and beyond.
With that, Homer, I'll hand the call back to you.
Thanks, Joe. For the Q2 of 2020, net income attributable to Valero stockholders was $1.3 billion, or $3.07 per share, compared to net income of $612 million, or $1.47 per share for the Q2 of 2019. Q2 2020 adjusted net loss attributable to Valero stockholders was $504 million, or $1.25 per share, compared to adjusted net income of $665 million, or $1.60 per share for the Q2 of 2019. Q2 2020 adjusted results exclude the benefit from an after-tax lower of cost or market, or LCM, inventory valuation adjustment of approximately $1.8 billion. For reconciliations of actual to adjusted amounts, please refer to the financial tables that accompany the release. Operating income for the refining segment was $1.8 billion in the Q2 of 2020 compared to $1 billion in the Q2 of 2019.
Excluding the LCM inventory valuation adjustment, the Q2 2020 adjusted operating loss for the refining segment was $383 million. Q2 2020 results were impacted by lower product demand and lower prices as a result of the COVID-19 pandemic. Refining throughput volumes averaged 2.3 million barrels per day, which was lower than the Q2 of 2019 due to lower product demand. Throughput capacity utilization was 74% in the Q2 of 2020. Refining cash operating expenses of $4.39 per barrel were $0.59 per barrel higher than the Q2 of 2019, primarily due to the effect of lower throughput rates. Operating income for the renewable diesel segment was $129 million in the Q2 of 2020 compared to $77 million in the Q2 of 2019. After adjusting for the retroactive blenders tax credit, adjusted renewable diesel operating income was $145 million for the Q2 of 2019.
Renewable diesel sales volumes averaged 795,000 gallons per day in the Q2 of 2020, an increase of 26,000 gallons per day versus the Q2 of 2019. Operating income for the ethanol segment was $91 million in the Q2 of 2020 compared to $7 million in the Q2 of 2019. Excluding the benefit from the LCM inventory valuation adjustment, the Q2 2020 adjusted operating loss for the ethanol segment was $20 million. Ethanol production volumes averaged 2.3 million gallons per day in the second quarter of 2020, which is 2.2 million gallons per day lower than the Q2 of 2019. The decrease in adjusted operating income from the Q2 of 2019 was primarily due to lower margin resulting from lower ethanol prices and lower throughput.
For the Q2 of 2020, general and administrative expenses were $169 million, and net interest expense was $142 million. Depreciation and amortization expense was $578 million, and the income tax expense was $339 million in the Q2 of 2020. The effective tax rate was 20%, which was affected by the results of certain of our international operations that are taxed at rates that are lower than the U.S. statutory rate. Net cash provided by operating activities was $736 million in the Q2 of 2020. Excluding the favorable impact from the change in working capital of $629 million, as well as our joint venture partner's 50% share of Diamond Green Diesel's net cash provided by operating activities, excluding changes in its working capital, adjusted net cash provided by operating activities was $38 million.
With regard to investing activities, we made $503 million of capital investments in the Q2 of 2020, of which approximately $240 million was for sustaining the business, including costs for turnarounds, catalysts, and regulatory compliance. Approximately $263 million of the total was for growing the business. Excluding our partner's 50% share of Diamond Green Diesel's capital investments, Valero's capital investments were approximately $448 million. Moving to financing activities, we returned $400 million to our stockholders in the Q2 of 2020 through our dividend, resulting in a year-to-date total payout ratio of 96% of adjusted net cash provided by operating activities. As of June 30, we had approximately $1.4 billion of share repurchase authorization remaining. On July 16th, our board of directors approved a quarterly dividend of $0.98 per share, further demonstrating our sound financial position and commitment to return cash to our investors.
With respect to balance sheet at quarter end, total debt and finance lease obligations were $12.7 billion, and cash and cash equivalents were $2.3 billion. The debt to capitalization ratio net of cash and cash equivalents was 33%. At the end of June, we had $5.7 billion of available liquidity excluding cash. Turning to guidance, we still expect annual capital investments for 2020 to be approximately $2.1 billion, which includes expenditures for turnarounds, catalysts, and joint venture investments, with about 60% allocated to sustaining the business and 40% to growth. Approximately 30% of our overall growth CapEx for 2020 is allocated to expanding our renewables business.
For modeling our Q3 operations, we expect refining throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.4-1.45 million barrels per day, U.S. Mid-Continent at 380,000-400,000 barrels per day, U.S. West Coast at 215,000-235,000 barrels per day, and North Atlantic at 375,000-395,000 barrels per day. We expect refining cash operating expenses in the Q3 to be approximately $4.40 per barrel. With respect to the renewable diesel segment, we expect sales volumes to be 750,000 gallons per day in 2020. Operating expenses in 2020 should be $0.50 per gallon, which includes $0.20 per gallon for non-cash costs such as depreciation and amortization. Our ethanol segment is expected to produce a total of 3.8 million gallons per day in the Q3 .
Operating expenses should average $0.38 per gallon, which includes $0.06 per gallon for non-cash costs, such as depreciation and amortization. For the Q3 , net interest expense should be about $145 million, and total depreciation and amortization expense should be approximately $580 million. For 2020, we expect G&A expenses, excluding corporate depreciation, to be approximately $825 million. We expect the RINs expense for the year to be between $400 and $500 million. Lastly, as discussed on our last earnings call, due to the impact of the beneficial tax provisions in the CARES Act, as well as the COVID-19 pandemic and its impact on our business, we are not providing any guidance on our effective tax rate for 2020. That concludes our opening remarks.
Before we open the call to questions, we again respectfully request that callers adhere to our protocol of limiting each turn in the Q&A to two questions. If you have more than two questions, please rejoin the queue as time permits. This helps us ensure other callers have time to ask their questions.
Thank you. At this time, we will be conducting a question and answer session. If you would like to ask a question, please press star one on your telephone keypad. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Our first question today comes from Prashant Rao of Citigroup. Please proceed with your question.
Good morning. Thanks for taking the question.
You bet.
Hey, Joe.
Good. I wanted to start on the demand recovery. Joe, you mentioned the rapid recovery in product demand through 2Q. Can we get a sense of the strength of product demand as we entered the current quarter, and how it's been trending since? If you could, any color on how to think about that in terms of buckets of gasoline versus jet versus diesel and everything else?
Yeah, sure. Gary, you want to?
Yeah, sure. I'll walk you through it. I'll start with gasoline. As Joe mentioned, we saw demand fall off to about 50% of what we would normally have. Our export volumes fell to about a third of where they would typically be, in the Q2 . As you mentioned, demand has certainly recovered faster than most people have expected. By May, we were at 77% normal gasoline demand in our system. In June, 88% of normal, we've continued to see recovery as we transition into July. On the export side, as I mentioned, we bottomed out at about a third of the volume we typically export in the quarter. By June, we were back to 70% of our normal export volume. July, with the estimates we have today, we'd be about 76% of normal on our export volume.
Gasoline demand has recovered much faster than certainly most would have expected and appears to be pretty strong. On the distillate side, the magnitude of the demand destruction wasn't nearly as great. As we mentioned, we fell off to about 70% of typical demand. Diesel demand recovered pretty quickly back to about 80% of normal. In our system, we've remained about 80%-85% of normal demand. However, that's below what the DOE was reporting. The DOE is closer to 94% diesel demand. I think the difference there is certainly in our Three Rivers and McKee system, we had a lot of diesel going into the upstream sector, and with lower drilling activity, we're seeing a little less diesel demand than maybe we're seeing nationwide. Also, just like gasoline in the export market, we fell off to about a third of our typical export volume in May.
Just like gasoline, it's recovered at a pretty good pace, actually stronger. In June, we were back to about 45% of our normal export demand. Things have really picked up for diesel export demand in July. Our current estimate for July, which show July export volumes 107% of where they were in July of 2019. I think the other thing that's really interesting when you look at the export numbers is looking at those export numbers in light of the U.S. Gulf Coast diesel production. If you look at our export volumes last year in July, we exported about a third of what our refineries produced, the diesel they produced. July of this year, with our estimate on exports, it would be 47%. Almost half of what our refineries are making are going to the export markets. On the jet side, also seeing recovery and demand.
This week's DOE stats, which show jet demand about 60% of normal. I think the DOE data really highlights the importance of the recovery in jet demand, because as jet demand has recovered, you've seen diesel yields from refineries fall off significantly. Where we've peaked at about 39% diesel yield, that's come down to about 32% diesel yield. As you continue to see jet demand recovery, you'll see diesel yield fall off from the refineries, which will really help the diesel supply-demand balances. I think on the jet side, that would be the only sign that we're seeing that's a little bit troubling. Certainly, with some of the renewed efforts to slow the spread of the pandemic and many of the states shutting down.
We don't have a lot of good line of sight into jet demand, but some of our nominations for August demand are down a little bit from what we saw in July.
Excellent. That's a great answer. Thank you for all that color, Gary. My follow-up's just on the balance sheet. You've net debt to cap held in pretty well sequentially, and free cash flow, including the working cap tailwind, was positive in the quarter. Given what we're seeing in the demand recovery and the commentary around where we are in 3Q, if we can hold at these levels, if not improve slowly from here, does it feel like you're already starting to turn the corner a bit on the balance sheet? That is to say, the defensive measures that you've taken so far this year feel sufficient to ride out this downturn absent another pullback in demand?
Yeah. Why don't we let Jason take a shot at that?
Yeah.
Hey, this is Jason. Yeah. I think you're right. With the liquidity we have now, the $2.3 billion in cash and $5.7 billion of other liquidity available, we do think that's adequate for how we see it playing out right now.
Okay. Fantastic. Thanks. Thank you both. Jason, congrats on the promotion and stepping into the new role. I look forward to talking to you more on that front in the future.
Thanks. I appreciate it.
Thanks, Prashant.
The next question is from Theresa Chen of Barclays. Please proceed with your question.
Morning. Thanks for taking my question.
Great. Thank you.
Just a quick follow-up on Prashant's question related to the demand side and your commentary about LATAM. The current estimates of, I think it was 107%, versus normalized levels that you're seeing, how much of that do you think is pent-up demand? Or is it sustainable? Related, do you think that any of the refineries that were previously maybe not optimal or operating at optimized capacity would perhaps permanently shut down or be permanently impaired economically in that region, such that perhaps you can take some market share going forward?
Yeah. I think what we've seen, at least for the export markets we go to in Latin America, their demand recovery has been very close to the same type of demand recovery we're seeing in the U.S. I do think you may have some pre-filling of inventories getting ready for winter, which could cause exports to spike a little bit. In our system, we see a pretty steady flow of diesel volume to Latin America, and the volumes are fairly constant. Where we really get a spike in our export volumes is when the arb to Europe is open. That arb is currently open as it has been much of July, and that's where a lot of that incremental volume is going.
Got it. Then switching to the differentials front. We seem to have several pipeline or projects in regulatory purgatory, and just given your expansive commercial presence, I'd be interested to hear your views on how differentials could react specifically to DAPL. If the pipe is shut down, how do you think that will impact not only Bakken differentials, but also WTI, as in, do you think that could create perhaps like a pull on Cushing? What are your thoughts here?
Definitely, if DAPL isn't allowed to operate, it certainly will pressure the Bakken differentials. We could see that moving weaker. Enbridge came out yesterday. They have some efforts to improve their capacity to help clear the Bakken. Of course, through that Enbridge system, we are connected via our Line nine to Quebec, we'd have an opportunity to bring that Bakken volume to Quebec, which would be a benefit for us. In terms of the WTI differentials, I think with where we are on the forecast for production and where pipeline capacity is, I don't see it really having a significant impact on the WTI differentials. I think we're kind of in a mode where Brent-TI probably is in that $2-$3 range based on the incremental cost to get it to the Gulf and clear.
Understood. Thank you very much, and congratulations to Jason as well.
Thank you.
The next question is from Manav Gupta of Credit Suisse. Please proceed with your question.
Hey guys, first is more of a policy question at this point.
Hey, Manav, we can barely hear you, man.
Oh. Sir, is it better now?
Sorry.
Yeah. On the policy side.
There you are.
At this point, President Joe Biden's clean energy agenda does not have renewable diesel in it. There is a school of thought that you can't force the big trucks and buses to go on electric, but you can encourage them to go on renewable diesel. Do you see a chance that the clean energy agenda of the Democratic nominee expands and includes renewable diesel at some point of time?
Manav, everybody fainted when you made your first proclamation. We'll let Rich Walsh take a shot at the answer, okay?
We have some familiarity with Biden and some of his priorities. One of the things that I would point out is that, nobody's going to want to take the union jobs away that are associated with the manufacturing that we have out there. There's a huge amount of infrastructure in the country that's based on that. Same thing with the renewable fuels. I don't think that any administration that comes in is going to want to pull the rug out from under the farmlands. We see the renewable diesel having a big role to play, a significant role to play. I know there's a lot of aspirational statements and positions out there about electrification, but there's a big marketplace for renewable diesel, and we think it fits strongly in the green agenda.
Martin, anything you want to add to that?
Well, I'd just echo that. When you get the true numbers, if you look at the carbon intensity, renewable diesel competes very well with a so-called zero-emission vehicle. You're already up to 16%, 18% renewable diesel in California. You've got mandates out to 2030 in California and Europe. The clean fuel standard coming in Canada. New York proceeding. As Rich said, we just feel really good about the future and the growth and just see this worldwide, globally, in the fuel mix for a long time to come.
That was very helpful. One quick follow-up. The Monday morning indicators which you put out, which are very helpful, are basically indicating that when you look at all the regions versus May, every region is showing some improvement. The Gulf Coast, where you have most of your capacity, is actually showing a $3 per barrel improvement. I'm just trying to understand on the margin front, why is the rate of change on the Gulf Coast showing a better positive variance versus some of the other regions?
Probably the biggest variance is due to the crude differentials. The crude differentials had been very tight, but we've seen medium sours move $0.60 in the last few days, and we've seen the Canadian heavy move $1. In our Gulf Coast, we run a lot more of the medium and heavy sours. That would have the positive impact on the margin indicator versus the other regions, which are primarily sweet.
Thank you so much for taking my question.
The next question is from Paul Sankey of Sankey Research. Please proceed with your question.
Good morning, everyone. Can you hear me?
Hi, Paul.
Yeah, it's Analyst Hub, actually, not Hubbard. Anyway, good to see you all. Joe, it's been a long six months, four months since we last spoke, and I was wondering the extent to which you feel the world has changed on a secular basis. Obviously, you've referred to the demand side, and we can debate how air travel and whether suburbanization is more gasoline intense. Clearly you've accessed capital. You seem very clearly to be restating the dividend commitment that you've had since you became CEO. I guess one question would be where you think we're going in terms of how U.S. crude markets change. It does seem that we're in for a very different outlook now in terms of how much available crude there is in the U.S. and how the balance will shift.
We've heard a reference already, and thanks for the laugh about how the election may change things, but any further comments you have on that would be very interesting. Thanks, Joe.
Yeah, you bet. Paul, just looking back over the last six months, it's been a bit of a roller coaster ride. When we started off the year in pretty decent shape, we had the incredible trough. Most of us in this room have been in this business for a very long time, and you got to look back a lot of quarters before you see a quarter like the second quarter of this year. It was just brutal. The margins were just horrible. Anyway, the one thing that we're focused on really is that we're going to run the business for the long term, and we need to have a steady hand right now and just continue to focus on doing what we do and doing it well.
We're dealing with news that's barraging us every day with negative commentary, and people are fearful, and we've got an election coming on, and you and I probably could have a lively conversation about the impacts of that. Frankly, we're coming out of this. I think if you look at our country and the way that people want to live, it is not the way that they've lived over the last quarter. Anyway, I'll stop there. Gary, talk a little bit about the crude situation.
I think most forecasts we see confirm what you're talking about. As total oil demand picks up, I think a greater percentage of that gets filled with more sour production. Our view is that the U.S. will still be a net exporter of crude oil, and as long as the U.S. is exporting crude oil, we'll continue to have advantage on the light sweet barrels we're bringing into our system. Of course, with the flexibility that we have, especially with our complex Gulf Coast refining assets, getting some more medium and heavy sour barrels on the market will help us as well from that aspect.
As far as your
Yeah, Joe.
I'm sorry. No, Paul, you mentioned the election. We don't have a crystal ball on what's going to happen. We do know that if you just look fundamentally at where we are, the products that we produce are necessary for life as we know it. You can have a lot of conversation around what we're going to do and what needs to be. In reality, fossil fuels are going to be with us for a very long time. Demand forecasts continue to be for increased crude oil consumption going forward as countries continue to develop and so on. We just need to not get hung up in the, think we're going to be in this dungeon that we're in now forever.
Yeah. Obviously, a vaccine would change that. I think I've read from your comments very clearly that the strength of demand is really impressive if you think that we just printed minus 30% GDP, and we've got yesterday gasoline demand down eight percent. It's actually quite incredible. Thanks.
Yes. You bet. Take care.
The next question is from Doug Terreson of Evercore ISI. Please proceed with your question.
Good morning, everybody.
Hey, Doug.
My question's on supply and specifically how you guys are thinking about closures of refining capacity over the next several years. The reason that I ask is because I think IEA's final tally of closures last cycle was six million-seven million barrels per day of supply. Between recent closure announcements that we've seen in Asia, IMO-related factors, and current refining economics, it seems like we could be on a similar track for the next couple of years as well. Just wanted to see how you're thinking about how the supply side could be affected by this factor in coming years. Is there really any reason to believe it'll be much different from the trough of the last cycle?
Hey, Doug, this is Lane. We've always sort of had the view that really what shuts refineries down, obviously, they have to have some sort of fundamental issue, whether they're configured incorrectly for where the market is or some other structural thing. Ultimately, what closes them is either a big regulatory change where it requires a lot of capital, and it just becomes like, you look at the whole scenario of cash flow, and it becomes insurmountable, and you start trying to normally try to sell it, and then ultimately it shuts down. The other one that does that is, it could be like a big turnaround. We visited a refinery a few years back in the U.K., and that's essentially what got them. They'd put off a turnaround, and it had kept doing that, and ultimately it was a big FCC alky cracking complex turnaround.
The cost of which got to be where it was so large they chose to shut it down. It's really big refineries, if they can just sort of move along and manage expenses and things like that. It's when if a refinery has an outlook based on configuration or fundamentals that makes it negative to begin with, and then there's a large cash outflow due to something changing. That's generally what gets these refineries.
Okay. Thanks a lot.
You bet.
The next question is from Phil Gresh of JP Morgan. Please proceed with your question.
Yes. Hey, good morning. First question here, just obviously, you've referenced the demand picture improving into July quite a bit. That said, the crack spreads are still pretty soft here in July and as we head into August. As you look at the second half of the year and look to balance the supply against the demand and the current inventory picture, do you think demand is going to be able to take care of the inventory situation? Do you think we're in a situation where we need to underproduce through the second half of the year in a greater extent to get inventories lower?
Hey, this is Lane again. Ultimately, we believe to get back to more normalized economic sort of drivers for our business, we need to get back into sort of the five-year range for inventories. There's three paths you talked about. There's really, how does the demand look? How disciplined are refiners with respect to their utilization rates? Of course, finally, it's just a matter of how many closures there are. Our view is that we've been really impressed so far with the industry's response to this in terms of being disciplined, and been encouraged by that. Certainly, as we move forward, seeing how jet demand works and obviously the seasonality with respect to butane going in the pool, we expect that utilization rates will sort of be commensurate with where the economics are.
Somewhere in the, I'm going to say early next year, our view is we'll get sort of back into the five-year range of inventories.
Okay, got it. I guess, would your view then, just extrapolating that a little further to kind of the medium-term outlook, would you think by the middle of next year, that would imply margins could get back to some kind of normalized level if demand continues to improve? Just how are you thinking about things in terms of structurally a normalized picture moving forward?
A normalized world looks like the inventories are basically back into the five-year band. That's how we sort of look at it. Yeah, we believe some more time next year, but we should be back into that sort of market.
Okay. All right. Thank you.
The next question is from Sam Margolin of Wolfe Research. Please proceed with your question.
Morning, everybody. Thanks for taking the question. My question is about the next potential DGD expansion. You mentioned you're in engineering, at this point, the kit seems pretty well established. The underlying fundamentals of the business are good. I think what you said is reasonable, that there's a high probability that these other markets that have a credit system or a carbon price that are comparable to California, this is growing. I guess my question is on this evaluation, what are the inputs that you're watching? Is it more commercial, or are you really evaluating some design changes or some other aspect of the integration in front of FID here?
Hey, Sam, this is Martin. We're really just going through our gated process and the work. This is at a new location, so there's other things you have to take care of, the offsites, the integration with the refinery. It's really not, I wouldn't say I think commercially and operationally, we feel pretty good about where we're at. It's just really doing the work you have to do to get to a cost estimate and the rigor that we apply to these things. We're still on track. We expect to make a final investment decision in early 2021. If we go forward, we would expect to start construction in 2021 and operations commencing in 2024.
Okay. I appreciate it. It is really helpful. Thank you.
Thanks, Sam.
The next question is from Doug Leggate of Bank of America. Please proceed with your question.
Thanks. Good morning, everybody. Hope everybody's doing well out there.
Thanks.
Jason, let me add my congrats. It looks like you're jumping into the fire at a pretty interesting time. Good luck with everything.
Thank you.
Joe, at the beginning of this, at the beginning of March, when Saudi launched its flotilla of crude to the United States, I seem to recall you talking about getting calls relating to your ability to absorb that crude. Obviously, we saw a huge increase in exports or imports rather from Saudi, essentially at the end of May. That appears to have tailed off now, and I'm just wondering if you can walk us through your prognosis for heavy availability and crude spreads in light of what I just suggested.
Yeah, Doug. Gary can speak to this really well.
Doug. I think for us, we've certainly seen spreads about as narrow as we've ever seen with our margin for light sweet, medium sour, and heavy sour all right on top of each other. As we look forward, OPEC has two million barrels a day coming online in August. It looks like Canadian production will ramp up somewhere in the 200-300 barrel a day range. We're already starting to see that have an impact on the market. I mentioned medium sour discounts have widened about $0.60 in the last week. Canadian heavies moved about $1 a barrel weaker. Longer term, the forecast we see show that as total oil demand increases, a much larger percentage of that total oil demand will be filled with sour type production rather than the light suite which came off the market.
We think all of that could lead to wider quality differentials as we move forward longer term.
Okay. I appreciate that. I don't want to make this my second question, but just a footnote to that, Gary. Our understanding from our colleague or associate that we use at the Center for Energy Studies in Russia, he suggested that the increase from Saudi and Russia would be absorbed domestically. Do you believe that those barrels are actually hitting the water?
We have seen some barrels from the Middle East show up in the U.S. Gulf or on offer in the U.S. Gulf, which we haven't seen in quite some time. Basra has been on offer, which we haven't seen in quite some time. I think some of the barrels are making their way onto the water and into the market. Some of that is also due to the fact it looks like Far East buying is down a little bit as well, which is also helping to pressure the crude differentials and make barrels available to us.
I appreciate that. Joe, my second question, I apologize in advance, it is a policy question in light of what we're seeing in the polls and so on. It's really just ask you if you would mind articulating Valero's position on carbon tax, and I'll leave it there. Thanks.
Okay. No, that's great. Again, we'll get Rich Walsh. Rich is responsible for our government affairs activities. We'll get him to comment on this. Doug, we're seeing different proposals coming out, right? Biden's got a position he's taken, and the House is looking at things, and so on. We don't know what's going to come out of this yet, okay? We just really don't. Because nothing seems to have been settled on. That being said, Rich, you just want to kind of share what our thoughts are?
Yeah. It's a little bit hard to respond to it in the abstract, right? It all depends on how the tax is structured, right? If you're looking at a properly structured carbon tax, you got to consider, is a carbon tax going to drive carbon offshore to unregulated environments? You'll need to structure around that. It needs to be market-driven. You need to think about affordability. You need to think about complexity in structuring it. Not picking winners and losers just by virtue of it. Letting it actually allow all carbon reduction options to play into the market is really important. The other thing I think you should temper all of this with is considering the state of the economy right now. Any administration that gets elected is going to be dealing with a COVID recovery economy, and you need energy to drive the economy.
You can't really want to drive stimulus in the economy and then layer a bunch of taxes on and completely restructure the energy format for the nation. It's really not feasible. I think the next administration, it's going to be about the economy, and the economy's going to need energy. While there's a lot of hyperbole in the campaign and a lot of aspirational statements, the reality is that they're going to need strong fuels to keep the economy going.
I guess in summary, we just need to see what they're going to do before we can say what our position would be on it.
Understood. I appreciate you framing at least how you think about it. Thanks a lot, guys. Good luck.
Yeah, thanks.
The next question is from Roger Read of Wells Fargo. Please proceed with your question.
Hey, good morning, everybody.
Hi, Roger.
A lot of stuff's been hit here. I guess one question I'll throw at you on the refining side. We've heard talk in some of the other companies about delays and deferrals on maintenance and how that may affect what's available to run, meaning maybe a little higher this fall and winter, but maybe lower next spring as people get, let's say, we get past the worst of the pandemic and all that. As you think, probably, Lane, this question's for you, as you think about getting inventories back to the five-year average, is that something that we should factor in as an additional help? There's enough surplus capacity everywhere if demand stays kind of soft that maybe we won't really notice anything on the maintenance deferral side?
Hey, Roger. I think it's really a function of how that operator responds to some of this. For example, one of the things that we did when we saw and when this all first started is we took the opportunity to take Pembroke FCC down and clean out its fractionator, right? We actually incurred additional maintenance expense to deal with what we thought was an acute issue around its operation. We could have tried to get through that and get it to its turnaround next year. We thought, "You know what? Let's just get in and get that cleaned out," and also help with this sort of structural demand destruction that was early on. I think it all depends on the operator. An operator who's stressed, they have their balance sheet stressed, their access to capital is, and debt is a little bit stressed.
They may in fact decide to defer a lot of maintenance to some other point because they got a liquidity issue, and they got to push it out to a point at which they hope that there's enough recovery they can afford to do these things. The risk in that is that the unit doesn't really know how good your balance sheet is or how the world is. It just sort of decides. At that point, if that unit goes down, it's an unplanned event. It becomes a much larger event. It's a much more expensive event. That's the risk an operator in that condition has to deal with. Valero specifically, we didn't have a lot of turnaround work going into this or even planned turnaround work in the third and fourth quarter. We'll still address where we think we have operating issues.
The other general comment I'll say is, yeah, we reduced expenses. One of those knobs was, I would call it light maintenance. You can sort of tell from the way I talk, just sort of core value of ours is that we will never, ever cut our maintenance capital such that it puts our reliability at risk. We believe that's a pathway to get to even higher expenses and more cash outlay in the future, because we believe in being in this in the long term. We don't operate that way. We did touch lightly on some of what we consider to be a little bit of discretionary maintenance. Did that answer your question?
I think so. It's obviously a lot of moving parts to it. I'm just trying to, where we can, understand some of the things that are going to be coming at us here other than just.
Well, I guess what I'm trying to say is it's very operator specific. If you like to look out there at the cast of characters, the people who are in this business, some people will respond by being careful, and some people might have to take an additional risk. Then it's just a matter of how it all unfolds.
No, I appreciate that. I guess the other question I have is to follow up on the earlier comment about the diesel yield going from the high 30s to the low 30s as jet fuel demand comes back up. As we look overall at what's been coming in the last several weeks on the DOEs, we've seen gasoline draws a little bit on net. Diesel's actually been continuing to build. Are we at a point here where jet fuel demand has recovered enough that we should see the lower diesel yields feed into no longer building diesel margins? Kind of maybe tag teaming on Phil's question, are we at a situation here where maybe we face, I don't know, overall run cuts or a further cut in diesel yields in order to kind of balance the market.
One of the reasons I'm asking that is, as we roll late September into October, we go from summer-grade to winter-grade gasoline, and so that tends to make it easier to make gasoline. I was just curious if that further complicates things if we don't see a continued improvement in jet fuel demand.
Yeah. I think our view is we don't see where jet fuel demand fully recovers to where we were and that jet fuel demand picks up enough to really correct the yield issue, which is where it gets really to Lane's point. For us to really see diesel inventories get back to that five-year average level and get total light product inventories into that five-year average range, we really need to see discipline on the utilization. To keep utilization down is probably the biggest key to getting inventories back.
Stay tuned. All right. Thanks, guys.
The next question is from Paul Cheng of Scotiabank. Please proceed with your question.
Hi. Good morning, guys.
Hey, Paul.
Two question, since that Jason is now the CFO, Jason, you have any preliminary outlook for 2021 CapEx? If not the exact amount, but whether it's going to be flat, up or down compared to this year?
Yeah. Paul, hey. We haven't given the guidance yet, as you well know.
That's why I say anything memory outlook from Jason.
I'm going to say this right now, okay? The high end would be $2.5 billion, and then probably $2 billion on the low end.
Right.
Okay? I think we just need to wait and see what happens. Lane's got us really well positioned on the execution of the capital plan, that if we need to delay a project or continue to slow some of these projects, we'll do it. I think we're very highly confident we're just going to continue to proceed with the Diamond Green Diesel project.
Yeah, we haven't slowed that down.
Yeah, we're not going to slow that down. Paul, I'd say $2 billion. If we see the, as the guys have talked about, to get really back to a really strong margin environment, we need to see inventories come down some. That could happen sooner than later, but we just don't know. I think if to the extent we can restart some of these capital projects, we'd like to do it. Okay? I think we've talked before, Jason, we've talked about this, that if you're going to prioritize your use of funds in the company, one of the first things we'd like to do is go ahead and restart these high-return capital projects like the Coker. We're going to look at the balance sheet and be sure that we reduce our debt and that we build some cash.
Yeah.
Then at ultimately, Paul, we would look at share repurchases. Anyway, that's kind of our sequencing around the use of cash. Jason-
Actually, just curious, Joe and Jason, what is the debt level you need to bring back down to before you will consider the other maybe shareholder return options?
Bring capital down to, are you saying?
Bring down debt.
No. What debt level you want to bring it down to? I would imagine that when you start generating free cash, maybe one of the priorities that you want to bring down your debt. Correct me if I'm wrong, if that is the first priority, at what point the debt level you will say okay, while that we still want it to be down more, but at this level that we could have more balance between increasing the return to shareholder and reducing debt at the same time?
Okay.
Yeah, I know our guidance on our capital allocation framework is we target 20%-30%. That's a good guideline. There's not an absolute hard and fast rule. That's a good thought.
Paul, and you know what kind of debt we've got out there. In the past, and we'll continue to look at it, we do regularly, but it's been prohibitively expensive for us to go out and call debt. Okay.
We look at it, and Jason's team looks at it all the time. It just hasn't made sense to do in the past, and we'll continue to look for it going forward at a going forward.
Okay.
Yeah.
A final question from me. Line five, in the event if you're being shut, for Quebec City, the supply alternative, Gary, can you maybe elaborate a little bit?
Throughout history, we've really supplied the Quebec Refinery over the water and can fully supply Quebec with waterborne barrels. Line nine is an optimization for us and has provided a nice economic benefit to us. We have the ability to supply Quebec either West African barrels or barrels from the U.S. Gulf Coast over the water.
Is there any option or opportunity to find additional raw American inland supply, or that's really once Line nine is shut, that's really that no additional route will be able to get more local supply or that Calgary or that Bakken supply into that?
The Line that's really closed is Line five and not all of Line nine is fed from Line five. Even if Line five is closed, we still believe we'd have access to Western Canadian barrels that could feed Line nine.
How does that work actually? Is it prorated? Line five is shut, and let's assume that the total available in Line nine become, say, call it half. Is it you will get half?
Your normal allocation or how does that work, the process?
That's close to how it would work. There would be a proration that goes into effect based on your shipper history. Where we would fall out on that, I'm not sure. Assuming Line five is half of the volume and everyone was prorated to 50%, we would be 50% of what we normally ship through Line nine.
I see. Thank you.
Thanks, Paul.
The next question is from Brad Heffern of RBC Capital Markets. Please proceed with your question.
Hey, everyone. Thanks for taking the questions. Joe, you've had this, the 40%-50% cash return target for a long time now. I'm curious if we end up in a sort of longer margin recovery environment, maybe like we saw after the financial crisis, how long you're comfortable sort of paying above that target as you are now, before potentially the dividend could need to be addressed?
Okay. Hey, we'll let Jason talk generally to how we're thinking about cash flows and the dividend here, okay?
Yeah, you're right. We're well above it now. I think Homer said we're at 96% year to date on payout. With this being an extraordinary and short-term event, we don't adjust that based on this type of a situation. We stick with our guidance. We won't vary from it. I don't know if we have an exact number on how long we would be comfortable with that.
No, we don't.
Yeah. Okay. I guess sort of along the same lines, have your thoughts changed at all about the repurchase program, just given what we've seen? Obviously, the historical criticism has been that when you have money to do repurchases, obviously, the stock price is higher. That's certainly proven to be true this time. Is there a chance that on the other side, we see Valero sustain a higher cash balance and a lower overall debt level than maybe we thought previously? Any color like that would be great. Thanks.
You want to talk about it or you want me to?
I'll go.
I'll tell you. Again, I think the key to remember here is we're in kind of a funky short-term, what we consider to be a short-term period. Okay. We're going to evaluate it. We don't know what next week's going to hold or what the next month's going to hold or the next year. What we're doing is sticking to what we've done in the past, and we're comfortable with it right now. We are well-positioned going into it. We've looked at how we're positioned today versus where we were back in 2009 when we had a previous downturn. We stress test everything. We're not willing right now to make decisions with long-term implications based on what we consider to be a short-term set of circumstances. We're just going to play this out, and we'll see what happens.
Okay. Fair enough, Joe. Thanks.
The next question is from Neil Mehta of Goldman Sachs. Please proceed with your question.
Good morning, team, and thanks for taking the question. The first question I have is just on DGD margins. We've been following the indicator margins on your website. They came in a little softer than what we expected in the Q2 . Volumes looked good. Just any thoughts on 2020 DGD margins would be helpful.
Neil, this is Martin. I can tell you, the Q2 was $1.93 a gallon EBITDA, which we actually feel pretty good about. If you look now where we're at relative to the Q2 , diesel price is up $0.27 a gallon. The D4 RIN component with the multiplier is up $0.12 a gallon. You're close to $0.40 a gallon better on the indicator margin than we were in the Q2 with those components. Looking out for the rest of the year, we feel really good about where DGD is going to be for the rest of the year and foreseeable future.
That's great. That brings us to the follow-up, which is just your thoughts on RINs and particularly the D6 RIN and just how it could play out from here. It kind of ties back into some of the election commentary you guys made earlier.
Thanks.
Well, right now we expect RINs to remain supported in the near term. There's a lot going on. You've got low energy prices relative to agricultural prices, and that makes the biofuels less competitive, which typically means a higher RIN. You've got uncertainty around the small refinery exemption program and obviously effects of COVID-19 on gasoline. You just don't know if the gasoline pool will absorb the mandated ethanol volumes next year. That's a risk. Then the EPA, the 2021 RVO itself has been postponed indefinitely. There's just a lot of uncertainty around the RIN right now. As a result-
Chris Sighinolfi of Jefferies. Please proceed with your question.
Hi, Joe. Good morning, everybody.
Hi, Chris.
Thanks for the added color today. I do have two questions. I guess, first following up on Roger's earlier question. With changes in product slate and unit configuration and perhaps the swing into winter grade, how high could you push gasoline yield if demand there continues to rebound and for jet and distillate, maybe it doesn't? On a related note, are you changing at all the crude procurement processes, just given the pace and degree of change and uncertainty with regard to individual product demand over the last couple of months and maybe continuing for the next couple of months?
Gasoline yield, to give you a really good answer in terms of you were in a mode of trying to maximize gasoline and minimize distillate, it's probably in the order of a low 50% sort of yields.
Overall, it's obviously a function of different refineries. Our Benicia refinery makes 60% gasoline, and so does our McKee refinery. Some of the more heavy refineries are a little bit different. It's really a function of the refineries. If the world works out the way, is where gasoline's recovered and jet doesn't recover, and consequently, you got to be careful. We'll certainly test the limits of that, probably Q1 and going into Q2 , depending on, again, how disciplined refiners are for the rest of the year.
On crude, I guess early in the second quarter when gasoline got very weak, we pushed a little bit more medium sour into our system to try to promote higher diesel yield. Since then, we backed off, and we're at a real similar crude diet to what we typically run, and I don't see that changing in the near future.
Okay, great. Lane, I appreciate the earlier discussion of product inventories and your expectations as we move into next year. For my own edification, when you think about recapturing five-year inventory ranges and the signal that that inventory normalization might send to prices and cracks, do you think about that in an absolute sense, or do you think about it in terms of a days of demand ratio? I know it's a conceptual question, but I guess with all this shadow inventory represented by the low refining utilization rates, I'm just curious how you and your team think about those components.
That's an excellent question. Obviously, there's just different demand through time. We look at where inventories are in the five-year range. That's where we start. Then we certainly start looking at days of supply. Then we look for, are there inventories that maybe the DOE is not capturing that's somewhere else out there. We look at all those things, for sure. It's at a high level. We're just saying, the industry needs to be disciplined. Obviously, demand is on its way back. We want to see what is normalized inventories to be in the five-year range. Then we start looking at days of supply and are there inventories in unusual places that we'll take into account.
Okay. That's really helpful. Thanks a lot, guys. Good luck.
The last question today comes from Benny Wong of Morgan Stanley. Please proceed with your question.
Hey, good morning, guys. Thanks for squeezing me in. I'll keep it to one. I just want to be mindful of your time. Just looking at your renewable diesel, your business margin there came in at $1.95, which was a little bit better than what we expected. When we look at spot prices, the business margin looks like it'd be much better, maybe even closer to $2.50, $2.75. When we put aside movement in commodity prices, is there any reasons or factors that we should not expect the same magnitude of index price recovery to flow into your business margin in 3Q and the back half of the year?
Hey, this is Martin. As I said earlier, we've seen quite a bit of recovery since the 2Q average numbers in both the diesel price and the RIN. LCFS price is flat. I would say you ought to expect what we've guided to before, that we feel pretty good about Q3 and Q4 for renewable diesel.
Got it. Okay. Appreciate that. There's nothing within movement and capture rates and costs that we might have to incrementally think about in the back half of the year. Is that right?
That's correct.
Great. Thank you very much.
Thanks, Benny.
That's all the time we have for questions today. I would now like to turn the call back to Homer Bhullar for closing remarks.
Thank you. We appreciate everyone joining us today. If you have any follow-up questions, please feel free to call the IR team. Thank you.
This concludes today's conference. You may now disconnect your lines at this time. Thank you for your participation.