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Greetings, and welcome to Valero's Second Quarter 2022 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question and answer session will follow the formal presentation. [Operator Instructions]
As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Homer Bhullar, Vice President, Investor Relation. Thank you. Please go ahead.
Good morning, everyone, and welcome to Valero Energy Corporation's second quarter 2022 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 President and Chief Commercial Officer; and several other members of Valero's senior management team.
If you have not received the earnings release and would like a copy, you can find one on our Web site at investorvalero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments and reconciliations and disclosures for adjusted metrics mentioned on this call. 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 the 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, and good morning, everyone. I'm pleased to report that our team maximized refining run rates in the second quarter, while executing our long-standing commitment to safe, reliable, and environmentally responsible operations. In fact, we've been increasing throughput since 2020, as demand recovered along with the easing of COVID-19 pandemic restrictions. Our refinery utilization rate increased from the pandemic low of 74% in the second quarter of 2020, to 94% in the second quarter of 2022. Refining margins in the second quarter were supported by continued strength in product demand, coupled with low product inventories and continued energy cost advantage for U.S. refineries compared to global competitors.
Product supply is constrained as a result of significant refinery capacity rationalization that was triggered by the COVID-19 pandemic, driving the shutdown of marginal refineries and conversion of several refineries to product low-carbon fuels. In addition, the Russia-Ukraine conflict intensified the supply tightness with less Russian products in the global market. However, product demand has been strong due to the summer driving season and pent up demand for travel. Valero continues to maximize refinery throughput to help supply the market at this time when global product inventories are at historically low levels.
Our low-carbon Renewable Diesel and Ethanol segments also performed well in the quarter. The Renewable Diesel segment had record production volumes as the DGD expansion, DGD 2 ramped up to full capacity. On the strategic front, we remain on track with our growth projects that reduced costs and improve margin capture. The Port Arthur Coker project, which is expected to increase the refinery's throughput capacity, while also improving turnaround efficiency, is expected to be completed in the first-half of 2023. As for low-carbon projects, the DGD 3 renewable diesel project, located next to our Port Arthur refinery, is expected to be operational in the fourth quarter of 2022. The completion of this 470 million gallon per year plan is expected to nearly double DGD's total annual capacity to approximately 1.2. billion gallons of renewable diesel, and 50 million gallons of renewable naphtha.
BlackRock and Navigator's carbon sequestration project is progressing on schedule, and is expected to begin startup activities in late-2024. We're expected to be the anchor shipper, with eight of our ethanol plants connected to this system, which should provide a lower carbon-intensity ethanol product, and generate higher product margins. And we continue to evaluate other low-carbon opportunities, such as sustainable aviation fuel, renewable hydrogen, and additional renewable naphtha and carbon sequestration projects.
On the financial side, we remain committed to our capital allocation framework, which prioritizes a strong balance sheet, and an investment-grade credit rating. We incurred $4 billion of incremental debt in 2020 during the low-margin environment resulting from the pandemic. Since then, we've reduced our debt by $2.3 billion, including a $300 million reduction in June, and will evaluate further de-leveraging opportunities going forward.
In summary, we remain focused on safe, reliable, and environmentally responsible operations, and on maximizing system throughput to provide the essential products that the world needs. And we continue to strengthen our long-term competitive advantage through refining optimization projects, and to grow our business through innovative low carbon fuels that enhance the margin capability of our portfolio.
So, with that, Homer, I'll hand the call back to you.
Thanks, Joe. For the second quarter of 2022, net income attributable to Valero stockholders was $4.7 billion or $11.57 per share compared to $162 million or $0.39 per share for the second quarter of 2021. Adjusted net income attributable to Valero stockholders was $4.6 billion or $11.36 per share for the second quarter of 2022 compared to $260 million or $0.63 per share for the second quarter of 2021.
For reconciliations to adjusted amounts, please refer to the earnings release and the accompanying financial tables. The refining segment reported $6.2 billion of operating income for the second quarter of 2022 compared to $349 million for the second quarter of 2021. Adjusted operating income was $6.1 billion for the second quarter of 2022 compared to $442 million for the second quarter of 2021.
Refining throughput volumes in the second quarter of 2022 averaged $3 million barrels per day, which was 127,000 barrels per day higher than the second quarter of 2021. Throughput capacity utilization was 94% in the second quarter of 2022 compared to 90% in the second quarter of 2021. Refining cash operating expenses of $5.20 per barrel in the second quarter of 2022 were $1.07 per barrel higher than the second quarter of 2021 primarily attributed to higher natural gas prices.
Renewable Diesel segment operating income was $152 million for the second quarter of 2022 compared to $248 million for the second quarter of 2021. Renewable diesel sales volumes averaged $2.2 million gallons per day in the second quarter of 2022, which was 1.3 million gallons per day higher than the second quarter of 2021. The higher sales volumes were attributed to DGD 2's operations which started up in the fourth quarter of 2021.
The Ethanol segment reported $101 million of operating income for the second quarter of 2022 compared to $99 million for the second quarter of 2021. Adjusted operating income which primarily excludes the gain from the sale of our Jefferson ethanol plant whose operations were idle than 2020, was $79 million for the second quarter of 2022. Ethanol production volumes averaged 3.9 million gallons per day in the second quarter of 2022. For the second quarter of 2022, G&A expenses were $233 million and net interest expense was $142 million. Depreciation and amortization expense was $602 million, and income tax expense was $1.3 billion for the second quarter of 2022
The effective tax rate was 22%. Net cash provided by operating activities was $5.8 billion in the second quarter of 2022. Excluding the favorable impact from the change in working capital of $594 million and the other joint venture member 50% share of DGD's net cash provided by operating activities excluding changes in DGD's working capital, adjusted net cash provided by operating activities was $5.2 billion.
With regard to investing activities, we made $653 million of capital investments in the second quarter of 2022. Of which, $298 million was for sustaining the business including costs for turnarounds, catalysts and regulatory compliance, and $355 million was for growing the business. Excluding capital investments attributable to the other joint venture members, 50% share of DGD and those related to other variable interest entities, capital investments attributable to Valero were $524 million in the second quarter of 2022
Moving to financing activities, earlier this month, our Board of Directors approved a regular quarterly common stock dividend of $0.98 per share payable on September 1, to holders of record on August 4. We returned 42% of adjusted net cash provided by operating activities to our stockholders through dividends and stock buybacks in the quarter, which is at the low-end of our annual 40% to 50% target payout ratio.
With respect to our balance sheet, we completed another debt reduction transaction in the second quarter that reduced Valero's debt by $300 million. As Joe already noted, this transaction combined with the debt reduction and refinancing transactions completed in the second-half of 2021 and the first quarter of 2022 have collectively reduced Valero's debt by $2.3 billion.
We ended the quarter with $10.9 billion of total debt, $2 billion of finance lease obligations, and $5.4 billion of cash and cash equivalents. The debt to capitalization ratio net of cash and cash equivalents was 25%, down from the pandemic high of 40% at the end of March 2021, which was largely the result of the debt incurred during the height of the COVID-19 pandemic. And we ended the quarter well-capitalized with $4.6 billion of available liquidity, excluding cash.
Turning to guidance, we expect capital investments attributable to Valero for 2022 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts, and joint venture investments. About 60% of that amount is allocated to sustaining the business, and 40% to growth. About half of the growth capital in 2022 is allocated to expanding our low carbon fuels businesses.
For modeling our third quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.72 million to 1.77 million barrels per day, Mid Continent at 420,000 to 440,000 barrels per day, West Coast at 255,000 to 275,000 barrels per day, and North Atlantic at 445,000 to 465,000 barrels per day. We expect refining cash operating expenses in the third quarter to be approximately $5.40 per barrel, which is higher than the second quarter, primarily due to higher energy costs.
With respect to the renewable diesel segment, we expect sales volumes to be approximately 750 million gallons in 2022, with the anticipated start up of DGD 3 in the fourth quarter. Operating expenses in 2022 should be $0.45 per gallon, which includes $0.15 per gallon for non-cash costs such as depreciation and amortization. Our ethanol segment is expected to produce 3.9 million gallons per day in the third quarter. Operating expense should average $0.50 per gallon, which includes $0.05 per gallon for non-cash costs such as depreciation and amortization. For the third quarter, net interest expense should be about $140 million, and total depreciation and amortization expense should be approximately $640 million. For 2022, we expect G&A expenses, excluding corporate depreciation to be approximately $870 million.
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. Please respect this request to ensure other callers have time to ask their questions.
Thank you. [Operator Instructions] The first question today is coming from Manav Gupta of Credit Suisse. Please go ahead.
Guys, I'm going to actually ask only one question, and that is basically can you help us understand the demand dynamics out there? There were some worries on demand destruction, and then there were some worries on recessionary demand. The conversations we are having indicates that's not the case, but you have the most diversified footprint. So, help us understand, gasoline or diesel, what are you seeing in terms of demand out there? And I'll leave it there. Thank you.
Thanks, Manav.
Manav, this is Gary. I can tell you, through our wholesale channel there is really no indication of any demand destruction. In June, we actually set sales records; we sold 911,000 barrels a day in the month of June, which surpassed our previous record, in August of '18, where we did 904,000 barrels a day. We read a lot about demand destruction and mobility data showing in that range of 3% to 5% demand destruction. Again, we're not seeing in our system. We did see a bit of a lull the first couple of weeks of July, but our seven-day averages now are back to kind of that June level with gasoline at pre-pandemic levels, and diesel continuing to trend above pre-pandemic levels.
Thank you, guys, and congrats on a very good quarter.
Thank you.
Thank you. The next question is coming from Theresa Chen of Barclays. Please go ahead.
Great quarter, team, very impressive.
Thanks.
In light of the macro developments both on the supply side and the demand side, what are your thoughts about where the mid-cycle crack is at now structurally?
You guys want to --
Well, Theresa, this is Lane, I'll take a crack at it, and Gary can tune me a little bit. But, obviously right now it's significantly above the mid-cycle or at least our view of mid-cycle, and then probably anybody else's, for that matter. But with that said, you got to remember our idea of mid-cycle is we go through an entire economic cycle, i.e., from recession to recession. And so, that's kind of -- it's descriptive and defined, and we work through those numbers with few adjustments. But I think we believe, at least we --- the world seems to be trending in a place where the -- through the next economic cycle for a number of reasons, whether it's just sort of the way the energy transition is working for the lack of investment in fossil fuels. For a number of these types of reasons we sort of see that the -- probably be above what -- where our mid-cycle is today for the next economic cycle.
Yes, I agree with what Lane said. Really, our market outlook calls for a prolonged period where we would be above what we currently have as mid-cycle. And there's a number of structural changes. When you talk about high energy costs as a result of higher natural gas costs, in the U.S. we have lower feed stocks cost due to our proximity to crude natural gas. And then you're getting refiners that are now having to pay some form of a carbon tax, which raises their cost as well. So, as long as the supply and demand balances are tight, and there's a call on that capacity, it would be logical to assume it's going to start to reset that mid-cycle level.
Thank you. And kind of piggyback on Manav's question related to demand, if we do see a period of demand contraction or demand softness, what do you think the risk is at this point for the industry, as a whole, to build overwhelming amounts of inventories given that the refining industry just lived through two-and-a-half years of having to be extremely flexible, shutting down capacity, et cetera, to run through the pandemic.
Yes, so, I -- again, kind of referring back to those structural advantages we have in the U.S. on feedstock costs and the energy costs and freight advantages going to South American, we feel like we're in such a strong competitive position even if demand fell here in the United States, we would be able to export volume and be competitive doing that in South America.
Well, and this is Lane, and Theresa, to your point, I mean the extreme measures our industry took to deal with the pandemic demand destruction, it's hard to imagine outside of another pandemic the demand destruction where going though a recession would have anything remotely close to that. And obviously, going through the pandemic, quite a bit of capacity was taken offline.
Thank you.
Thank you. The next question is coming from Doug Leggate of Bank of America. Please go ahead.
Hi, good morning, everyone. Thanks for taking my questions. So, guys, I guess kind of a follow-up on the mid-cycle question, but I'm going to ask it a little differently given your unique insights to this. Pembroke is clearly an insight to what's happening in Europe that, today, I guess is paying somewhere around $60.00 per 1,000 cubic feet of natural gas, so U.K., obviously, is a little lower than that. But when you think about this structural cost advantage of the U.S., which is where we are focused, I guess, on mid-cycle, as opposed to global, what are the dynamics that you're seeing? Is Pembroke making money today? What's its relative competitiveness as a benchmark, let's say, for Europe versus the U.S.?
Hey, Doug, it's Lane. So, a very good question, and we sort of talked about this quite a bit in terms of this advantage the United States is having with respect to, obviously, energy prices. Today, Pembroke is doing well; it did particularly well in this past quarter. To give a more of a precise answer around natural gas, you've been mainly paying about $30 to, I don't know, maybe -- to this morning, it was $50, but I mean, per million BTU, but I would say it's more in this $30 range. There's quite a bit of volatility, however the U.K. is a little bit better-positioned than Europe is in terms of the value that they're paying for gas.
So, even [there is another step] [Ph] change, and we're not -- we don't refine over there, so we're just sort of reading the same things that you guys are, there's another step change in terms of how much gas is costing in the U.K. versus some of these European refineries that are maybe not in the best situation around natural gas. So, Pembroke is doing well, I mean and -- and so, I wouldn't consider it actually to be at the marginal capacity today. Obviously, the fact that they're doing well means that we're way past them as being somebody like -- even them being the sort of marginal capacity setting out their -- setting the -- mainly the heat crack, so --
Lane, if I may follow-up real quick, where does Pembroke sit in, to the extent you're prepared to share, on your portfolio cost curve today?
Well, today, it's high, right, because of the cost of natural gas. But when you look at them on the other issues, whether it's our -- sort of our -- our cost per barrel or all those out, sort of on an energy-adjusted basis, they're one of the most competitive refineries in Europe, and actually look pretty good on a U.S. basis. And so, I'm not going to give exact precision, but it's a very efficient refinery. They have are very, very competitive in the Atlantic Basin.
Okay, thank you. My follow-up, so hopefully a quick one, you've cut your net debt in half over the past year, I guess. I for one, as you know, am delighted to see some cash building on the balance sheet. I'm just curious how you think about bulletproofing your balance sheet versus stepping into, perhaps, your buybacks over the foreseeable future? And I'll leave it there. Thanks.
Thanks, Doug, this is Jason, I can take one. We'll be doing basically the same thing we've been doing in the past. Our capital allocation priorities haven't changed. We said when the margins start recovering, we start paying down our debt and build cash as a priority; we made really good progress on both of those fronts. And Joe and Homer mentioned on the debt side, and you mentioned, we had a series of transactions, starting last September running through June 1, where we paid back $2.3 billion of our COVID debts so far. On the cash side, we said we'd planned a whole more given what we experienced through COVID, $3 billion to $4 billion be the range we'd look at. We're now at $5.4 billion with a net debt to cap of 25% at the end of the second quarter. So, we think we're in a good shape on those fronts.
Now, our approach to buybacks will continue to be guided by our target payout ration of 40% to 50%, just the net cash from operations. We've remained at the lower-end of the range so far this year given our competing priorities of paying back the debt and building cash. We're at a 42% payout so far this year, so we think we're in good shape, and we'll plan to continue doing more of the same, paying down our debt and honoring our return commitment to the shareholders.
All right, guys, I appreciate the answers. Thank you.
You bet, Doug. Take care.
Thank you. The next question is coming from Roger Read of Wells Fargo. Please go ahead.
Yes, thank you, good morning.
Morning, Roger.
Coming back to the demand thing, but maybe a little more of a forward look, distillate was the big surprise kind of in the spring coming out of the winter in Europe. And as we look to this next winter, I mean if you're in Europe it doesn't look like gas gets any cheaper. So, as we think about distillate or fuel oil demand there and the way we're running at this point, in the summer, what do you see as the ways in which incremental diesel can make it into Europe and affect the overall Atlantic Basis margins?
Yes, it's going to be a real challenge for us, Roger, to be able to supply a lot more diesel into Europe. If you look, with the U.S. inventories where they are, the industry basically running all-out. We're getting back to where jet demand is recovering in the U.S., which is actually driving ULSD yields down a little bit. So, it's very difficult for me seeing that there's going to be a lot of flow from the U.S. into Europe.
Got you. And then as a follow-up on the 40% to 50% payout ratio, pre-COVID there were a number of times you ran well above that level. Now that we're in a situation where it looks like better than mid-cycle, cracks are going to persist for a while, you want to hold more cash. Do you see this as a situation where you may undershoot or kind of consistently stay at the low-end, as we saw in the second quarter or is this something that evolves as, let's just say, as $4 billion of debt repayment is achieved is -- does it go back into that -- or to the high-end of the range thereafter?
You want to answer the first one?
Yes, sure. Yes, you're right, for the foreseeable future, at least in the next several months, we've still got that competing priority of paying down our debt. So, I think we'll stay at the lower end while we're paying down debt. If any of the cycle continues to be super strong, you're right; we'll have a lot of excess cash to consider.
Yes, and Roger, I agree completely with what Jason said. I mean we want to go ahead and get things cleaned up, and get this balance sheet absolutely bulletproofed. And carrying a bit more cash is something that makes a lot of sense to do. You'd like to have your maintenance and turnaround CapEx covered with cash on hand, the dividend covered with cash on hand, and then we'll see where we go. But, anyway, I think for now we're on the right course, and as Gary has stated, it looks like the margin environment is going to be higher for some time. It certainly is today, not what we experienced in the second quarter but certainly well above what we would consider to be a traditional mid-cycle. And if we continue to build cash we'll continue to honor the payout, and it'll probably move from the lower end to the higher end.
Okay. And just maybe as one little tweak on that, as you think about dividend versus share repos, does that ultimately change once the balance sheet is back the way you wanted -- it's been a while since you've increased the dividend, I guess, is really what I'm getting at. Should we think of that as becoming another way to return cash?
Yes, I mean, you should. That is something we'll be looking at, as we've discussed, our short-term focus is on getting the debt back down. And we will look at that. We met and looked at this before. We'll be measured in our approach to ensure it's something that's sustainable through this cycle, especially given what we experienced coming through COVID, but that is something we'll be looking at.
Great, thank you.
Thank you. The next question is coming from Paul Sankey of Sankey Research. Please go ahead.
Hi, good morning, everyone.
Good morning, Paul.
Good morning. It was obviously a momentous quarter for oil markets. Can you just talk a bit about what's happened in crude markets, and what the outlook is in terms of, obviously, the Russian impacts and the various differentials we're looking at, the Brent/WTI Spread, everything else? Thanks.
Yes, this is Gary. So, I think, overall, we started to see there was not certainty what would happen with the Russian sanctions, but as time has gone on it appears that the Russian oil has continued to flow, and it's a change in trade flow, not less Russian oil on the market. The combination of that, SPR barrels coming on to the market, some production growth in certain parts of the world caused flat price to come down. And then it's also caused quality differentials to be pressured somewhat. In addition to the things I mentioned, the early releases, the SPR, largely medium-sour barrels with pressured the differentials. And then we've seen high sulfur fuel oil move weaker, which high sulfur fuel oil prices tend to impact quality differentials as well. Some of that is Russian [resid] [Ph], is starting to make its way back to the market. You're seeing more high sulfur fuel oil come from Mexico, and so those things are starting to pressure the quality differentials we're seeing in the market today.
That's very helpful, thanks. Could you just continue that forward thought, how do you think things will change over the next six months or so? I mean one obvious thing is that the SPR, I don't know, but I mean presumably at some point it's got to stop being released, right?
Yes, well, that's exactly right. I think you'll see lower volumes coming from SPR. Most people have kind of lowered their global oil demand forecast. So, I think the oil markets are fairly well-balanced. We wouldn't expect a lot of movement in the quality differentials from where they are today.
Thank you, appreciate it. Thanks, guys.
Take care, Paul.
Thank you. The next question is coming from John Royall of JP Morgan. Please go ahead.
Hey, good morning, guys. Thanks for taking my question. So, on R&D, can you talk about the captures stepping down in 2Q, and any moving pieces there beyond the backwardation, I know you've talked about in the last quarter? And then, what do you expect the long-term captures to look like in that business once the -- you know, get to a more normal looking market structure for diesel and once you have DGD 3 up and running?
Yes. This is Eric. I think you hit the nail on the head. Really the big difference between Q1 and Q2 was the severity of the backwardation quarter-to-quarter, but if you look at the rest of the capture rate, which was weaker, yes, soybean prices were higher, and obviously LCFS prices were down sort of averaging $130 in the first quarter versus closer to $100 in the second quarter. So, it's clearly margins tighter in the second quarter, and capture rate is lower mostly due to backwardation you mentioned. If you look forward, I think again you said that as USD markets normalize you will see a little bit of return normal in the back-half of this year for RD.
Great. And then, just picking with R&D, I know you've had some good news on the BTC and the staffs this morning. Could you give your latest thoughts on the LCFS program in California, and where you think pricing could go there? I know we have the scoping process now to think about, and we have a federal program in Canada starting next year. So, just any thoughts on pricing there into the second-half and next year will be helpful.
Yes. The LCFS market in California has really seemed to have stabilized in the sort of $90 to $100 range. We don't see a lot of volume moving. And as you mentioned, the scoping meetings they have, they're considering increasing the obligations into 2030, which should have a -- create a greater demand for the LCFS credits. Because as we see now, with renewable diesel and other renewables consuming up to about 50% of the obligation, and gasoline demand still relatively muted on the West Coast is just -- it's the credit obligation. It's just not a big driver there. So, I think you mentioned Canada, we see that's an opening emerging market. The world is trying to figure what these earlier credit prices are going to be valued at, is that new federal regulation in Canada goes into effect between now and next June. And then obviously with Oregon and Washington opening up, they all seem to be hanging around the same sort of $90 to $100 credit price. So, obviously we want to see -- we would like to see that go back up, and if I was going to have an outlook, it seems to have stabilized some more kind of in that range.
Okay, thank you.
Thank you. The next question is coming from Connor Lynagh of Morgan Stanley. Please go ahead.
Yes, thanks. I wanted to return to the topic of export markets and sort of the global balance. As we get closer to Europe's proposed date to stop taking Russian refined products, what's your sort of high-level view of how the market when we position, and the sort of implication I'm wondering about here is you highlight Latin America as a key area of your exports, is that likely to change, do you think Russian volumes will be competitive there, just high-level thoughts on that will be great.
Yes, it's difficult to know what's going to happen with the sanctions. I think we see some South American countries that seem to be interested in taking some Russian barrels. So, that certainly could be a scenario that develops some of the Russian diesel makes its way to South America. And then we backfill into Europe, I could see that happening, but we don't really have a lot of clarity what's going to happen.
I guess then I'm just trying to triangulate, maybe this is more of a shorter term comment, but you were suggesting earlier that there probably was not a high likelihood that U.S. diesel in particular will be flowing to Europe, is that more of a near-term comment? And then if the sanctions were to enact, would you revisit that view or you just -- basically with the duration of that expectation?
Yes, certainly in the short-term, freight rates are high, and we see a better incentive going into Latin America. I don't know what's going to happen in terms of Russian sanctions in the rebalancing. So, better we just kind of wait and see.
All right, fair enough. Maybe just to sneak one last one in here, capture rates have actually held up pretty strong in the refining business. Anything that we should think about in terms of big swing factors in the third quarter here? Do you think that 2Q result is pretty indicative of where you are going to be in the near-term?
Hi, this is Lane. So, I would say, normally speaking absent any big moves in flat price, it would be fairly similar.
Appreciate it. I'll turn it back.
Thank you. The next question is coming from Neil Mehta of Goldman Sachs. Please go ahead.
Yes, good morning, team. Congrats on a great quarter here. The first question was around the blender's tax credit. We got some news out of Wash last night that there could be an extension there. So, just would love your perspective on what that could mean for the DGD business? And how do you understand ruminations in Washington?
Well, this is Eric, I'll start. The BTC obviously is part of the business model that we capture with renewable diesel obviously, and we have always said that we are fairly certain there would be some sort of a blender's tax credit, because there's always been one for them for the last decade. We have seen, you know, there's some view that without a blender's tax credit the [defo RIN] [Ph] would pick it up, and maybe not perfectly dollar-for-dollar, but certainly sort of the 70%-80% range. And so, we will see how this plays out. But certainly it's supportive of the renewable business. I don't know if Rich you wanted to comment at all on the political side.
Yes. This is Rich Walsh. I mean we just saw a bill came out late last night, 700 pages, we are looking through it. I mean there are some things in there that are helpful to our business, the tax credit obviously we're just talking about, there is also a SAF tax credit in there as well that we will be looking at, and there're some things too we are trying to sort through. So, I think this has surprised everybody that came out that quick, I don't think we really ever thought that the blender's tax credit was going to be -- tax credit would be a problem without -- end up on one of these bills before the end of the year. But it's always good to see it looking stronger and on the forefront.
All right, great catching it. Follow-up is just on yield switching, we are in environment now, we are obviously heating oil and distillates trading well above gasoline, do you see the industry and the company being able to switch to capture that, and does that take some pressure off as the distillates, how the equation help to recapture inventory?
Hey, Neil. This is Lane. So, Gary kind of addressed this a little bit, our assets have been in max distill mode for a few weeks. And so, one of the dynamics that's occurring right now, as Joe covered, it's actually made distillate yields fall, or diesel deals fall. So, I guess the short answer is I have seen everybody else is doing kind of similar signals, there's not a lot of additional diesel outside of incremental runs that somebody might have, and the industry is running at pretty high utilization rates. I don't see a big opportunity to make up through decent shortfall right now.
Thanks, Lane. Thanks, guys.
Thank you. The next question is coming from Ryan Todd of Piper Sandler. Please go ahead.
Good, thanks. Maybe a follow-up on renewable diesel, and ways that spreads, and the feedstock market; obviously we have seen those spreads there [technical difficulty] first-half of the year, in particular, soybean oil moves pretty significantly in the recent time here. Can you talk a little about what you are seeing in animal fat, and kind of low feed markets in the second-half of the year, would you expect those to widen out little more, and then as you look towards the start up of DGD 3 would you expect kind of -- we saw late last year where as you start buying that there is some kind of normalization and equilibrium period there, where we see some volatility?
Yes, I think as you said, I mean the soybean oil market was pricey in the second quarter, but since come down, and if you look at -- feedstock availability is there, I mean we are not having any problem sourcing any of the different waste oils or animal fat feedstocks. Relative values, it goes along. With the LCFS, you know, a lot of that is not as advantage as it has been if you look at sort of this time last year. But we certainly have availability to get the feedstocks we need for DGD 3, and there is no doubts with DGD 3 being our third and largest unit starting up in the fourth quarter it will change some of the trade flows certainly in the U.S. and as well as where we can pull from all the global sources of feedstocks. So, I think you are right, we will see any impact of feedstocks in general as we change a lot of the trade flows, and then -- but I think we will see in a collaboration some time next year as it sort of settles out. How those trade flows change. And so, it will be interesting and we are in it. That will be one thing we are looking at as you start up and see like I mentioned earlier the Canadian regulation opening up and some other markets opening up, we will be looking at how that all plays out versus feed stocks.
Yes, and then maybe a quick question on project spend and the environment. I mean from your update it clearly doesn't see you are having an impact on timing. Any impact that the inflationary environment or supply chain I think it will have on capital budget, things like [indiscernible] project or DGD 3 as we look over the next 12 months?
Hi, this is Lane; all those projects where steel prices and labor and everything else is locked in prior to sort of this inflationary time that we are experiencing right now.
Perfect. Thank you.
Thank you. The next question is coming from Sam Margolin of Wolfe Research. Please go ahead.
Hello, how are you?
Hey, Sam.
Hey, Sam.
Good. You?
Good. Thanks. I want to ask about a comment I heard earlier on the call that made me think you mentioned high sulfur fuel spreads are blowing out. We've got Light Sweet premiums and WCS discounts are very deep. You have also got these very wide differentials between distillate and other products, specifically gasoline. It sounds like the scenario that people imagined for IMO 2020. And I was just wondering how influential do you think that is in the market today given everything else that's going on?
I think you are seeing a lot of pull through of IMO 2020 in the market today. It's contributing to the stronger distillate cracks that you are seeing because more diesel has been pulled in the marine sector. And then it's also contributing to the higher sulfur fuel discounts as well.
Hi, this is Lane. I'll add to that. It's also probably some of the really high valuations on sort of I am going to say sort of the landing basis weaker, because again it's a little bit -- it's not unlike what's happening on natural gas, the marginal refiner trying not to make high sulfur fuels bidding up the Light Sweet market, so they can try to stay out of that market, right? So, it's propping up that the value of that crude versus medium sours.
Okay, thank you. And then, there is a follow-up for drilling down on renewable diesel conversation and maybe on the policy side. But some feedback that we've gotten recently from other industry contact is that renewable fuels including ethanol have moved very much into the energy security category. And almost that's taking prominence over the carbon and emission side. And then, that's spurring a lot of support -- incremental support I should say from regulators and DC. I was wondering if you are seeing the same thing when you interact with your counterparts in the government.
This is Rich. I'll take an opportunity there. I would just qualify by saying they are low carbon too. So, they are not moving just into security. They are also part of the low carbon solution. So, if you look at light carbon renewable diesel, it actually can outperform on a carbon intensity basis some of the EV alternatives that are out there. So, I think, one, what you are starting to see now is a realization among regulators that actually these low carbon liquid fuels are dropping. They are cheaper to implement. They are available for consumers. And they provide an opportunity to also solve some of the climate issues that are out there. So, I mean I think what you are seeing is recognizing in the marketplace that these might be better alternatives. And, of course, they are domestic and the real strength of the U.S. economy. So, it's not surprising that you are starting to see more affection for the low carbon fuels.
All right. Thanks so much.
Thank you. The next question is coming from Jason Gabelman of Cowen. Please go ahead.
Hi, taking my questions. I want to ask firstly on the policy side, and the government seemed interested in intervening in the markets when petroleum prices got too high, only a month ago, and there is obviously concerns into the back-half of the year that prices can rise again particularly on the flat [crude toys] [Ph]. So, I was wondering if you could maybe discuss a bit higher conversations with the government when particularly around petroleum products export banner quota and if you think that's a realistic policy option that the government could implement in the future, and how that would impact you? And I have a follow-up. Thanks.
Okay. So, Lane and I had the opportunity to meet with the Secretary of Energy and members of her team in response to President Biden's request, and I would consider the meeting to be constructive. She was well-briefed on what the issues were, and the implications of some of the policy changes that you just mentioned. We talked about various options that could be implemented in the short-term, it would help take some of the pressure off of fuel prices that have those in hand, and in fact the staff -- her staff has continued to follow-up with members of our team and other attendees in that meeting to see what might make sense to try to implement. So, it was a good meeting. Lane, anything you would add to that?
The only thing I would add, I don't remember any mention of trying to limit exports --
No, no.
I will really not talk about whatsoever.
And yes, it goes to my point that they understand the implications of some of these decisions. You know, banning exports doesn't have the effect that they would want to have as far as we can tell. It would probably just put some pressure on the industry, and it would certainly drive the global prices higher without the U.S. supply to backfill some of the shortfalls that are out there. So, they seem to have a keen grasp for that. And that was encouraging to us, but I consider it was a constructed meeting, and they're interested in solutions. It's always interesting to see what happens after these conversations take place, and would there be any actual follow-up with it, but there is still talking. So, more to come, Jason.
All right. Were there any potential solutions that you and the representatives you met with eye on?
Yes. I think one of the things was RVP change.
RVP in relaxing self-respect, that was essentially I think the major -- ongoing policy there's essentially an initiative that you could give, it would help maybe -- some of the U.S. refiners have to export because of self-respect. That's fairly clear. And so, I think that -- and then the other idea was again like what Joe just mentioned, relaxing the RVP in some of these, and that would require some of the non-attainment metropolitan areas would have to go from reformulated to a conventional land. That's a little bigger move, but those are the things that we talked about.
Got it. That's really helpful. And my follow-up just on DGD, we are getting to this cash flow inflexion point in the business when DGD 3 starts up, and I was wondering if you could help us think about guideposts for what cash distribution policy will be from the joint venture back to the partners, or at least a time when we could expect an update on that? Thanks.
Okay. This is Jason. I will start off, and then maybe Eric can chime in. We all know how DGD was -- the business was build, we use cash flows from the business, it's funded, all the growth are largely funded till now. We will DGD 3 coming online in the fourth quarter. So, there should be some tests, cash flows to look out at the time and the partners will be [indiscernible] what to do with it.
Yes. So, obviously we do expect there to be a positive cash flow next year with the DGD 3 starting up, and capital finishing on that project. And so, obviously we will have to work with our partner on what we want to do with that cash. And so, like we have said, we're going to take a pause after DGD 3 starts up, and we kind of take that a look on the market of -- you know, lot of things we have talked about today between feedstocks and new product elements, and then we hook with the recent policy discussions that came out last night, you know, what we want to do with the cash, but obviously there should be a cash flow to discuss in 2023 associated with DGD.
All right, thanks a lot for the answers.
Yes.
Thank you. The next question is coming from Matthew Blair of Tudor, Pickering, Holt. Please go ahead.
Hey, good morning. If this potential DPC for SAF goes through, would you think about adding SAF capability at DGD 3, and if so, what kind of yields should we be thinking about?
Yes, so, obviously, there's a lot of things we got to still get the details of before -- but we certainly have a project in the wings that is waiting to see how this SAF credit is going to play out. And so, there is a project that we looked at for -- that we continue to do engineering on that would bolt-on SAF capability to DGD 3 with roughly a kind of 50-50 yield of SAF and renewable diesel. So, it would be a significant increase in SAF capability for the U.S., obviously the largest producer of SAF. So, it does like you it could be a possibility, but like I said, a lot of details to work through from a policy standpoint, and then as well that has to be discussed with our partner.
Sounds good. And then, could you walk us through the Q2 hedging impacts at DGD? I think in Q1 it was a headwind of $119 million. What does that look like for Q2? And this, like an inventory hedge or a margin hedge, any details there?
Yes, that's -- all those details will be in the Q. And what I would say is really, it's all just a product of backwardation being more severe in the second quarter than the first quarter. So, it was a larger impact and that's why, as we said earlier, margin capture was much lower mostly just because of the market effects on ULSD. But I think we see that probably looking a little more favorable in the back-half of the year. But if that's all, it'll really be tied to how the ULSD market plays out. But currently looks better, let's see how the rest of the year plays out.
Great, thank you.
Thank you. That brings us to the end of the question-and-answer session. I would like to turn the floor back over to Mr. Bhullar for close comment.
Great, thank you. We appreciate everyone joining us today. Obviously, feel free to contact the IR team if you have any additional questions. Thank you, everyone, and have a great day.
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