Valero Energy Corp
NYSE:VLO
If you don’t study any companies, you have the same success buying stocks as you do in a poker game if you bet without looking at your cards.
Utilize notes to systematically review your investment decisions. By reflecting on past outcomes, you can discern effective strategies and identify those that underperformed. This continuous feedback loop enables you to adapt and refine your approach, optimizing for future success.
Each note serves as a learning point, offering insights into your decision-making processes. Over time, you'll accumulate a personalized database of knowledge, enhancing your ability to make informed decisions quickly and effectively.
With a comprehensive record of your investment history at your fingertips, you can compare current opportunities against past experiences. This not only bolsters your confidence but also ensures that each decision is grounded in a well-documented rationale.
Do you really want to delete this note?
This action cannot be undone.
| 52 Week Range |
118.3752
180.9246
|
| Price Target |
|
We'll email you a reminder when the closing price reaches USD.
Choose the stock you wish to monitor with a price alert.
This alert will be permanently deleted.
Valero Energy Corp
You don't have any saved screeners yet
Greetings, ladies and gentlemen, and welcome to the Valero Third Quarter 2021 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]. If anyone should require operator assistance during the conference [Operator Instructions]. As a reminder, this conference is being recorded. It is now my pleasure to introduce your host, Mr. Homer Bhullar, Vice President of Investor Relations & Finance. Thank you, sir. Please go ahead.
Good morning, everyone and welcome to Valero Energy Corporation's Third Quarter 2021 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 & 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 investorvalero.com. Also 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 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 will turn the call over to Joe for opening remarks.
Thanks, Homer. And good morning, everyone. We saw significant improvement in refining margins globally in the third quarter as economic activity in mobility continued to recover in key markets. Finding margins were supported by strong recovery in product demand, coupled with product inventories falling to low levels during the quarter. In fact, total U.S. light product inventories are now at 5-year lows, and total light product demand is over 95% of the 2019 level.
Across our system, current gasoline sales are at 95% of the 2019 level, and diesel sales are 10% higher than in 2019. And on the crude oil side, medium and heavy sour crude oil differentials widened during the quarter as OPEC+ increased supply. Hurricane Ida resulted in some downtime at our St. Charles in Miro refineries and the Diamond Green Diesel Plant. We immediately deployed emergency teams and supplies after the storm to help our employees, their families, and the surrounding communities in the restoration and recovery effort.
The affected facilities did not sustain significant damage from the storm and once power and utilities were restored, the plants were successfully restarted. I'm very proud of our team's efforts in the ability to safely shutdown and restart our operations. Despite the impacts of the hurricane, we also completed the Diamond Green Diesel expansion project, DGD 2. In the third quarter, ahead of schedule, and on-budget and are in the process of starting up the new unit. DGD 2 increases renewable diesel production capacity by 400 million gallons per year, bringing DGD's total renewable diesel capacity to 690 million gallons per year. In addition, we successfully completed and started up the new Pembroke Cogeneration unit in the third quarter.
Which is expected to provide an efficient and reliable source of electricity and steam and further enhance the refineries competitiveness. Looking ahead, the DGD 3 project at our Port Arthur refinery continues to progress and is still expected to be operational in the first half of 2023. With the completion of these 470 million gallons per year plan, DGGS total annual capacity is expected to be 1.2 billion gallons of renewable diesel, and 50 million gallons of renewable naphtha. The large-scale carbon sequestration project with BlackRock and Navigator is also progressing on schedule. Navigator has received the necessary board approvals to proceed with the carbon capture pipeline system, as a result of a successful binding open season.
Valero is expected to be the anchor shipper with 8 ethanol plants connected to this system, which should provide a higher ethanol product margin, uplift. The Port Arthur Coker project, which is expected to increase the refineries utilization rate and improved turnaround efficiency, is still expected to be completed in 2023. On the financial side, we remain disciplined in our allocation of capital, which prioritizes a strong balance sheet and an investment-grade credit rating. We redeemed the entire outstanding principal amount of our $575 million floating rate senior notes due in 2023 in the third quarter. And we ended the quarter well-capitalized with 3.5 billion of cash and 5.2 billion of available liquidity excluding cash.
Looking ahead, we continue to have a favorable outlook on refining margins as a result of low global product inventories, continued demand recovery, and global balances supported by the significant refinery capacity rationalization seen over the last year-and-a-half. In addition, the expected high natural gas prices in Europe and Asia through the winter should further support liquid fuels demand as power generation facilities, industrial consumers, and petrochemical producers see incentives to switch from natural gas to refinery oil products for feed stock and energy needs. Continued improvement in earnings of our core refining business, coupled with the ongoing expansion of our renewable’s businesses, should strengthen our competitive advantage and drive long-term shareholder returns. So, with that, Homer, I'll hand the call back to you.
Thanks, Joe. For the third quarter of 2021, net income attributable to Valero stockholders was $463 million or $1.13 per share compared to a net loss of $464 million or $1.14 per share for the third quarter of 2020. Third quarter 2021 adjusted net income attributable to Valero stockholders was $500 million or $1.22 per share compared to an adjusted net loss of $472 million or $1.16 per share for the third quarter of 2020. For reconciliations to adjusted amounts, please refer to the financial tables that acCompany the earnings release. The refining segment reported 835 million of operating income for the third quarter of 2021 compared to a 629 million operating loss for the third quarter of 2020. Third quarter 2021 adjusted operating income for the refining segment was 853 million compared to an adjusted operating loss of 575 million for the third quarter of 2020.
Refining throughput volumes in the third quarter of 2021 averaged 2.9 million barrels per day, which was 338,000 barrels per day, higher than the third quarter of 2020. Throughput capacity utilization was 91% in the third quarter of 2021 compared to 80% in the third quarter of 2020. Refining cash, operating expenses of $4.53 per barrel were $0.27 per barrel higher than the third quarter of 2020, primarily due to higher natural gas prices. The renewable diesel segment operating income was 108 million for the third quarter of 2021 compared to 184 million for the third quarter of 2020. Renewable diesel sales volumes averaged 671,000 gallons per day in the third quarter of 2021, which was 199,000 gallons per day lower than the third quarter of 2020.
The lower operating income and sales volumes in the third quarter of 2021 are primarily attributed to plant downtime due to Hurricane Ida. The ethanol segment reported a 44 million operating loss for the 3rd quarter of 2021 compared to 22 million of operating income for the 3rd quarter of 2020. Excluding the adjustments shown in the acCompanying earnings release tables, third quarter 2021 adjusted operating income was 4 million compared to 36 million for the third quarter of 2020. Ethanol production volumes averaged 3.6 million gallons per day in the third quarter of 2021, which was 175 thousand gallons per day lower than the third quarter of 2020. For the third quarter of 2021 G&A expenses were $195 million and net interest expense was $152 million.
Depreciation and amortization expense was $641 million and income tax expense were $65 million for the third quarter of 2021. The effective tax rate was 11%, which reflects the benefit from the portion of DGD's net income that is not taxable to us. Net cash provided by operating activities was 1.4 billion in the third quarter of 2021. Excluding the favorable impact from the change in working capital of 379 million and our joint venture partners, 50% share of Diamond Green Diesel, net cash provided by operating activities, excluding changes in DGD's working capital, adjusted net cash provided by operating activities was 1 billion.
With regard to investing activities, we made 585 million of total capital investments in the third quarter of 2021. Of which 191 million was for sustaining the business including costs for turnarounds, catalyst, and regulatory compliance, and 394 million was for growing the business. Excluding capital investments, attributable to our partner's 50% share of Diamond Green Diesel and those related to other variable interest entities, capital investments attributable to Valero were 392 million in the third quarter of 2021. Moving to financing activities, we returned $400 million to our stockholders in the third quarter of 2021 through our dividend, resulting in a payout ratio of 40% of adjusted net cash provided by operating activities for the quarter.
With respect to our balance sheet at quarter end, total debt and finance lease obligations were 14.2 billion and cash and cash equivalents were 3.5 billion. And as Joe mentioned earlier, we redeemed the entire outstanding principal amount of our 575 million floating rate senior notes due in 2023 in the third quarter. The debt-to-capitalization ratio, net of cash and cash equivalents was 37%, and at the end of September, we had 5.2 billion of available liquidity, excluding cash. Turning to guidance, we still expect capital investments attributable to Valero for 2021 to be approximately 2 billion, which includes expenditures for turnarounds, catalysts, and joint venture investments.
About 60% of our capital investments is allocated to sustaining the business and 40% to growth. And over 60% of our growth capital in 2021 is allocated to expanding our renewable diesel business. For modeling our fourth quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.67 to 1.72 million barrels per day, Mid-continent at 455 to 475 thousand barrels per day, West Coast at 230 to 250 thousand barrels per day, and North Atlantic at 435 to 455 thousand barrels per day. We expect refining cash operating expenses in the fourth quarter to be approximately $4.70 per barrel.
With respect to the renewable diesel segment, we expect sales volumes to average 1 million gallons per day in 2021. Operating expenses in 2021 should be $0.50 per gallon, which includes $0.15 per gallon for non-cash costs such as depreciation and amortization. Our ethanol segment is expected to produce 4.2 million gallons per day in the 4th quarter. Operating expenses should average $0.43 per gallon, which includes $0.05 per gallon for non-cash costs such as depreciation and amortization.
For the fourth quarter, net interest expense should be about a $150 million and total depreciation and amortization expense should be approximately $600 million. For 2021, we still expect G&A expenses excluding corporate depreciation to be approximately $850 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 2 questions, please rejoin the queue as time permits. Please respect this request to ensure other callers have time to ask their questions.
Thank you. The floor is now open for questions. [Operator Instructions]. Our first question is coming from Doug Leggate of Bank of America. Please go ahead.
Thanks. Good morning, everyone. Hi, Joe and team. Morning Homer, thanks for getting on the call [Indiscernible]. Joe, I want to start with a balance sheet question and then a macro question if I may. So, this might be for Jason, but when you think forward to 2022, you've obviously completed the renewable diesel expansion at this point, your capital this year, you obviously had growth capital in there still, and your balance sheet is still probably above where you'd like to see at mid-cycle, how should we be thinking about Capex and prioritizing the right level of debt or balance sheet that you'd like to have as we think about 2022?
Go ahead, Jason.
Okay. Yeah, On Capex, I mean, our Capex budget going forward, we're forecasting to be pretty consistent with -- as we've done in the past so really no change there. And as we end up with extra as you said, excess cash flow that -- we have our commitment to shareholders to return the 40% to 50% that really hasn't changed. We have our dividend which we think is in a pretty good place relative to the peers. And then we will have buybacks to make up to our target and then cash beyond that, we are going to look at delivering a bit, that's a commitment we made. We bought back to 575 of floating rate notes and just last month. And we're looking to do more next week. I mean, sorry, next year, as it moves forward.
We would you like that to be Jason, I guess is my point. Where do you want net debt-to-cap to be?
But we hadn't changed what we have in our frameworks to 20, 30%. So, we hadn't changed that, but we're definitely working down from where we are now. I don't know that we've changed our -- the endpoint at this time.
Okay. Thank you. Joe my macro question is really, I want to try and phrase it like this. There's a ton of moving parts, for you guys in particular with top-line reversing and obviously OPEC+ adding back oil and all the rest of it. So, you got spread side of it. And then you go the product side of it with jet-fuel perhaps being the missing link. Maybe the simplest way to ask this question is do you see for Valero 2022 at this point from what you know, as an above mid cycle year on a below mid-cycle year in terms of EBITDA, I'll leave it there. Thanks.
Thanks, Doug.
Hey Doug, this is Gary. I would tell you, on the demand side of the equation, our view of 2022 has been fairly consistent. We see gasoline and diesel demand recurring -- returning to pre -pandemic levels. Our view is jet -- it probably is the latter part of the year before jet demand recovers to pre -pandemic levels. The real change on 2022 is coming from the fact that inventories are just so low. Inventories domestically are low, but globally they are low as well. And when you look at the fourth quarter turnaround activity, it's difficult for us to see that we're going to replenish clean product inventories before next year.
And so going into next year with inventories low, we're starting to move to a view that we can see some fairly strong crack spreads. I think in addition to that, the high-cost natural gas also comes into play. When you look at places around the world that are paying $30 a million BTU for natural gas, it pressures that refining capacity and kind of raises the incremental crack spreads needed for them to run, which also pushes margins higher. So, I would tell you that we probably came in looking at 2022 slightly below mid-cycle and it's trending now more above mid-cycle type levels.
Appreciate the answers, guys. We'll talk to you in a couple of weeks. Thank you.
Thanks, Doug.
Thank you. Our next question is coming from Theresa Chen of Barclays. Please go ahead.
Hi, there. Good morning, everyone.
Morning, Theresa.
Thanks for taking my question, morning. Gary, I wanted to follow up on your comments about the natural gas pressures internationally, and clearly, we're seeing some of it domestically as well. So first maybe just on the competitive dynamics between domestic and refiners elsewhere, Europe, for example, how does -- how do you think this affects the competitive positioning of your assets, and where do you see that export or potentially going to?
Well, that's a good question. I guess might ask for some lane help here. Natural gas is what about 25% of our OpEx?
I'll [Indiscernible]
Yeah. So, you kind of figure $4 a barrel and a dollar and that's natural gas. And if you're paying $30 versus 5, you can see what that does for overall refinery cash operating expenses, which does give us a very significant advantage into those export markets. We're seeing that today. You're not seeing much flow from Europe into those Latin American markets, and we're seeing a big pull into those markets.
Got it. And maybe, switching gears a little bit, I would love to get an update on your outlook on renewable diesel economics. As DGD 2 is now starting up, and specifically, it looks like LCFS prices have hit a trough and now are seeing some signs of life consistent with Martin's previous expectations. Is this largely because of demand recovery or petroleum products in California beginning to higher deficit generation? Is there something else going on here? Would love it if Martin can look into his crystal ball again and give us a sense of where prices could go from here.
Okay, Theresa. This is Martin, I'll give that a shot. I think, yeah, we've seen the LCFS prices rebound $1.75 a metric ton now. I think some of that's due to the expectation to game the second half data out. Second quarter of '21 data will be published at the end of the month, but if you go back and look, it's really obvious the deficits after 2019, just stopped increasing. And at that time, the carbon reduction goal was moving from 6.25% to 7.5% to 8.75%. So historically each year you'd see a step change in deficits, we've seen nothing happen since 2019. and credits are keeping up with deficits and the credit bank is flat.
So that kind of explains why the pricing went away. It's not an over generation of credits, it's the lack of deficits. It's clear. And I think with the Delta variant now, hopefully, in the rear-view mirror and mobility improving, we would expect to see some pretty big changes in the deficit picture in California, going forward. And I think that's what the market is beginning to expect. As far as the renewable diesel economics, the DGD, as we signaled, we expected the margins to moderate versus the record margins in the first half of 2021.
Part of this is DGD 2 getting into the marketplace. We're impacting the waste feed stock market at this point because we're changing the flows and any time you change the flows and change the inertia of the market, you're going to see a temporary increase in price. Once the new flows work through the market, we expect those prices to moderate, and go back to what we always talk about, the annual margins. We've been very consistent the past 3 years. Our annual margins only move from 218 a gallon to 237 a gallon in that 3-year period, and we believe that margin history is a good indication of what to expect in the future.
Thank you.
Thank you. Our next question is coming from Roger Read of Wells Fargo. Please go ahead.
Yeah, good morning, everybody.
Hey, Roger.
Just, uh -- let's go ahead and beat the natural gas horse hear completely to death. I know you've got cogen plant that helps you sort of mitigate things a little bit over in Europe. As you step back and look at both your operations and think about it, you were somebody else, what are the options for mitigation of higher natural gas costs? I mean, do you hedge -- do you think others hedge? Another way to come at it is mentioned in the intro. Joe, I think you said was, probably demand for some other liquid products. So, what are the -- some of the ratios we should think about there is to how that could pull additional product demand and what are, maybe, the trigger points for why you would do that over natural gas?
Hey, Roger. This is Lane. So, I'll take a shot at some of these. One is, yeah, we do have completed our [Indiscernible] project over on Pembroke and so you'd sort of ask yourself, "Hey, a $30 gas. Does this still even work? " And it does. I mean our FID economics on that unit was about $105,000 a day of benefit, and today we're somewhere between $130 to $150,000 a day and it just has to do with the -- who the marginal supplier of electricity in that market versus an the efficient cogen. So that's where we have that margin that we have running it and it does help.
Now a lot of people in the U.K. a lot of those guys rather have cogens as well, I don't know how efficient they are, because that's where these relative economics lie. Is how efficient your cogen is versus the marginal guy in that market. Because as Gary alluded to earlier, what you're seeing is you need margin in the Atlantic Basin because of the call on their capacity to essentially run oil and satisfy the market.
So, what that means is Europe and UK are going to be very marginal in their economics, but that gives a bit -- that gives a substantially larger margin to people on this side of the Atlantic. In terms of ways to mitigate it through hedging or is a few ways, one is in just minimize gas. You can start burning propane, you can do other things, most of our refineries for their complexity, we're long gas, so we can always get into a place where we are essentially deriving our natural gas requirements from oil. And so, we played out arbitrage and signal around and try to see where that is. And the other thing is use option strategy. You know, you can go out and buy coal options for gas and in various ways of using options to mitigate your exposure. And then, obviously you can go out and buy before contract. I don't know how many people do that. It's an interesting question. And we look at it all the time and we compare -- you know, we look a little bit at his insurance because it's not free, right? And so, you have to take a view of my trying to use this to lower my exposure from a cost perspective, and my trying to -- my trying to prevent a shock incident.
In other words, something like we saw during winter storm Yuri or something like that. So, you have to sort of frame -- what are you trying to do here? Because it isn't free. And if it doesn't translate into something that costs for somebody our size, that that being just additional operating cost, we essentially paid his insurance. And so, you have other ways to do it. You can decide to fix or float as you're getting closer towards the end of the month. There's a lot of tools in our tool bag to mitigate this but at the end of the day, to try to lock in lower prices going forward, it's almost always structural contango. If you look in the curve right now, it's kind of crazy looking, and so everybody's staring at this because you can see the futures activity in the first quarter. And so, it's difficult, but we do have tools to do that.
Did you speak to fuel switching?
Great, thanks.
I did, I mean that's why I was saying we can -- we fuel switch.
Propane. Yeah, okay.
Mainly propane, but we also made gas from our operations.
Okay.
Thanks. On the -- let's look at it from a happier standpoint, the product demand side, it appears jet fuel should get a lift with some of the international travel restrictions coming off next month. And then we obviously have supply chain issues in trucking. I was just curious. You mentioned earlier that it looked like diesel demand was up versus 19 levels. Do you think there's another lift up, focused on logistics, and just general trucking demand? And then how do you see the jet fuel demand picture? Hopefully, improving as we get into year-end.
Yes, so Roger, I think there is a good chance -- some upside to diesel. We've seen good harvest demand. A lot of it depends on the fourth quarter, what happens in weather, but specifically on the trucking side, still a lot of companies struggling to find drivers to drive the trucks and get products moved around. So, I think, as we worked through that and get drivers back to work, there is a chance that you'd see more highway demand for diesel. Which is encouraging. On the jet side, we saw a nice step change in the third quarter. We were trending 71%, 72% of 2019 levels and that jumped into the 80s.
So that's nice to see. At that level, you're kind of overall total. Product demand is about 300,000 barrels a day below where it was in 2019. But you've got 675,000 barrels a day less refining capacity. So already, you're really tighter supply, demand balance is, at least, domestically, than we were pre -pandemic. And then we are seeing encouraging signs on the jet side. You look, we don't have a lot of transparency there, but the nominations that we're seeing from the airlines that we supply, seemed to show that they are anticipating a pretty heavy holiday travel season and so we would expect an uptake there with jet demand.
Great. Thank you.
Thank you. Our next question is coming from Phil Gresh of JPMorgan. Please go ahead.
Yeah. Good morning. Just following up on the last commentary around the domestic supply demand picture, how are you thinking about the export markets right now? It seems like the Brazilian demand is really starting to pick up from recent data points. So just in general, what are you seeing and then how do you think about the competitive dynamics in those export markets given the situation with European refineries right now?
Yeah, so I would tell you that, you know, our export demand has returned to pre -pandemic levels. Very good mobility in Latin America, and we're seeing very strong export demand on the diesel side, the same type thing, very good export demand and the arb to Europe is swinging kind of open and closing pull to Europe as well. So again, trade flows seem to have completely normalized to where they were pre -pandemic.
Got it. Okay. And then, my second question is just, there's been a lot of discussion of the impact of higher natural gas on European refineries, and the effect it's had on crack spread, so if we were to see a scenario or natural gas prices were to come back down in Europe, do you feel like the underlying diesel crack would still be stronger than where it was before all this happened just because of underlying demand improvements or, just curious how we should think about that?
Yeah. So, I suspect you would see some falloff in the crack spread as natural gas weakened, however, the inventory situation will continue to keep and support crack spreads. It looks to us, especially in Europe, even if they ramp up utilization, and you look at where demand is versus the inventory draw that's been trending, it's going to be very difficult for Europe to really replenish their stocks and as long as that's the case, we would expect it to support the cracks.
Okay. Got it. Thank you.
Thank you. Our next question is coming from Prashant Rao of Citigroup. Please go ahead.
Hi. Good morning. Thanks for taking my question, guys. Good morning. I wanted to ask first on -- just little bit on the capital allocation policy. Given the commentary around EBITDA being -- looking like, it could be little bit above mid-cycle next year and what you said about giving it a comfortable place on the dividend and looking to maintain your capital allocation framework. I'm just curious how DGDs earnings can, specifically the distributions from [Indiscernible] fit into that?
I think many of us have been expecting, maybe the distributions up for the partners come later. Given that you've got Capex on DGD 3 coming and that project is set for 2023 start, but is that a factor on how you think about potentially putting more money back to shareholders and specifically to the dividend? Or is the distribution not really that material versus the other sources of cash flow that you have?
Okay, this is Jason I can take a shot. And you're right, it's definitely a positive development and going to get bigger and bigger as the DGDs more units come online. So, it is significant, it doesn't change our math on how we look at it, we get half of the distributions and that's cash into us and we still acquire 40% to 50% target in our normal analysis in that aspect, but it's definitely a growing [Indiscernible] EBITDA to us it's very -- excited about and will help us going forward.
Thanks, Jason. I wanted to ask about something we haven't touched on yet, Ethanol and CCUs Project, good progress there. Couple of questions here in one, how soon could you FID or what do you need to see to be able to roll in the remainder of the footprint in to a CCS project and then up from a macro standpoint or I guess from more of a revenue standpoint, we've got some news about 45 queue increases for certain increase -- for certain industries. We've also got some volatility around the RFS and what that means for overall ethanol demand and support from the government for ethanol blending. I was just wondering if the second part of the question, if you could address how those -- all those factors might affect your thoughts about the project. Thanks.
Yeah, Prashant, this is Martin. Well, we're operating 12 ethanol plants now. 8 of them are going into the navigator system. And the ones on the eastern side -- the four on the eastern side, we're moving forward with sequestration plans at three of the four. And potentially all of them a little bit down the road, but the geology on the eastern side of the U.S. -- so this is Indiana and Ohio, is the Eastern side of the [Indiscernible] I should say, is good for CCUS. So, we're planning to do sequestration at the -- actually on-site.
So now that's going through our gated process, and still hurdles to get through there. But that's the plan. So that's where we're headed on that. And we're excited about CCUS. as you stated, the 45Q is an uplift of about $0.15 a gallon and just on a gross basis. The Low Carbon getting to a 40ci versus 70s worth almost $0.50 a gallon on a gross basis. As far as we look at demand for ethanol, we're feeling, I think, pretty good about maybe something happening with the fuel spec in the U.S. to get to a 95 RON, a higher efficiency engine. Good for the autos, good for ethanol, good for oil.
So, we're more optimistic about that than we probably have been in the past, that would increase the ethanol blending. The Ethanol is definitely in the fuel mix to stay in the U.S. And we're seeing -- now we're getting into situation too with pretty good export demand again, that's kind of picking back up post the big impacts of COVID. So, we're pretty optimistic about the future there. But it's really -- what's driving our optimism is the Low Carbon. We're deep into corn fiber ethanol at this point. Producing that at several sites and the outlook for the carbon sequestration.
Got it. Thanks, Martin. Appreciate that. Thank you very much, guys. I'll leave it there.
Thanks, Prashant.
Thank you. Our next question is coming from Manav Gupta of Credit Suisse. Please go ahead.
Hey guys. A little bit follow-up on that question. When we go back and look at 18 and 19 and you're specifically our Gulf Coast scrap, it was about averaging about 1072. You are indicators are indicating it's closer to 13 right now. Brand WCS is almost 9. I know we have still some times to go in this quarter, but the way things are shaping up is it fair to say your strongest Gulf course quarter in probably 2 to 3 years is now approaching?
Well, again, we don't know how the quarter is going to shape-up. But certainly, if you look at the month-to-date indicator, it is significantly above mid-cycle. We would agree with you on that.
Okay. And a quick follow-up here is there are number of commercial technologies out there to produce sustainable aviation fuel, but nothing works like HAFFA and nobody works HAFFA better than Valero does. And so, we're seeing out there smaller players come out with lesser commercial technologies, get big off-take agreements with airlines, big companies, and the guy who can do it that best is still sitting on the sidelines. So, I was wondering what gets Valero involved in sustainable aviation fuel?
Sure, Manav, this is Martin. Well, we're progressing our SAF production through our gated engineering process and we're currently developing, talking with customers, and as you stated, there's plenty of customers that are interested in SAF, so it's not really a demand issue. And also want to state that a DGD 4 is not required for SAF as we have -- can retrofit DGD 1, 2 or 3 or any combination thereof. The thing about SAF is it does require additional investment, a fractionator at a minimum and maybe additional equipment beyond that.
So, the price of SAP needs to be such to justify that incremental investment. So, we're not waiting engineering-wise for the final outcome on the SAP blender's tax credit. But we do think a favorable tax credit compared to the -- a dollar gallon that you get on the blender's tax credit. So favorable one to that, it's likely needed to proceed beyond engineering. And as you say, it's not a question of if we are going to produce and sell SAP, it's a question of when. But again, we're looking for positive incremental EBITDA out of this, and not just to do it. So that's what's the holdup is right now.
Thank you.
Thank you. Our next question is coming from Paul Sankey of Sankey Research. Please go ahead.
Good morning, everyone.
Hello. Paul.
It's a long time since we've worried about natural gas prices. Can you remind me what the sensitivity sort of rule of thumb you guys uses for how battle good it is, and how much that's changed since, it's been 10 years or so since it's really been a problem, has your asset-based changed in terms of sensitivity? Thanks.
Dollar change per million BTUs, about $0.20, $0.22 a barrel or gross.
Great. Lane while I have you, the crude slate has changed a lot over that period as well. Nothing from Venezuela, very low Saudi, plenty from Canada, issues with Mexico. Can you just talk about -- and also notably some significant discounts, for example, West Africa to brand, Dubai to brand. Can you talk a bit about how you're managing the crude market? Thanks.
I'll let my good friend Gary answer that question.
So far today, if you look, we're seeing the widest margin in some of the heavy feed stocks we run. You mentioned, heavy canadian has good margins, some of the fuel blend stocks that we're running today have good margin. In terms of the other light sweet to medium sour, it comes and goes. If you look at today's market, it would favor light sweet over medium sours. But in general, what we're seeing is, in our Gulf Coast assets, as you move east in the Gulf, you tend to have better economics on the medium sours, and as you move west, it favors running more light sweet.
Is the -- has the lower amount of crude coming out of the U.S. itself had a major impact?
No. As long as we are still exporting crude, that really kind of sets the Brent TI and we're a long way from getting to a point where we're not in the export markets.
Yeah, that make sense. The -- in fact my rule of thumb for my final part, what's your sensitivity to jet fuel if there's a way of framing that? Because obviously if we see that come back, I would have thought it's the highest margin product you guys produce. I just want to know how maybe what the opportunity cost has being at the lost jet fuel or what the issues have been around operations. Thanks.
This is Lane. I would tell you that I don't know if I would -- Gary, I wouldn't consider. It's all a matter of optimization. If you look at it historically it's has had the ran in it. So, you can compare jet to ULSD and you can see what it -- almost always in the industry [Indiscernible] out to the penny. So, I would say most of the time, unless there's something unusual, the market is essentially in different ULSD between jet. Now with that said, our operations, especially we can actually go -- almost go down to 0 jet, and the way we we're configured, so I wouldn't say there's been a big opportunity cost not making jet.
Now, obviously, what that means to the industry is that jet has been going into diesel. And so, to the extent it created [Indiscernible] and potentially hurt the crack, but as you've heard throughout the call, jet -- diesel demand is actually above where it was. So, there's been some offsets to all that. Specifically, I don't think us not being able to make jet's been a big [Indiscernible] to us.
Yeah, that makes sense and it's just -- you make an interesting point about how much latent diesel demand there is with the shortage of truckers and everything else. The diesel market looks really, really tight, right?
Yes.
Great. Thanks, guys.
Thank you. Our next question is coming from Paul Cheng of Scotiabank. Please go ahead.
Hey, guys. Good morning.
Morning.
I want to also ask a question on the natural gas. Lane, I think you talked about earlier when Sankey ask ed about the cost, the $0.22 per barrel. How about on the gross margin capture, given that the hydrocracker [Indiscernible] for heavy [Indiscernible] put, you use up 0.6 PCF of gas and hydro treatment [Indiscernible], so how should we look at the higher natural gas price to impact volumes on the gross margin? After that I have another question.
Yeah, it's about $0.10 a barrel in cost of goods.
Is $0.10 per barrel for every $1?
Yes.
Okay. The second question is that, I think this is for Martin. When we look at the DGD, we saw in the third quarter in ethanol, they both come in the gross margin worse than what the benchmark indicator will be. Benchmark indicator is in now number that for renewable diesel, seems like it's pretty spread. But your gross margin, accurate job, placed substantially. And then for ethanol is actually up on the gross margin indicator, but you guys are actually did not.
It is actually down. I think for ethanol it's a fiscal issue and I think that a bit of the fiscal issue on the renewable diesel in the third quarter also. So, can you maybe elaborate a bit, help us to understand what happened and also whether those trends continue into the fourth quarter? And also, if you can tell us that -- what is the current DGD 2 curve on one way? Thank you.
Hi, Paul, I might need some help in keeping those straight. Here we go. I'm going to start with ethanol. Bust it, Paul Cheng. The third quarter, as you stated, the indicator margin was $0.70 a gallon,
which was up $0.30 a gallon versus the second quarter. But what you have to remember about that indicator margin is, it's based on the Cbot corn price and does not include the corn basis. In most years, that's a fine approximation to our corn costs, but due to the low corn to stocks -- ratio of the use to -- the stocks to use ratio this year basis was extremely high. If you look at some of the U.S.D.A reports, basis was $1, $1.20 bushel. So that takes $0.30 to $0.40 out of the indicator. So, at the end of the day, the indicator was just artificially high and that kind of EBITDA was not achievable.
So, the good news is now, with the new corn crop, while the Cbot price is still high, the basis has broken. So those indicator margins you're seeing now, which are over a dollar a gallon, are pretty indicative of where the industry would be. So that's -- so it's not an ongoing issue. But this corn price is going to stay high. And we're going to go through this period probably again next year, where basis, as you get to the end of the corn crop, really gets high. But right now, we're kind of -- the basis is broken.
On DGD, the indicator was down to like $2.84 in the third quarter, pretty flat, the second quarter, but on DGD, there's quite a few things moving. The first thing I would tell you, we signaled that we would have lower margins in the third quarter. Some of that was we expected this price is -- as prices are going up, the product prices, fat prices, all that's going up. The RIN goes up immediately, but we've got a lag in our cost of goods with the fat, so when you break over and that price quits increasing or starts decreasing, then your RIN falls immediately and you're still consuming a higher-priced feed stock.
So, we had some of that in the third quarter. The other thing that's happened in the third quarter is we were out buying for DGD 2 and we're entering the market and I went through that earlier. Anytime you go into the market in a big way and change these flows, we got inertia in the market and it's going to take a while for it to get back down so we expect these [Indiscernible] prices and a price relative to soybean oil, and we're seeing a little good news there now. So, we expect that to correct itself too. And I'm trying to think what else I missed here.
What's the DGD 2 current run rate?
Hey, were just in the process of starting it up, Paul, but we're moving along well. Everything looks good, we don't have a run rate yet.
Okay. So, you haven't actually stopped running yet?
Yeah. This is Lane. We actually started it up about three days ago.
I see. Okay. We do. Thank you.
Thanks, Paul.
Thank you. Our next question is coming from Sam Margolin of Wolfe Research. Please go ahead.
Hey, good morning, everyone.
Hey, Sam.
Follow-up on capital allocation as the cycle gets firmer here. In the past, the buyback and dividend growths worked together, right? It was sort of partially enabled to grow your dividend as much as you did because you took out 30% of your shares. As we think about entering kind of the next phase of the cycle here into a potentially stronger period, do they have to be together or can you do one component of increasing capital returns without the other?
Jason is going to love me to take this one. You know Sam I mean; we don't necessarily link them together, right? We do use the 40% to 50% target. Is based on how we make our decisions. And as Jason said earlier, we've got the dividend yield kind of towards the high end of this year range right now. Maybe at the high end of the peer range. So, we'll continue to look at it going forward. And he laid out the priorities really for our use of cash as we go forward and he wants to de -lever a little bit. I guess we're what like somewhere around 37% total debt-to-cap. We'd like to, you know, push it back down closer to that 30% number we had and do that in a multitude of ways.
But anyway, that's one of our top priorities. And then we haven't given up on buybacks by any stretch of the imagination. We see them as playing a part in this capital allocation framework going forward. It's funny because you guys love us when we do it and then sometimes, we do it and the price is high and the stock comes up and you say, why did you do buybacks, right? Anyway, it's a fine balancing act for us and I think if you just revert back to the capital allocation framework and the way we've executed it in the past, I think right now, that's our plan for execution going forward.
Okay. Thanks. Very helpful. And then just -- just a follow-up for Martin on the dynamics in the renewable diesel space. This may have been a coincidence, but at the time that DGD and a competitor plant in the same area were down, the whole complex of bean oil and waste oils came down too. And some people interpreted that as a signal of just how tight the market is. A couple of plants can bring down that complex by $0.20 a pound. Was your -- is your feeling the same thing or was that just a coincidence? And there's actually some spare capacity in feedstock that's underappreciated. Thanks.
Hey Sam, this is Martin, it's a coincidence definitely on the bean oil side, I mean, when you look at that -- if you look at bean oil prices, soybean oil, just look at any veg oil price. And veg oil price, whether it's palm oil, bean oil, or canola oil, that's the big three globally, they have doubled since the fall of 2019 and all that was led by a shortage of palm oil. The palm oil stocks got lower in Malaysia. So, to put it in perspective, if you look in Malaysia and Indonesia, palm oil, that production is 6 times as large as soybean oil in the U.S. So, palm oil drives veg oil pricing.
So anytime you see soybean oil, [Indiscernible] soybean oil move, it's a lot more about palm oil likely than anything else. So now that's said, the waste pig stuff price relative to soybean oil, as I said earlier, I think DGD had had an impact on that. It gets complicated because you're getting into all kinds of tallow and slaughter rates, and the weight of animals and all this information. But we do expect that to come back out. Certainly, you've got a situation now where the waste feed stuff prices are on an energy content or way above the value of corn on an energy content. So, the people feeding waste oils are trying to figure out wastes not to feed waste oils. So, we're still optimistic about waste feed stuff in the future and really glad we have always pre -treatment capacity to handle it.
Thanks so much. Have a good day.
Thank you. Our next question is coming from Ryan Todd of Piper Sandler. Please go ahead.
Thanks. Maybe just a natural follow-up on your last comment there. But over the last 12 months, we've seen a lot of headlines about potential capacity additions in renewable diesel. But I think we've also seen a shift amongst a lot of those additions towards what I would characterize as a capital light entry to renewable diesel targeting vegetable oils and avoiding the cost of pre -treatment facility. So how do you see these trends impacting already markets over the next few years given your increasingly differentiated position on feedstock flexibility and sourcing?
Sure. Yeah, well I would say that this higher veg oil prices given what's going on in palm oil is kind of a structural shortage there now. The plantations, the trees are getting older, the yields getting less, so there's a little bit of a veg oil issue that's been coming for years, so we don't see the veg oil prices moderating. Which you have to remember that for Diamond Green Diesel for our renewable diesel business, a high veg oil prices met with a higher D4 RIN.
And the absolute veg oil pricing doesn't dictate margin for us, and also the spread between RVD soybean oil, and crude degummed soybean oil does not impact DGD. So being in this waste feed stock position with robust pre -treatment just puts us in a lot better position than the guys that are acCompanying in and running veg oils and not -- so that position I think is going to be little tough. But we feel pretty good about our position.
Good. Thanks. And then maybe -- a follow-up on er shift to refining. I assume we know your answer to use specifically, but there are quite a few -- a lot of refineries is currently being marketed out there. What would it take for you to seriously consider adding another asset to your portfolio and if not, for you specifically? How do you see this shaking out with a lot of these assets? Do you see more closures or I guess how do you see this asset long position right now playing out over the next 12 to 18 months?
All right. Well, I'll answer it this way and then Rich can say whatever he wants. We're very comfortable with the portfolio that we have today. As you know, we've got a strong track record of having grown through acquisition in the past, and there was a time in place for that strategy to be executed, and we executed it really well. And then we spent the last 10 years plus, just getting the assets up to a standard that we were comfortable operating them in. And we realize that any acquisition like that that we would we would end up going through the same process.
And so, it would have to be an incredibly compelling case for us to give that any consideration. And so, although we continue to look at what's in the market just to be sure we don't miss opportunities, I wouldn't anticipate that you should expect us to be doing anything on that front. I'd rather invest in the assets that we know, continue to optimize the assets that we have, and build the renewables business right now than investing in additional refining capacity.
Thanks, Dan. Thanks, Joe.
Thank you. Our next question is coming from Jason Gabelman of Cowen. Please go ahead.
Thanks. I guess the first one just an easy modeling. On this lower tax rate, is that a good rate to use moving forward? I think you mentioned the low rate was driven by the DGD non-op impact. So just wondering if that's a good rate and if anything, else drove the lower effective tax rate for the quarter. And secondly, I just wanted to go back to the LCFS price volatility in California.
It seems there's a lot of renewable fuel capacity coming online next year. And I'm wondering in the market we're in right now at what price does the LCFS price have to go to in order to maybe consider selling some of your renewable diesel into Europe rather than in California. I'm asking because you guys have a good position in terms of your U.S. Gulf Coast optionality’s, I'm wondering if you could give any insight to that. Thanks.
All right. Yeah, this is Mark Schmeltekopf, I'll take the question on the tax rate and then hand it over to Martin for your second question. The tax rate for the quarter does look -- it was 11%, it's a little challenging to tell you kind of what to expect in the future, but in the near future, I would say it would be somewhat under 21%. Just as a reminder, and as we said in the earnings release, you have to remember the impact that the DGD earnings have on the effective tax rate. So, our consolidated pretax income includes 100% of DGD income. And while tax expense only reflects taxes on a portion of that income, there's no tax expense on our share of the blender's tax credits included in DGDs income nor is there any tax on our partners half of DGDs income.
So that impact is pretty having an outweighed impact on our overall effective rate. And I just also want to remind you that our partner's share of DGD s income is excluded from our net income by backing it out in non-controlling interest. So, if you look at it just from a purely EPS or cash standpoint, the only benefit LIRA is getting is not being taxed on our share of the blender's tax credit, which is quite a bit lower than I think some of the analysts are thinking it does. So, what it tells you is that our results are not driven as much by the perceived tax benefit as they were by underlying recovery and margins. And so, I'll hand it over to Martin.
Sure. Thanks, Mark. Yeah, on the -- I would say on the LCFS, if you look about look at it, it's really to get to the root of your question is, again, this has been a lot more about deficit out there driving the price down and to me, credits in the first quarter of '21 renewable diesel blending was 23% in California. The highest previous quarter was 18%, but still the credits aren't just exploding in California is just a lack of deficits.
And I think as we get out of the COVID and the Delta variant and back to work and we've got a big debt lag right now in California, right? We don't know what the second quarter that is will know that the end of October, And credit prices are up, they've hit a low of a dollar [Indiscernible] $58 a ton, now they are 175. But to get to your question, we routinely go to Europe and Canada with our fuel already. We're always looking at the different markets and working for the highest impact and given our long-term contracts we'll sometimes be constrained but we're always in those markets.
All right. Thanks.
Thank you. Our next question is coming from William -- I'm sorry, Matthew Blair of Tudor, Pickering, Holt. Please go ahead.
Hey, good morning and thanks for squeezing me in here. I was wondering if you anticipate being a shipper on Capline to your Louisiana refineries, and if so, would that be WCS or perhaps some other crude? Looking at that Capline tariff filing from earlier this week, expected volumes are only a 102,000 barrels per day, which just seems kind of low, so just trying to suss out if that's due to a lack of interest from Louisiana refineries or that's due to the lack of supply with the connector pipeline not going through. Thanks.
Yeah. So, this is Gary, with most of the pipelines and Capline, really not too much different for us. Our focus has been on getting good connectivity to those pipelines, but not necessarily taking a shipper commitment. We let the producer ship, and then we buy at the other end. And I think that's what we would plan to do with Capline as well.
And do you think those volumes will be WCS coming down, or something else?
Well, that's a good question. I think it looks like initially it will be mainly like sweet [Indiscernible] certainly with the Line 3 replacement, we could see heavy Canadian making its way into cap line at some point in time. And that would be good for us, a more efficient way to get heavy Canadian to our St. Charles Refinery.
Indeed. Thanks. I'll leave it there.
Thanks, Matthew.
Thank you. At this time, I would like to turn the floor back over to management for any additional or closing comments.
Thanks, Susana. Appreciate everyone dialing in today. If you have any questions, you want to follow up on, please feel free to reach out to the IR team. Thanks, everyone, and please stay safe and healthy.
Ladies and gentlemen, thank you for your participation and interest in Valero. You may disconnect your lines or log off the webcast at this time and enjoy the rest of your day.