Welcome to the Valero third quarter 2021 earnings conference call. At this time, all participants are on the listen-only mode. A question-and-answer session will follow the formal presentation. If you would like to ask a question, please press star one on your telephone keypad. If anyone should require operator assistance during the conference, please press star zero on your telephone keypad. As a reminder, this conference is been recorded. It is now my pleasure to introduce your host, Mr. Homer Bhullar, Vice President of Investor Relations and 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 and Chief Commercial Officer, and several other members of Valero senior management team. If you have not received the earnings release and would like a copy, you can find one on our website at 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'll turn the call over to Joe for opening remarks.
Thanks, Homer. Good morning, everyone. We saw significant improvement in refining margins globally in the third quarter as economic activity and mobility continued to recover in key markets. Refining 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 five-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. On the crude oil side, medium and heavy sour crude oil differentials widened during the quarter as OPEC plus increased supply. Hurricane Ida resulted in some downtime at our St. Charles and Meraux 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 and the ability to safely shut down 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 refinery's competitiveness. Looking ahead, the DGD3 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 this 470 million gallons per year plant, DGD's 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 eight 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 refinery's utilization rate and improve 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 feedstock and energy needs. Continued improvement in earnings of our core refining business, coupled with the ongoing expansion of our renewables businesses, should strengthen our competitive advantage and drive long-term shareholder returns. 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 third quarter of 2021, compared to $22 million of operating income for the third 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 175,000 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 was $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 Q3 2021. Excluding the favorable impact from the change in working capital of $379 million and our joint venture partner's 50% share of Diamond Green Diesel's 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 Q3 2021, of which $191 million was for sustaining the business, including costs for turnarounds, catalysts, 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 Q3 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. 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. 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 million-1.72 million barrels per day, Mid-Continent at 455,000-475,000 barrels per day, West Coast at 230,000-250,000 barrels per day, and North Atlantic at 435,000-455,000 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 fourth 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 $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 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. The floor is now open for questions. If you would like to ask a question, please press star one on your telephone keypad at this time. A confirmation tone will indicate your line is in the question queue. You may press star two if you would like to remove your question from the queue. For participants using speaker equipment, it may be necessary to pick up your handset before pressing the star keys. Once again, that's star one to register a question at this time. 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.
Morning, Doug.
Joe, I want to start with a balance sheet question and then a macro question, if I may. 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 obviously had growth capital in there still, and your balance sheet is still probably above where you'd like to see it mid-cycle. How should we think 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, our CapEx budget going forward, we're forecasting to be pretty consistent with as we've done in the past. Really no change there. As we end up with extra, as you said, excess cash flow, we have our commitment to shareholders to return 40%-50%. That really hadn't changed. We have our dividend, which we think is in a pretty good place relative to the peers. We'll have buybacks to make up to our target. Cash beyond that, we are going to look at de-levering a bit. That's a commitment we made. We bought back the $575 million of floater rate notes just last month. We're looking to do more next week. I mean, sorry, next year as we move forward.
Where would you like that to be, Jason, I guess is my point? Where do you want that net debt to cap to be?
Well, we haven't changed what we have in our frameworks of 20%-30%, so we haven't changed that, but we're definitely working down from where we are now. I don't know that we've changed 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 Capline reversing and obviously OPEC plus adding back oil and all the rest of it. You've got the spread side of it, and then you've got 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 or a below mid-cycle year in terms of EBITDA? I'll leave it there. Thanks.
Thanks, Doug.
Yeah, 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 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 has come from the fact that inventories are just so low. Inventories domestically are low, but globally they're low as well. 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. Going into next year with inventories low, we're starting to move to a view that we could see some fairly strong crack spreads. I think in addition to that, the high cost natural gas also comes into play.
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. 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.
Yeah. Thanks, Doug.
Thank you. Our next question is coming from Theresa Chen of Barclays. Please go ahead.
Hi there. Morning, everyone.
Morning, Theresa.
Thanks for taking my question. Morning.
Sure.
Gary, I wanted to follow up on your comments about the natural gas pressures internationally. Clearly we're seeing some of it domestically as well. First, maybe just on the competitive dynamics between domestic and refiners elsewhere, Europe for example. How do you think this affects the competitive positioning of your assets and where do you see that export arc 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?
Oh, something like that, yeah.
Yeah. You kind of figure $4 a barrel and $1 that's natural gas. 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. 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 recovering for 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 to $1.75 a metric ton now. I think some of that's due to the expectation of getting the second half data out. Second quarter of 2021 data will be published at the end of the month. If you go back and look, it's really obvious the deficits after 2019 just stopped increasing. At that time, the carbon reduction goal was moving from 6.25% to 7.5% to 8.75%. Historically, each year you'd see a step change in deficits. We've seen nothing happen since 2019. Credits are keeping up with deficits and the credit bank's flat. That kind of explains why the pricing went away. It's not an over generation of credits, it's a lack of deficits. It's clear.
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. I think that's what the market is beginning to expect. As far as the renewable diesel economics at DGD, as we had 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 feedstock market at this point because we're changing the flows. 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. Go back to what we always talk about, the annual margins.
We've been very consistent the past three years. Our annual margins only moved from $2.18 a gallon to $2.37 a gallon in that three-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 let's go ahead and beat the natural gas horse here completely to death. I know you've got the 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 if 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. What are some of the ratios we should think about there as to how that could pull additional product demand and what are maybe trigger points for why you would do that over natural gas?
Hey, Roger, this is Lane. I'll take a shot at some of this. One is, yeah, we have completed our cogen project over in Pembroke, you'd sort of ask yourself, "Hey, at $30 gas, does this still even work?" It does. Our FID economics on that unit was about $105,000 a day of benefit. Today we're somewhere between $130,000-$150,000 a day, it just has to do with who the marginal supplier of electricity in that market versus sort of an efficient cogen. That's sort of the margin that we have running it does help. Particularly in the U.K., a lot of those guys over there 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. As Gary alluded to earlier, what you're seeing is you need margin in the Atlantic Basin because there's a call on their capacity to essentially run oil and satisfy the market. What that means is Europe and the U.K. are going to be very marginal in their economics, but that gives a substantially larger margin to people on this side of the Atlantic. In terms of ways to mitigate it through hedging, there's a few ways. One is you can just minimize gas. You can start burning propane. You can do other things. Most of our refineries, because of their complexity, we're long gas.
We can always get into a place where we're just essentially deriving our natural gas requirements from oil. We play that arbitrage and signal around to try to see where that is. The other thing is to use option strategies. You can go out and buy call options for gas and various ways of using options to mitigate your exposure. Obviously you can go out and buy the forward contract. I don't know how many people do that. It's an interesting question. We look at it all the time. We look at it a little bit as insurance because it's not free. You have to take a view, am I trying to use this to lower my exposure from a cost perspective? Am I trying to prevent a shock incident?
In other words, something like we saw during Winter Storm Uri or something like that. You have to sort of frame what are you trying to do here? It isn't free, and if it doesn't translate into something, that cost for somebody our size ends up being just additional operating costs that we essentially paid as insurance. You have other ways to do it. You can decide to fix or float as you're getting closer into the month. There's a lot of tools in our tool bag to mitigate this. At the end of the day, to try to lock in lower prices going forward, there's almost always structural contango. If you look at the curve right now, it's kind of crazy looking. Everybody's staring at this because you can see the futures activity in the first quarter.
It's difficult, but we do have tools to do that.
Did you speak to fuel switching?
I did. That's what I was saying. We fuel switch.
Propane? Yeah, okay.
Mainly pure propane, but we also make gas from our operations.
Okay.
Thanks. 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, 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? How do you see the jet fuel demand picture hopefully improving as we go into year-end?
Yeah. 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. Specifically on the trucking side, still a lot of companies struggling to find drivers to drive the trucks and get products moved around. I think as we work through that and get drivers back to work, there is a chance that you 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, that's nice to see.
At that level, your kind of overall total light product demand is about 300,000 barrels a day below where it was in 2019. You've got 675,000 barrels a day less refining capacity. Already you're really tighter supply-demand balances, at least domestically, than we were pre-pandemic. We are seeing encouraging signs on the jet side. You look, we don't have a lot of transparency there. The nominations that we're seeing from the airlines that we supply seem to show that they're anticipating a pretty heavy holiday travel season. We would expect an uptick there with jet demand.
Great. Thank you.
Thank you. Our next question is coming from Phil Gresh of JP Morgan. Please go ahead.
Yeah, good morning. Just following up.
Good morning.
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. 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. I would tell you that 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 closed, seeing pull to Europe as well. Again, trade flows seem to have completely normalized to where they were pre-pandemic.
Okay. 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 spreads. If we were to see a scenario where 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? Just curious how we should think about that.
Yeah. I suspect you would see some fall off 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. 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.
Morning. I wanted to ask first on, just a little bit on the capital allocation policy. Given the commentary around EBITDA looking like it could be a little bit above mid-cycle next year, and what you said about a comfortable place on the dividend and looking to maintain your capital allocation framework. I'm just curious how DGD's earnings and specifically the distributions from JV fit into that. I think many of us have been expecting maybe that the distributions up to the partners come later, given that you've got CapEx on DGD3 coming, and that project is set for a 2023 start. Is that a factor in how you think about potentially putting more money back to shareholders and specifically to the dividend? 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. You're right, it's definitely a positive development and going to get bigger and bigger as the DGD's more units come online. It is significant. It doesn't change our math or how we look at it. We get half of the distributions and that's cash in to us, and we still apply our 40%-50% target and our normal analysis in that aspect. It's definitely a growing stream of EBITDA to us, which we're 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 into a CCUS project? From a macro standpoint, or I guess from more of a revenue standpoint, we've gotten some news about 45Q increases 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 all those factors might affect your thoughts about the project? Thanks.
Yeah, Prashant, this is Martin. Well, we're operating 12 ethanol plants now, and eight of them are going into the Navigator system. 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. The geology on the eastern side of the U.S., so this is Indiana and Ohio is, the eastern side of the Corn Belt, I should say, is good for CCUS. We're planning to do sequestration actually on-site. Now that's going through our gated process, and still hurdles to get through there. That's the plan. That's where we're headed on that, and we're excited about CCUS.
As you stated, the 45Qs uplift of about $0.15 a gallon and just on a gross basis, the low carbon getting to a 40 CI versus a 70 is worth almost $0.50 a gallon on a gross basis. As far as if 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. Higher efficiency engine, good for the autos, good for ethanol, good for oil. We're more optimistic about that than we probably have been in the past. That would increase the ethanol blending. Ethanol is definitely in the fuel mix to stay in the United States. We're seeing now we're getting into a situation too with pretty good export demand again, that's picking back up post the big impacts of COVID.
We're pretty optimistic about the future there. 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 Doug's question. When we go back and look at 2018 and 2019, and specifically your Gulf Coast crack, it was averaging about $10.72. Your indicators are indicating it's closer to $13.00 right now. Brent WCS is almost $9.00. I know we have still some time to go in this quarter. The way things are shaping up, is it fair to say your strongest Gulf Coast quarter in probably two to three years is now approaching?
Well, again, we don't know how the quarter's 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. A quick follow-up here is, there are a number of commercial technologies out there to produce sustainable aviation fuel, but nothing works like HEFA, and nobody works HEFA better than Valero does. We are seeing out there, smaller players come out with lesser commercial technologies, get big offtake agreements with airlines, big companies, and the guy who can do it at best is still sitting on the sidelines. 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. As you stated, there's plenty of customers who are interested in SAF, so it's not really a demand issue. I also want to state that a DGD 4 is not required for SAF, as we 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. The price of SAF needs to be such to justify that incremental investment. We're not waiting engineering-wise for the final outcome on the SAF blenders' tax credit. We do think a favorable tax credit compared to the $1 a gallon that you get on the blenders' tax credit.
A favorable one to that's likely needed to proceed beyond engineering. As you say, it's not a question of if we're going to produce and sell SAF, it's a question of when. Again, we're looking for positive incremental EBITDA out of this and not just to do it. That's what the hold up is right now.
Thank you.
That seems not very helpful.
Thank you. Our next question is coming from Paul Sankey of Sankey Research. Please go ahead.
Good morning, everyone.
Morning, Paul.
It's a long time since we've worried about natural gas prices. Can you remind me what the sensitivity, the sort of rule of thumb you guys use for how bad or 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 base changed in terms of its sensitivity? Thanks.
This is Lane. Still about a $1 change per million BTU is about $0.20, $0.20, $0.22 per barrel for us.
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. And also notably some significant discounts. For example, West Africa to Brent, Dubai to Brent. Can you talk a bit about how you're managing the crude market? Thanks.
I'll let my good friend Gary answer that question.
Far today, if you look, we're seeing the widest margin in some of the heavy feedstocks 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 kind of comes and goes. If you look at today's market, it would favor light sweet over medium sours. In general, what we're seeing is kind of 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.
Got it. Has the lower amount of crude coming out of the U.S. itself had a major impact?
As long as we are still exporting crude, that really sets the Brent TI arb, but we're a long ways from getting to a point where we're not in the export markets.
Yeah, that makes sense. Back to the rule of thumb for my final part. What's your sensitivity to jet fuel, if there's a way of framing that? Obviously if we see that come back, I would've thought it's the highest margin product you guys produce. I just wondered maybe what the opportunity cost has been of 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. Gary, I wouldn't consider. It's all a matter of optimization.
Yeah.
If you look at it historically, it's had the RIN in it, so you can compare jet to ULSD. Almost always, the industry irons that out to the penny. I would say most of the time, unless there's something unusual, the market is essentially indifferent to ULSD between jet. With that said, our operation is such that we can actually almost go down to zero jet, and the way we were configured. I wouldn't say there's been a big opportunity cost not making jet. Obviously, what that means to the industry is that jet has been going into diesel, and so to the extent it created length and potentially hurt the crack. As you've heard throughout the call, 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 hit to us.
Yeah, that makes sense. 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 tight, right?
Yes.
Yes.
Great. Thanks, guys.
Thank you. Our next question is coming from Paul Cheng of Scotiabank. Please go ahead.
Hey, guys. Good morning.
Morning.
Morning.
Want to also ask a question on the natural gas. Lane, I think you talked about earlier when Sankey asked about the cost, say $0.22 per barrel. How about on the gross margin capture?
Given that the hydrocracker probably for every barrel of output you use about 0.56 MCF of gas, and hydrotreater also uses gas. How should we look at the higher natural gas price, the impact on the gross margin? After that, I have another question.
Yeah, it's about $0.10 a barrel in cost of goods.
Yes, $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 and ethanol, they both come in the gross margin worse than what the benchmark indicator will be. Benchmark indicator, at least in our number, that for renewable diesel, it seems like it's pretty flat. Your gross margin actually dropped quite substantially. For ethanol, it's actually up on the gross margin indicator, but you guys actually did not. That's actually down. I think for ethanol it's a feedstock issue, and I think there's a bit of the feedstock issue on the renewable diesel in the third quarter also. Can you maybe elaborate a little bit, help us to understand what happened? Also whether those trends continued into the fourth quarter.
Also if you can tell us that what is the current DGD 2 current run rate. Thank you.
All right, Paul, I might need some help in keeping those straight. Here we go. I'm going to start with ethanol.
You're busted, 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. 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 cost, but due to the low corn to stocks ratio, the stocks to use ratio this year, basis was extremely high. If you look at some of the USDA reports, basis was $1, $1.20 a bushel. That takes $0.30-$0.40 out of the indicator. At the end of the day, the indicator was just artificially high, and that kind of EBITDA was not achievable.
The good news is now with the new corn crop, while the CBOT price is still high, the basis has broken. Those indicator margins you're seeing now, which are over $1 a gallon are pretty indicative of where the industry would be. It's not an ongoing issue. This corn price is going to stay high. 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. Right now, the basis is broken. On DGD, the indicator was down to $2.84 in the third quarter, pretty flat the second quarter. 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 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. When you break over and that price quits increasing or starts decreasing, then your RIN falls immediately, and you're still consuming a higher price feedstock. 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, you've got inertia in the market, and it's going to take a while for it to get back down.
We expect these waste feedstock prices, how they price relative to soybean oil, to come off. We're seeing a little good news there now. We expect that to correct itself too. I'm trying to think what else I missed here.
What's the DGD 2 current run rate?
Okay, we're just in the process of starting it up, Paul, but we're moving along well. Everything looks good, but we don't have a run rate yet.
Oh, okay. You haven't actually start running yet?
Yeah. This is Lane. We actually started it up about three days ago.
I see. Okay. Will do. Thank you.
Thanks, Paul.
Thank you. Our next question is coming from Sam Margolin of Wolfe Research. Please go ahead.
Hey. Morning, everyone.
Hi, Sam.
Follow-up on capital allocation. As the cycle kind of gets firmer here. In the past, the buyback and dividend growth 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's gonna let me take this one. Sam, we don't necessarily link them together, right? We do use the 40%- 50% target based on how we make our decisions. As Jason said earlier. We've got the dividend yield towards the high end of the peer range right now, maybe at the high end of the peer range. We'll continue to look at it going forward. He laid out the priorities really for our use of cash as we go forward. He wants to delever a little bit. I guess we're, what? Somewhere around 37% total debt to cap.
Yeah.
We'd like to push it back down closer to that 30% number we had, and you can do that in a multitude of ways. Anyway, that's one of our top priorities. 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, then you say, "Oh, why'd 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. Just a follow-up from 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. Some people interpreted that as a signal of sort of just how tight the market is, right? A couple of plants can bring down that complex by $0.20 a pound. 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.
Sam, this is Martin. It's a coincidence definitely on the bean oil side. When you look at that, if you look at bean oil prices, soybean oil, just look at any veg oil price. 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 low in Malaysia. To put it in perspective, if you look at Malaysia and Indonesia palm oil, that production is 6x as large as soybean oil in the United States. Palm oil drives veg oil pricing. Anytime you see soybean oil, just crude degummed soybean oil move, it's a lot more about palm oil likely than anything else.
Now that said, the waste feedstock price relative to soybean oil, as I said earlier, I think DGD's had an impact on that. It gets complicated because you get into all kinds of tallow and slaughter rates and the weight of animals and all this information. We do expect that to come back out. Certainly, you've got a situation now where the waste feedstock prices are on an energy content or way above the value of corn on an energy content. The people feeding waste oils are trying to figure out ways not to feed waste oils. We're still optimistic about waste feedstock in the future, and we're really glad we have all this pretreatment capacity to handle it.
Thanks so much. Have a great day.
Thank you. Our next question is coming from Ryan Todd of Piper Sandler. Please go ahead.
Good, thanks. Maybe this is a natural follow-up on your last comment there. Over the last 12 months, we've seen a lot of headlines about potential capacity additions in renewable diesel. I think we've also seen a shift amongst a lot of those additions towards what I would characterize as kind of a capital light entry to renewable diesel, targeting vegetable oils and avoiding the cost of pretreatment facilities. How do you see these trends impacting RD 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, there's kind of a structural shortage there now. The plantations, the trees are getting older, the yield's getting less. 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. What you have to remember that for Diamond Green Diesel, for our renewable diesel business, a high veg oil price is met with a higher D4 RIN, and the absolute veg oil pricing doesn't dictate margin for us. Also, the spread between RBD soybean oil and crude degummed soybean oil does not impact DGD.
Being in this waste feedstock position with robust pretreatment just puts us in a lot better position than the guys that are coming in and running veg oils and not. That position I think is going to be a little tough, but we feel pretty good about our position.
Great. Thanks. Maybe a different follow-up on or a shift to refining. I assume we know your answer to you specifically, there are quite a few, a lot of refineries currently being marketed out there. What would it take for you to seriously consider adding another asset to your portfolio? 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 kind of 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. Rich Lashway. 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 and place for that strategy to be executed, and we executed it really well. We spent the last 10+ years just getting the assets up to a standard that we were comfortable operating them in. We realized that any acquisition like that we would make, we would end up going through the same process. It would have to be an incredibly compelling case for us to give that any consideration.
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 invest in additional refining capacity.
Okay. 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 one. Is this lower tax rate, is that a good rate to use moving forward? I think you mentioned the lower rate was driven by the DGD non-op impact. Just wondering if that's a good rate, and if anything else drove the lower effective tax rate for the quarter. Secondly, I just wanted to go back to the LCFS price volatility in California. It seems like 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.
I'm wondering if you could give any insight to that. Thanks.
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 low. It was 11%. It's a little challenging to tell you what to expect in the future, but in the near future, I would say it would be somewhat under 21%. Just as a reminder, as we said in the earnings release, you have to remember the impact that the DGD earnings have on the effective tax rate. Our consolidated pre-tax income includes 100% of DGD's income. While tax expense only reflects taxes on a portion of that income, there's no tax expense on our share of the blenders' tax credits included in DGD's income. Nor is there any tax on our partners' half of DGD's income.
That impact has an outweighed impact on our overall effective rate. I just also want to remind you that our partners' share of DGD's income is excluded from our net income by backing it out in non-controlling interests. If you look at it just from a purely EPS or cash standpoint, the only benefit Valero's getting is not being taxed on our share of the blenders' tax credit, which is quite a bit lower than I think some of the analysts are thinking that it is. 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. I'll hand it over to Martin.
Sure. Thanks, Mark. I would say on the LCFS, if you look at it, to get to the root of your question, this has been a lot more about deficits out there driving the price down than too many credits. In the first quarter of 2021, renewable diesel blending was 23% in California. The highest in previous quarter was 18%, still, the credits aren't just exploding in California. It's just a lack of deficits. I think as we get out of the COVID and the Delta variant and back to work, we've got a big data lag right now in California, right? We don't know what second quarter data is. We'll know that at the end of October. Credit prices are up. They hit a low of what? $158 a ton, now they're $175.
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 net back 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.
Good morning. Thanks for squeezing me in here. I was wondering if you anticipate being a shipper on Capline to your Louisiana refineries. 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 102,000 barrels per day, which just seemed kind of low. Just trying to suss out if that's due to a lack of interest from Louisiana refineries or if that's due to a lack of supply with the connector pipeline not going through. Thanks.
Yeah. This is Gary. With most of the pipelines, and Capline is 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.
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 a light sweet crude, but certainly with the Line 3 replacement, we could see heavy Canadian making its way into Capline 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'd like to turn the floor back over to management for any additional or closing comments.
Thanks, Dana. 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.
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