Valero Energy Corp (VLO) — Q3 2021 Earnings Call Transcript

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. 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 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 and 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 refinery's 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, DGDS'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 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 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. 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 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 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 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 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, 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 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 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.

Thanks. Good morning, everyone. Hi, Joe and team. Morning Homer, thanks for getting on the call. 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.

Our Capex budget going forward is expected to be consistent with what we've done in the past, so there won't be any changes there. As we generate excess cash flow, we remain committed to returning 40% to 50% to our shareholders, which hasn't changed. We believe our dividend is well-positioned compared to our peers, and we plan to conduct buybacks to reach our targets. Any additional cash will be considered for further returns, which we've committed to. Last month, we repurchased $575 million of floating rate notes, and we aim to do more next year as we progress.

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 haven't altered our frameworks to 20 or 30 percent. We haven't made that change, but we are definitely working our way down from our current position. At this moment, I’m not sure we've adjusted our endpoint.

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 want to share our perspective on demand for 2022, which has remained relatively stable. We anticipate that gasoline and diesel demand will return to levels seen before the pandemic. However, we believe that jet fuel demand may not reach those levels until later in the year. The significant change for 2022 stems from the fact that inventories are quite low, both domestically and globally. Given the turnaround activities in the fourth quarter, we find it hard to believe that we will be able to replenish clean product inventories before the next year. As we head into next year with low inventories, we are beginning to expect relatively strong crack spreads. Additionally, the high cost of natural gas is a factor. When observing regions of the world paying $30 per million BTU for natural gas, this impacts refining capacity and raises the incremental crack spreads necessary for operations, which in turn boosts margins. Therefore, our initial outlook for 2022 was slightly below mid-cycle, but it is now shifting towards levels above mid-cycle.

Appreciate the answers, guys. We'll talk to you in a couple of weeks. Thank you.

Thanks, Doug.

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 refiners and those in Europe, for example, how do you think this affects the competitive positioning of your assets, and where do you see that export potentially going?

Well, that's a good question. I guess might ask for some lane help here. Natural gas is what about 25% of our OpEx? Joe Gorder : I'll. 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 three years. Our annual margins only move 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.

Yeah, good morning, everybody.

Hey, Roger.

Let's discuss natural gas costs in detail. I understand that your cogeneration plant helps to alleviate some challenges in Europe. Considering your operations and those of others in the industry, what options are available to mitigate the impact of rising natural gas prices? Do you think other companies engage in hedging? As mentioned earlier, Joe, you indicated there might be demand for alternative liquid products. What ratios should we consider regarding how this could drive additional product demand, and what might be the key factors that would lead to choosing these alternatives over natural gas?

Hey Roger, this is Lane. I'll address some of these points. First, we have completed our project at Pembroke, and you might wonder if it still makes sense with gas prices at $30. It does. Our FID economics for that unit showed a benefit of around $105,000 a day, and currently, we're seeing benefits between $130,000 and $150,000 a day. This is influenced by the marginal electricity supplier in that market compared to an efficient cogeneration unit. Many in the U.K. also prefer cogeneration, but their efficiency varies, which is crucial for understanding these economics. As Gary mentioned earlier, the Atlantic Basin requires margins due to the capacity to use oil to meet the market demand. Consequently, Europe and the U.K. are facing challenging economics, which creates a significantly larger margin for us on this side of the Atlantic. Regarding mitigation strategies for high gas prices, we do have a few options. One is to minimize gas use, potentially by burning propane. Most of our refineries are complex, and we usually have a surplus of gas, which allows us to manage our natural gas needs through oil. We continuously analyze price signals and arbitrage opportunities. Another approach is using options strategies, like buying coal options as a hedge against gas prices. Additionally, we could purchase contracts ahead of time. How many people do that is an interesting question, and we evaluate it constantly. It's like insurance because it comes with costs, so we must assess whether it effectively lowers our expenses or protects us from unexpected events, like during winter storm Yuri. We need to clarify our goals because options aren’t free. If they don’t translate to meaningful savings for a company our size, it ultimately adds to our operating costs. We have various methods for managing price exposure, whether by choosing fixed or floating rates as we approach month-end. There are many tools at our disposal to mitigate risks, but to lock in lower prices looking forward, we need to navigate a complex market, as indicated by current futures activity. It’s a challenging situation, but we are equipped to handle it.

Did you speak to fuel switching?

Great, thanks.

I was mentioning that we can switch fuel sources.

Propane. Yeah, okay.

Thanks. Looking at the product demand side, it appears jet fuel should receive a boost with the easing of some international travel restrictions next month. We are also facing supply chain issues in trucking. I was curious about your earlier mention of diesel demand being higher compared to 2019 levels. Do you anticipate another increase in logistics and general trucking demand? Additionally, how do you view the jet fuel demand outlook? Hopefully, it will improve as we approach year-end.

Yes, Roger, I believe there is a good chance for an increase in diesel demand. We've seen strong harvest demand, and a lot depends on what happens in the fourth quarter regarding weather. Specifically, on the trucking side, many companies are still facing challenges in finding drivers to operate the trucks and move products. If we can address that and get drivers back to work, there is a possibility of increased highway demand for diesel, which is encouraging. On the jet fuel side, we experienced a significant increase in the third quarter, rising to over 80% of 2019 levels from around 71-72%. Overall product demand is still about 300,000 barrels a day lower than it was in 2019, but we have 675,000 barrels a day less refining capacity now. This has resulted in a tighter supply-demand balance domestically compared to pre-pandemic times. We are also seeing positive indications on the jet fuel front; while we lack complete visibility, the nominations from the airlines we supply suggest they are expecting a busy holiday travel season, leading us to anticipate an increase in jet demand.

Great. Thank you.

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.

Hi, good morning. Thanks for taking my question. I wanted to ask about the capital allocation policy. Considering the commentary around EBITDA potentially being slightly above mid-cycle next year and your commitment to maintaining a strong position on dividends, I'm curious about how the earnings from DGD and the distributions will fit into that. Many of us have anticipated that partner distributions might come later, especially with the upcoming Capex for DGD 3, which is expected to start in 2023. Does that influence your decision on returning more money to shareholders, particularly regarding the dividend? Or is the distribution not significant compared to your other cash flow sources?

Okay, this is Jason. I can respond. You're right; this is definitely a positive development and will continue to grow as more DGD units become operational. It's significant, and while it doesn't change our calculations, we receive half of the distributions as cash, and we still target 40% to 50% in our normal analysis. However, the growing EBITDA is something we are very excited about and will support us moving forward.

Thanks, Jason. I wanted to ask about the Ethanol and CCUs Project, as I've seen good progress there. I have a couple of questions. How soon could you make a final investment decision, and what would you need to see to include the rest of the footprint into a CCS project? From a broader perspective, particularly regarding revenue, we've heard news about increases in the 45Q tax credits for specific industries. There's also some uncertainty surrounding the Renewable Fuel Standard and its impact on ethanol demand and government support for ethanol blending. Could you discuss how these factors might influence your views on the project? Thank you.

Yes, Prashant, this is Martin. Currently, we are operating 12 ethanol plants, with 8 of them being integrated into the navigator system. For the four plants located on the eastern side, we are advancing sequestration plans for three of them. There is potential for all of them in the future, and the geological conditions in Indiana and Ohio are favorable for carbon capture, utilization, and storage. We plan to implement sequestration on-site, which is part of our gated process, although there are still challenges to overcome. We are enthusiastic about carbon capture and utilization. The 45Q tax credit provides approximately $0.15 per gallon on a gross basis, while achieving a low carbon status from 40 carbon intensity versus 70 can be worth nearly $0.50 per gallon on a gross basis. Regarding ethanol demand, we feel positive about potential changes in the U.S. fuel specifications that could elevate it to a 95 RON, which would benefit automobiles, ethanol, and oil. We are more optimistic about this than before, as it could enhance ethanol blending. Ethanol will continue to be a key component of the U.S. fuel mix, and we are witnessing a resurgence in export demand post-COVID. Our optimism is largely driven by the Low Carbon initiatives, and we are currently engaged in producing corn fiber ethanol at several locations while also focusing on carbon sequestration.

Got it. Thanks, Martin. Appreciate that. Thank you very much, guys. I'll leave it there.

Thanks, Prashant.

Hey guys. A little bit follow-up on that question. When we go back and look at 2018 and 2019 and you're specifically our Gulf Coast scrap, it was about averaging about 1072. Your indicators are indicating it's closer to 13 right now. 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 Coast 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 several 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. We are making progress on our sustainable aviation fuel production through our structured engineering process. We are currently developing and engaging with customers, and as you mentioned, there is significant interest in sustainable aviation fuel, so demand is not an issue. I also want to clarify that we do not need DGD 4 for sustainable aviation fuel production, as we can retrofit DGD 1, 2, or 3, or use any combination of them. However, producing sustainable aviation fuel requires additional investment, at least in a fractionator and potentially more equipment. Therefore, the price of sustainable aviation fuel must be sufficient to justify this extra investment. We are not holding off on engineering due to the final outcome regarding the sustainable aviation fuel blender's tax credit. However, we do believe that a favorable tax credit, better than the current dollar per gallon offered, is likely needed to move forward beyond the engineering phase. As you pointed out, it's not a question of whether we will produce and sell sustainable aviation fuel, but rather when we will do so. We are looking for positive incremental EBITDA from this venture, and that is the current hurdle we are facing.

Thank you.

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 use for how badly gas 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 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. There's been no output from Venezuela, very little from Saudi Arabia, a lot from Canada, and issues with Mexico. Can you discuss the significant discounts, for instance, West Africa to Brent and Dubai to Brent? How are you 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.

Has the lower amount of crude coming out of the U.S. 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.

That makes sense. My question is about the sensitivity to jet fuel. If we see prices return, I believe it's your highest margin product. I'm interested in knowing the opportunity cost related to the lost jet fuel and any operational issues you've encountered. Thank you.

This is Lane. I wouldn't consider it straightforward. It's all a matter of optimization. Historically, there has been a comparison between jet fuel and ULSD, and you can see they often align closely in price. Generally, unless there's something unusual, the market treats ULSD and jet fuel similarly. That said, our operations are such that we can reduce jet fuel production significantly, so I wouldn't say we've faced a major opportunity cost by not producing jet fuel. Obviously, this means that more jet fuel has been going into diesel, which may have affected the market slightly, but as mentioned earlier in the call, diesel demand is currently higher than before. There have been some offsetting factors to consider. Specifically, not being able to produce jet fuel hasn't posed a significant issue for us.

Yeah, that makes sense, and you raise an interesting point about the significant latent diesel demand due to the shortage of truckers and other factors. The diesel market appears to be very constrained, doesn't it?

Yes.

Great. Thanks, guys.

Hey, guys. Good morning.

Morning.

I would also like to inquire about natural gas. Lane, you mentioned earlier when Sankey asked about the cost, the $0.22 per barrel. Regarding the gross margin capture, considering that the hydrocracker consumes 0.6 PCF of gas and hydro treatment, how should we assess the impact of higher natural gas prices on volumes and gross margin? I have another question after this.

Yeah, it's about $0.10 a barrel in cost of goods.

Is $0.10 per barrel for every $1?

Yes.

The second question is for Martin. When we examine the DGD, we noticed that in the third quarter, both ethanol and renewable diesel had gross margins that were worse than the benchmark indicators. The benchmark for renewable diesel seems to have a substantial spread. However, your gross margin is significantly lower. Ethanol's gross margin is above the indicator, yet your figures declined. I believe this is primarily a fiscal issue, and there may also be a fiscal concern regarding renewable diesel in the third quarter. Can you provide more details to help us understand what occurred and whether these trends will persist into the fourth quarter? Additionally, could you share the current DGD 2 curve? Thank you.

Hi, Paul, I might need some assistance with this. Let’s start with ethanol. In the third quarter, as you mentioned, the indicator margin was $0.70 a gallon, which increased by $0.30 a gallon compared to the second quarter. However, keep in mind that this indicator margin is based on the CBOT corn price and does not account for the corn basis. In most years, this approximation is reasonable for our corn costs, but this year, the corn stocks-to-use ratio was very low, leading to an exceptionally high basis. According to some USDA reports, the basis was around $1 to $1.20 per bushel. This situation effectively reduces the margin by $0.30 to $0.40. Consequently, the indicator margin was inflated, and that level of EBITDA was not realistic. The positive development is that with the new corn crop, while the CBOT price remains high, the basis has decreased. The indicator margins we are currently observing, which exceed a dollar a gallon, are more reflective of where the industry currently stands. This is not a persistent issue, but corn prices are expected to remain high, and we might encounter a similar situation next year as the basis tends to rise towards the end of the corn crop. As for DGD, the indicator dropped to about $2.84 in the third quarter, remaining relatively stable compared to the second quarter. There are several factors affecting DGD. We indicated that we anticipated lower margins in the third quarter due to rising product prices, including fat prices. While the RIN prices increase immediately, there's a lag in our cost of goods with fats; therefore, when those prices stabilize or start to decrease, the RIN prices fall quickly, whereas we continue using higher-priced feedstock. We experienced some of this in the third quarter. Additionally, we were actively purchasing for DGD 2 and entering the market, which I mentioned earlier. Entering the market significantly impacts the flow, causing inertia, and it will take time for it to return to previous levels. We expect these price adjustments and the relationship between DGD prices and soybean oil to improve, and we are starting to see some positive developments in that regard. Let me think if there's anything else I might have overlooked.

What's the DGD 2 current run rate?

Hey, we're 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.

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.

Thanks for your insights. I have a follow-up for Martin regarding the dynamics in the renewable diesel market. It seemed coincidental, but when both DGD and a competing plant in the area were down, the prices for both bean oil and waste oils declined as well. Some interpreted this as an indication of how tight the market is, noting that a few plant outages could lower prices by $0.20 a pound. Do you share this view, or do you think it was merely a coincidence? Is there potentially under-appreciated spare capacity in feedstock? Thank you.

Hey Sam, this is Martin. It's definitely a coincidence regarding bean oil. When you look at the prices of bean oil and other vegetable oils like palm and canola, they have doubled since the fall of 2019 due to a shortage of palm oil. The palm oil stocks in Malaysia have decreased significantly. To put it into perspective, the palm oil production in Malaysia and Indonesia is six times larger than soybean oil production in the U.S. Therefore, palm oil significantly influences vegetable oil pricing. So whenever you see changes in soybean oil, it often relates more to palm oil than other factors. Regarding the prices of waste feedstuff relative to soybean oil, I mentioned earlier that DGD had an impact on that. It gets complicated because it involves various factors like tallow, slaughter rates, and animal weights. However, we expect the situation to improve. Currently, waste feedstuff prices based on energy content are higher than corn's energy value. As a result, those feeding waste oils are looking for alternatives. We remain optimistic about waste feedstuff in the future and are pleased to have the pre-treatment capacity to manage it.

Thanks so much. Have a good day.

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. I would say that the current high vegetable oil prices, particularly due to the situation with palm oil, indicate a structural shortage. The plantations are aging, resulting in reduced yields, leading to a persistent vegetable oil issue that has been developing over several years, so we do not expect vegetable oil prices to decrease. It’s important to note that for Diamond Green Diesel, our renewable diesel business, high vegetable oil prices combined with a higher D4 RIN do not negatively impact our margins. Additionally, the price spread between renewable diesel soybean oil and crude degummed soybean oil does not affect our operations at DGD. Being in a position that allows us to utilize waste feedstock with effective pre-treatment gives us a significant advantage compared to those relying solely on vegetable oils. Therefore, while the market may face challenges, we feel confident about our standing.

Good. Thanks. Regarding your transition to refining, we understand your perspective, but many refineries are currently available in the market. What would prompt you to seriously consider adding another asset to your portfolio? If not, how do you view the current situation with these assets? Do you anticipate more closures, and how do you see this long position developing 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 go through 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.

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.

This is Mark Schmeltekopf, and I will address the question regarding the tax rate before passing it to Martin for your second question. The tax rate for the quarter is 11%, and it's somewhat difficult to predict future rates, but in the near term, it should be slightly below 21%. As we mentioned in the earnings release, it's important to consider the effect of DGD earnings on our effective tax rate. Our consolidated pretax income includes 100% of DGD income, yet the tax expense reflects taxes on only a portion of that income. There is no tax expense on our share of the blender's tax credits associated with DGD income, nor is there tax on our partner's share of DGD income. This significantly influences our overall effective tax rate. Additionally, our partner's share of DGD's income is excluded from our net income by being accounted for in non-controlling interest. Therefore, if you look strictly at EPS or cash flow, the only advantage LIRA has is that we aren't taxed on our portion of the blender's tax credit, which is lower than what some analysts expect. This indicates that our results are influenced more by actual recovery and margins than by any perceived tax benefits. Now, I'll turn it over to Martin.

Sure. Thanks, Mark. Regarding the LCFS, to address your question, it's mainly about the increase in deficits that are driving the price down. In the first quarter of 2021, renewable diesel blending in California was 23%, compared to the previous high of 18%. However, the credits aren’t significantly increasing in California due to the lack of deficits. As we move past COVID and the Delta variant and return to work, there's a notable backlog in California. We will find out about the second quarter by the end of October. Credit prices have risen from a low of around $58 a ton to $175. In response to your question, we regularly explore markets in Europe and Canada with our fuel. We are always looking for high-impact opportunities, though our long-term contracts may sometimes limit us. Nonetheless, we are actively engaged in those markets.

All right. Thanks.

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?

That's a good question. Initially, it seems like it will primarily be light sweet, but with the Line 3 replacement, we might start seeing heavy Canadian oil enter Capline at some point. This would be beneficial for us as it provides a more efficient way to transport heavy Canadian to our St. Charles Refinery.

Indeed. Thanks. I'll leave it there.

Thanks, Matthew.

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.