Greetings, welcome to the Valero's Second Quarter 2021 Earnings Conference Call. At this time, all participants are on a listen-only mode. A question- and- answer session will follow the formal presentation. If you would like to ask a question, you may do so by pressing 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 being recorded. It is now my pleasure to introduce your host, Homer Bhullar, Vice President, Investor Relations and Finance. Thank you, sir. Please go ahead.
Good morning, everyone, and welcome to Valero Energy Corporation's Second 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's 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, and good morning, everyone. Our system's flexibility and the team's relentless focus on optimization in a weak but otherwise improving margin environment enabled us to deliver positive earnings in the second quarter. More importantly, cash provided by operating activities more than covered our cash used in investing and financing activities for the quarter, even without the cash benefits from our 2020 income tax refund and the proceeds from the sale of a portion of our interest in the Pasadena Terminal. There was a significant increase in mobility in the second quarter, driving higher demand for refined products, particularly in the U.S. In fact, we're seeing demand for gasoline and diesel in excess of pre-pandemic levels in our U.S. Gulf Coast and Mid-Continent regions. Jet demand continues to ramp up as well and is around 80% of 2019's level.
We responded with higher refinery utilization to match product demand in our system. Product exports have been picking up, particularly to Latin America, with the easing of lockdowns in the region. We exported 410,000 bpd of products from our system in June, which is the highest volume since 2018. Our renewable diesel segment continues to perform exceptionally well and once again set records for renewable diesel margin and sales volumes, highlighting Diamond Green Diesel's ability to process a wide range of discounted feedstocks and Valero's operational and technical expertise. Our Ethanol segment also performed well and provided solid operating income in the second quarter as demand for ethanol increased along with higher gasoline production. Carbon sequestration project with BlackRock and Navigator is moving ahead and has garnered strong interest from additional parties in the binding open season.
Valero is expected to be the anchor shipper with eight Ethanol plants connected to this system. This project serves to help achieve our goal to lower the carbon intensity of our products while providing solid economic returns. Our Diamond Green Diesel 2 project at St. Charles remains on budget and is scheduled to be operational in the middle of the fourth quarter of this year. This expansion project is expected to increase renewable diesel production capacity by 400 million gal per year, bringing the total capacity at St. Charles to 690 million gal per year of renewable diesel and 30 million gal per year of renewable naphtha. Our Diamond Green Diesel 3 project at Port Arthur is also progressing well and is now expected to be operational in the first half of 2023.
With the completion of this 470 million gal per year plant, DGD's total annual capacity is expected to be 1.2 billion gal of renewable diesel and 50 million gal of renewable naphtha. Our refinery optimization projects remain on track, with the Pembroke Cogen project expected to be completed in the third quarter of this year and the Port Arthur Coker project expected to be completed in 2023. Looking ahead, we have a favorable outlook for refining margins as product demand continues to improve with increasing global vaccinations and mobility. In addition, there's been significant refinery capacity rationalization in the U.S. in the last couple of years, and we expect further closures of uncompetitive refineries, particularly in Europe.
We believe that product demand recovery coupled with significant refinery rationalization should be supportive of strong refining margins. We also expect to see wider medium and heavy crude oil differentials as OPEC+ increases crude supply, which should further provide support to refining margins. As low carbon fuel policies continue to expand globally, we remain well-positioned. With the current projects in progress, we expect to quadruple our renewable diesel production in the next couple of years. In addition, we continue to explore and develop opportunities in carbon sequestration, sustainable aviation fuel, renewable hydrogen, and other innovative projects to strengthen our long-term competitive advantage. With that, Homer, I'll hand the call back to you.
Thanks, Joe. Before I provide our second quarter financial results summary, I'm pleased to inform you that we recently published an updated stewardship and responsibility report, which now includes our SASB disclosures. In addition to being on track to achieve our previously announced target to reduce and offset 63% of our global refining greenhouse gas emissions by 2025 through investments in board-approved projects, the report includes a new target to reduce and offset 100% of our global refining greenhouse gas emissions by 2035. These targets are consistent with our strategy as we continue to innovate and leverage our global liquid fuels platform to expand our long-term competitive advantage with investments in economic low carbon projects.
And now turning to our quarterly summary, net income attributable to Valero stockholders was $162 million, or $0.39 per share for the second quarter of 2021, compared to $1.3 billion or $3.07 per share for the second quarter of 2020. Second quarter 2021 adjusted net income attributable to Valero stockholders was $197 million, or $0.48 per share compared to an adjusted net loss of $504 million, or $1.25 per share for the second quarter of 2020. For reconciliations to adjusted amounts, please refer to the financial tables that accompany the earnings release. The refining segment reported $349 million of operating income for the second quarter of 2021, compared to $1.8 billion for the second quarter of 2020. Second quarter 2021 adjusted operating income for the refining segment was $361 million compared to an adjusted operating loss of $383 million for the second quarter of 2020.
Refining throughput volumes in the second quarter of 2021 averaged 2.8 million bpd , which was 514,000 bpd higher than the second quarter of 2020. Throughput capacity utilization was 90% in the second quarter of 2021. Refining cash operating expenses of $4.13 per bbl were $0.26 per bbl lower than the second quarter of 2020, primarily due to higher throughput in the second quarter of 2021. The renewable diesel segment operating income was $248 million for the second quarter of 2021 compared to $129 million for the second quarter of 2020. Renewable diesel sales volumes averaged 923,000 gal per day in the second quarter of 2021, which was 128,000 gal per day higher than the second quarter of 2020. The segment set another record for operating income and sales volumes.
The Ethanol segment reported operating income of $99 million for the second quarter of 2021 compared to $91 million for the second quarter of 2020. The second quarter 2020 adjusted operating loss was $20 million. Ethanol production volumes averaged 4.2 million gal per day in the second quarter of 2021, which was 1.9 million gal per day higher than the second quarter of 2020. For the second quarter of 2021, G&A expenses were $176 million, and net interest expense was $150 million. Depreciation and amortization expense was $588 million, and income tax expense was $169 million for the second quarter of 2021. The effective tax rate was 37%, which was higher than our second quarter of 2020, primarily due to the remeasurement of our deferred tax liabilities, primarily as a result of an increase in the U.K. statutory tax rate that will be effective in 2023.
Net cash provided by operating activities was $2 billion in the second quarter of 2021. Excluding the favorable impact from the change in working capital of $1.1 billion 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 $809 million. With regard to investing activities, we made $548 million of total capital investments in the second quarter of 2021, of which $252 million was for sustaining the business, including costs for turnarounds, catalysts, and regulatory compliance, and $296 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 $417 million in the second quarter of 2021.
Moving to financing activities, we returned $401 million to our stockholders in the second quarter of 2021 through our dividend, resulting in a payout ratio of 50% of adjusted net cash provided by operating activities for the quarter. Earlier this month, our board of directors also approved a regular quarterly dividend of $0.98 per share payable in the third quarter. As Joe noted, we were able to cover all of our investing and financing activities, which includes our dividend and capital investments in the second quarter, with cash provided by operating activities, even without the benefit from the cash tax refund and the proceeds from the sale of a portion of our interest in the Pasadena Terminal. With respect to our balance sheet at quarter end, total debt and finance lease obligations were $14.7 billion, and cash and cash equivalents were $3.6 billion.
The debt-to-capitalization ratio net of cash and cash equivalents was 37%. At the end of June, we had $5 billion of available liquidity excluding cash. Turning to guidance, we 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 half of our growth capital in 2021 is allocated to expanding our renewable diesel business. For modeling our third quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.6 million bpd-1.65 million bpd, Mid-Continent at 435,000 bpd-455,000 bpd , West Coast at 250,000 bpd-270,000 bpd , and North Atlantic at 450,000 bpd-470,000 bpd.
We expect refining cash operating expenses in the third quarter to be approximately $4.45 per bbl. With respect to the renewable diesel segment, with the anticipated startup of DGD 2 in the middle of the fourth quarter, we expect sales volumes to average 1 million gal per day in 2021. Operating expenses in 2021 should be $0.50 per gal, which includes $0.15 per gal for non-cash costs such as depreciation and amortization. Our Ethanol segment is expected to produce 3.7 million gal per day in the third quarter. Operating expenses should average $0.43 per gal, which includes $0.06 per gal for non-cash costs such as depreciation and amortization. For the third quarter, net interest expense should be about $150 million, and total depreciation and amortization expense should be approximately $590 million.
For 2021, we still expect G&A expenses excluding corporate depreciation to be approximately $850 million. The annual effective tax rate should approximate the U.S. statutory rate. 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. Ladies and gentlemen, the floor is now open for questions. If you would like to ask a question, please press star, one on your telephone keypad at the 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. Again, that's star one to register a question at the time. Our first question is coming from Phil Gresh of J.P. Morgan. Please go ahead.
Yes. Hi, good morning.
Morning, Phil.
Nice job in the organic dividend coverage despite choppy refining margins here. Joe, I know you touched on some of this in the opening remarks around the macro environment. June was obviously pretty tough. July is getting better here. What do you think needs to happen going forward to see sustainable improvement in margins back to more normalized levels? Is it just demand and differentials, or do we need some of these closures you were referencing in your remarks? Just any additional thoughts?
Good morning, Phil. This is Gary. As you talked about, Joe talked about mobility increasing in the second quarter. We saw good recovery in mobility in the domestic markets, and with the recovery in mobility, we saw on-road transportation fuel demand basically recover to pre-pandemic levels. The issue we really had in the second quarter was the pace of recovery in the U.S. was just much faster than what we saw in most of the other major demand centers throughout the world. Where our margins started to track up as demand improved, eventually our market began to dislocate from the global markets, and we incentivized imports. We saw very high levels of imports later in the quarter, caused inventory to build, and as inventory built, we eventually saw margin disruption.
I think the good news for us as we go into the third quarter is that at least the markets we have good visibility into. We're seeing mobility increase in those markets like we did in the U.S. in the second quarter. With the increase in mobility, we're seeing demand take off quite nicely. We certainly see that in our Canadian markets, in the U.K., and the markets we go to in Latin America. I think that's what you really need to have sustained margin recovery is the global demand to pick up. Thus far, in July, we've seen margins that are better than we saw in the second quarter. That's certainly encouraging. On the crude side, you talked a little bit about the differentials. I think, to see meaningful move in the differentials, we need OPEC barrels back on the market.
Of course, it was good to hear OPEC plans to put 400,000 bpd back out on the market sometime post-August. I think to some degree, the markets are already reflecting that. If you look at the heavy Canadian differentials in the Gulf today, the fourth quarter has about $0.75 wider discounts than what we see in the prompt market. Again, that's $0.75 wider discounts in the face of backwardation in the Brent market. If you look at that discount as a percent of Brent, it's a fairly meaningful move that we would see as we get later in the year.
Got it. Okay. Thanks for that color. I just want to switch over to renewable diesel for the second question. The indicator margins were down sequentially, obviously because of the soybean oil-based indicator. Regardless, you put up another record quarter there, up sequentially again, presumed from the advantaged feedstock benefit. How do you see the sustainability of this trend? Were there any transitory factors in the quarter or structural things you were thinking about moving forward?
Hey, Phil, this is Martin. I think if you step back and just think about our renewable diesel segment, right? Our refining expertise has been a critical component to the development and operations of renewable diesel and ultimately the success of that business. You have to also keep in mind that we were an early mover in the space and have accumulated decades worth of knowledge, which is a lot more than almost all of our peers. Our operating reliability has been very good, and that's helped differentiate Diamond Green. We also use the same reliability processes at renewable diesel that we have applied to our refining system. Finally, structurally on the pricing, Diamond Green as well as other producers, you would expect them to have stronger results when prices are going up. The RIN price, ULSD price going up.
That value you see immediately and there's going to be a lag in the cost of sales on the feedstock. With this increasing price environment helped us somewhat.
Got it. Okay. Thank you.
Thank you. Our next question is coming from Doug Leggate of Bank of America. Please go ahead.
Thanks, fellas. Good morning. Let me also add my observations around the cash flow numbers. Sorry, I've got to follow. I didn't expect to go second in the queue. All right. Hopefully, you can hear me okay. Joe, or maybe Jason for this one. On the cash flow, obviously as things improve in the second half of the year, you've shown us that the cash coverage is going to be there, you still have the cash return commitment to investors while your balance sheet is somewhat elevated. Can you walk us through how you will prioritize the incremental cash returns, let's say over the next year or so? Will the balance sheet take priority beyond dividends? That was my first question. I've got a follow-up.
Okay. Yeah, sure. I'll be glad to talk to you about it. As Joe said, this quarter was a big step change for us in a couple of ways. We've made money for the first time where we had enough cash to cover all of our needs. That's a great place to be in. We're glad to be back there again. We did put on the $4 billion of debt last year. We have said as things normalize, that we'll initially focus on two things. First, building our cash balance back up to $3 billion plus in that range. And then second, starting to work to get our leverage down. Our June 30th cash balance was about $3.6 billion. We're in line there. We're in a pretty good spot. We're starting to working on the second problem, which is looking at our debt repayment.
We said a few times before, we would look at redeeming this tranche of three-year floaters that are callable as early as this fall. That would likely be our first step. That's still true. That's definitely something we're looking at. Then as we move forward further into this year and beyond that, we'll continue to look at other liability management opportunities. As earnings and cash generation continue to normalize, as you said, which is the way we hope things continue to move, we'll have increased optionality the more cash we have. Maintaining our credit ratings is also a priority for us, and we're targeting to have a net debt to cap around 3x in a normalized environment, which is consistent with where we were in the past. We still have our long-term net debt to cap target of 20%-30%.
To get more to your question, we also still remain committed to our capital allocation framework. Our shareholder payout ratio was 50% this quarter, and we continue to target this 40%-50% ratio on an annual basis. We do expect to be able to meet that as we move forward through the recovery and beyond, even as we work on our deleveraging strategy. We think we're going to be able to do both of them, I think would be your answer. We're certainly not going to have to sacrifice the dividend, and I don't think we'll have to sacrifice the target, the 40%-50% target either.
Yeah. I guess I was thinking more about the discretionary beyond the dividend, Jason, that's a very full and clear answer. Thank you for that. Joe, I wonder if I could bring it back to you. I don't know if you want to take this or someone else, in your prepared remarks, you talked about the perennial prospect of refinery closures, ex-U.S., I guess specifically, these are typically triggered by capital events, turnarounds, things of that nature, as you know, for the more vulnerable refineries. I'm just wondering, the fact that you were prepared to put that in your prepared remarks, do you have any particular thoughts or insights or what visibility that's giving you some comfort that it might happen this time around at an accelerated pace? I'll leave it there. Thanks.
No, Doug, that's a good question, and I don't think we've got any particular insight that anybody else doesn't have into specific assets. I think we can all look at them and say where the vulnerabilities are. I know Lane's spoken about this many times. You just want to share your thoughts?
Yeah. Doug, how we think about it is we think about regions that have, what I would say, structural disadvantages. We've talked about them before.
Sure.
If it's the East U.S., East Coast, U.S. West Coast, there's Latin America, they all have slightly different reasons for their disadvantages. The reason we focus on those areas is they flange up or we have operations in those areas, we think about how those areas will change over time and how we will respond to it. Obviously, when we have operations in those areas, we stress test and we try to understand the cash flow that our assets generate through an entire economic cycle. As you alluded to, we've said before, the things that drive assets are these big. You know, you start with, you have an issue, whether it's trade flow or reliability or whatever, you layer in chunky capital, whether it's regulatory capital or a big turnaround.
That's when these assets really fall, that operators start to think about what they're going to do. As Joe said, we don't sit there and this refinery over here or this refinery over there. We just sort of think of it regionally and where we think those issues and where closures might ultimately happen.
Appreciate the answers, fellas, and I assume the Valero portfolio is something that you're quite happy with where it is.
We always work very hard to make sure that we maintain our ongoing competitive advantage in all the markets that we operate.
Fair answer. Thanks, fellas.
Thanks, Doug.
Our next question is coming from Theresa Chen of Barclays. Please go ahead.
Good morning. Thank you for taking my questions. Maybe first, touching on DGD again, just in light of the very strong profitability we've been seeing for many quarters in a row. Given that LCFS credit prices have seen some volatility and faltering recently, how do you see that trend going forward, and what's driving that?
Hey, Theresa. This is Martin. I think one thing you have to look at is the credit bank in California. It's been pretty stable now for five quarters. But the other thing is, if you think California, we haven't seen any data from them since the end of 2020, right? There's a lag.
Tomorrow, we'll actually see the first quarter data. You might see, but it's probably a little bit of lack of knowledge, the credit bank being stable for the last several quarters. And then the other thing that I think you have to think about, do we worry about that too much? Not really, because if you had something that happened where there was a prolonged shift where the price went down in California, I'm pretty sure the response by CARB would be to move the goalpost to actually raise the carbon reduction targets because they have signaled several times they're pretty content with a $200 type per ton carbon price. We would just expect a quicker carbon reduction if there was a long-term shift in that price, which would then raise the price back up.
Got it. That makes sense. On the broader renewables front, I wanted to ask about your endeavors there, many projects you have under development, and specifically on renewable hydrogen. What kind of projects are you planning to do there?
Hi, this is Lane. What we're doing there, again, is in our St. Charles and Port Arthur refineries. As those projects flange up to our Diamond Green Diesel projects, we look for ways to essentially make renewable hydrogen from the LPGs that come off those units, and in turn, get them into an SMR. The hydrogen can go back and lowers the carbon intensity of the product out of both of those units.
Thank you.
Thank you. Our next question is coming from Roger Read of Wells Fargo. Please go ahead.
Yeah, thank you. Good morning.
Hi, Roger.
I guess I'd like to come back maybe to the first kind of question or first discussion there with you, Gary, as you were looking at the way things are improving. We've definitely seen inventories come down hard in the Europe market, and I was wondering, as you look at that, as you look at the mobility improving in some of those areas, what would be the expectation for imports over the next, I don't know, let's just say two to three months to keep it a reasonable timeframe, and what that could mean for margins potentially being measurably stronger in Q3 than they were for at least the end of Q2?
Yeah, Roger. I think the thing I'd point to is, the arb to import gasoline from Europe has really been closed most all of July. That's been encouraging to see. I think the last set of DOE data is really the first time we saw that reflected in the data imports falling off. It really has more of an impact than just the imports because we've also seen that we're, again, much more competitive in the Latin American markets. Not only was Europe exporting to the United States, but they were pushing into Latin America and causing us to lose some of the exports we typically send to that market. As things have picked up in Europe, they're not only not sending barrels to the U.S., but we're seeing our exports ramp up into Latin America.
What I would say is more normalization of trade flows, which will help inventories continue to draw and support better crack spreads.
Great, thanks. The other question a little off the typical beaten path here, but you're obviously moving aggressively more expansions of renewable diesel, as we've seen. A lot of talk about sustainable aviation fuel as one of the areas. I was just curious, is there anything you're looking at in that front? Are the economics of sustainable aviation as attractive as renewable diesel as you look at them? What would be the, I guess, to some extent, interchangeability between renewable diesel and sustainable aviation fuel?
Yeah. This is Martin. If you look at that, Roger, to make renewable jet or SAF, you have to have some additional equipment. There's a few ways to do it, but you're probably going to add a reactor, and you're certainly going to add the fractionator. That's additional capital. And then, that with your yield pattern changes a little bit where you make some more light-ins. At the end of the day, to get back to equal to renewable diesel, you're going to have to get some help on the SAF side with some additional pricing mechanism and additional green premium there. Right now, we don't see the economic incentive to make SAF. That being said, obviously, we're studying it. We're looking at everything. We're looking how the landscape changes, what's going through in all parts of the world and legislative processes or regulatory processes.
We'll keep watching it and we fully expect to be making it at some point. I don't think it's a question of if, but it's more about when.
Thank you.
Our next question is, excuse me, coming from Sam Margolin of Wolfe Research. Please go ahead.
Hi, everybody. How you doing?
Hi, Sam.
My first question is for Martin. If I could ask you to go into a little bit more detail about that yield comment you made at DGD, just given the per gallon value of all the different credits flowing in, a yield outcome is very powerful. If you're able to, can you just give a little more detail around that and how sustainable it is and how far off sort of your plans you are in terms of yield outcomes and production efficiency?
Well, Sam, I would say our yield's right on track with what we expect. It's really not so much the yield, it's more just about the timing. We've been in a market with a huge increase in ULSD price, a huge increase in the RIN year to date, and fat price has also been up, but you've had a bigger escalation in the RIN than you've had in the fat price. We've also been helped by the discount, our feedstocks, by running the 100% waste feedstocks. We're certainly buying at a price significantly lower than soybean oil. What I'm saying on the timing is just in a rising market like that, you're going to immediately see the ULSD price in your revenue. You're going to immediately see the RIN price. There's just a lag in the feedstock price and hitting cost of goods sold.
You're going to see a little better margin environment in a rising prices.
Hey, Sam. This is Lane. I'll add to it a little bit. We have been working with catalyst suppliers in terms of improving the yield of the current units and essentially trying to maximize renewable diesel versus LPG or some naphtha versus some of the off gases. We have seen our yields improve over the life of our overall operating experience from 2013 forward.
Okay. Understood. Thank you. Joe, in your prepared remarks, you had a comment about light heavy differentials potentially bottoming and starting to expand here as OPEC volumes come back. I'm still looking at the sulfur penalty. It's still very wide. Is there a signal around high sulfur fuel oil discounts and what that means for when actual supply of sour expands? Is the expansion of that advantage going to be faster than normal? Are you still thinking about it as kind of the normal relationship between kind of supply versus differentials?
No, I think some of the movement you've seen in high sulfur fuel, really two primary drivers on high sulfur fuel discounts. One, just the prospect of getting more OPEC barrels onto the market caused high sulfur fuel to weaken some. Some changes in the tax policies in China caused them to kick out some high sulfur fuel blend stocks, which caused high sulfur fuel to move weaker. Today, it's one of the more economic feedstocks we're running in our system. High sulfur fuel and high sulfur fuel blend stocks is one of the highest margin feeds we have in our system today. We expect that to continue.
Okay. Thanks, everybody. Take care.
Thank you. Our next question is coming from Neil Mehta of Goldman Sachs. Please go ahead.
Yeah. Good morning, everyone. The first question here is probably for Martin on the Ethanol side. You had strong results at that business segment. Can you just talk about what you think the sustainability of this ethanol recovery is and the moving pieces from feedstock to product prices?
Sure, Neil. Yeah, second quarter was obviously really good. If you look at the weekly inventory data in the second quarter, what was happening through most of the quarter is the inventories just kept drawing. Typically when inventories draw, you're going to get a better margin, and it's pretty good correlation there in the U.S. ethanol industry. The weekly data now in June, starting in end of May and through June, we've seen that turn the other way. Margins now are lower than they were in the second quarter. How long is this going to last? I'm not sure. We're starting to see some run cuts in the industry now. We've signaled some lower guidance for third quarter on runs versus what we did in second quarter. We'll see where that turns.
Really what we're looking at long-term, though, in ethanol is carbon sequestration, and we feel like that is going to differentiate us from the industry, between the 45Q tax credit that's worth about $0.15 a gal, getting into LCFS markets. That's more like $0.50 a gal gross. We're well-positioned there with what we're doing with Navigator and BlackRock, and then we're also looking at some standalone projects at our eastern ethanol plants for carbon sequestration. That's really our end game, is to lower the carbon intensity of our product and stay competitive there and differentiate ourselves.
Yeah. No, that's great. As a follow-up, it's just a big picture question, and I don't know if it's for Joe or Lane, but as I think about the demand side of the equation for both gasoline and diesel has come back really nicely. Obviously, we're still waiting here on global jet. Margins until recently didn't perform, and it just strikes us that the refining system in the U.S. was running too hard ahead of product. Do you believe that discipline in the U.S. refining system has broken down, or do you see that as still a structural tailwind for the space, that independent refiners will generally run at relatively low levels of utilization relative to demand, enabling favorable inventories? It's a big picture question, but one of the structural benefits, certainly of the refiners over the last couple of years, has been the discipline around runs.
Yeah. Neil, this is Lane. What I'd say is independent refiners will be much more disciplined than the industry was a decade ago, and it's just because at the end of the day, we have to manage our assets to cash flow and to make money. I think what you've seen, there was a clear signal in April and May to raise utilization. The markets were signaling that. What really happened, and Gary talked about it earlier, is it was just a bug light, right? The U.S. had recovered. Our mobility had gone way up, and it attracted imports from areas that were still essentially in lockdown. You had surplus capacity in Europe and some of these other places that attracted imports. I wouldn't say that the United States refining industry had gotten a lack of discipline. It was operating per the signals.
It was really the issue that there's capacity out there that essentially could get pointed at the U.S. As an earlier caller mentioned, the European fundamentals look better. You know, with today, what you're seeing is even though margins are up, we're not really arbs close to the United States coming out of Europe.
Thanks, Lane.
Thank you. Our next question is coming from Paul Cheng of Scotia Howard Weil. Please go ahead.
Hey, guys. Good morning.
Morning, Paul.
A couple of quick questions. Maybe this is for Gary. Gary, Mexico. The recent action by AMLO, does it cause any concern from you guys standpoint and whether it will slow down your investment in the near term to take a wait and see attitude, or that you think it just continue to be business as usual and you will push forward? With the maybe elimination or cancel large number of the import and export license, have you seen the market dynamic change there? That's the first question. The second question is for Lane. Just curious, you guys and the industry have done a remarkable job in changing to use the flexibility of the refining system to run different type of crude over the last several years, even for Gulf Coast heavy oil refiners, shift substantially more to the light.
And during the pandemic, substantially reduce jet fuel and even distillate and trying to get into gasoline. A lot of times that deviate from the design standard model. Along that way, while it is doable, have you seen any inefficiency or any cost create as such that the margin capture become maybe, perhaps a bit worse off? Thank you.
Okay. Paul, I'll start, and if Rich Walsh wants to add anything to it, I'll let him end on Mexico. Really our strategy is unchanged. The one thing I would say is we're not really investing in Mexico. We partnered with IEnova and others that are really making those investments, and then we sign long-term agreements to utilize the assets that they're investing in. But overall, I think, the strategy that we're using in Mexico is what they had intended when they started energy reform. They wanted to see investment in infrastructure in their country.
And a lot of others are really not doing that. They're kind of taking advantage of the legislation. We are investing in the country, and I think what we are doing in Mexico is exactly what was intended with the change in the regulation. Our strategy is still very much intact. Veracruz is fully operational now. We have our terminal in Mexico City, was commissioned during the second quarter. We will commission our terminal in Puebla in the third quarter. We've also started to bring jet fuel into Veracruz, and we'll start jet fuel sales in the third quarter as well. Things are going very well for us in Mexico. Rich, I don't know if you want to add anything.
I think that sums it up.
All right. If I pause to answer your second question. The industry did, I think, at least particularly we, I will say Valero, learned a lot going into the pandemic in terms of how to operate our refineries maybe differently, and actually demonstrated more flexibility, as you would expect us, to figure out how to operate. I think in terms of margin capture, what you'll see coming out of it is going into it, we had contango, right? There was structural contango in the crude markets, and as we're coming out of it, we've gone flat to slight backwardation. I think what you'll see kind of moving ahead, you have a combination of slight backwardation and obviously high flat price will cause some of the byproducts to maybe have some margin capture. Will it affect margin capture?
It doesn't really affect so much our ability to generate EBITDA as much as the way you think of it in terms of margin capture. In terms of anything that's happened post-pandemic, if anything, we just learned a lot more about how to manage our business even more carefully than we had before.
All right. Thank you.
Thank you. Our next question is coming from Manav Gupta of Credit Suisse. Please go ahead.
Hey, guys. Just first want to congratulate Mr. John Locke and Homer for their promotions and wish them all the luck for all the new responsibilities they're taking within Valero. Also wanted to congratulate you, Joe. We know the capital discipline and shareholder returns are two strong pillars on which you have to build this new Valero. It was personally very important for you to achieve full dividend coverage. Congrats on getting there despite a tough macro.
Yeah. No, thanks, Manav. And you know, John and Homer are both going to need a lot of luck.
My quick question here is, Lane or Joe, is we've seen North Atlantic here actually sometimes outperform your MidCon, do very strong. This quarter came in a little weaker. I'm hoping it was just a turnaround, and it's nothing to do with that one of the refineries is located in Europe and Canada. Just if you could give us some color on why North Atlantic was slightly weaker quarter-over-quarter.
Yeah. You actually hit the main issue. Both refineries were actually in turnaround in the second quarter. Their results were affected by that.
Okay. Thank you for taking my question.
Okay.
Thank you. Our next question is coming from Ryan Todd of Piper Sandler. Please go ahead.
Yeah, thanks. Maybe, one on, you announced that you moved up the timing of the Diamond Green Diesel 3 startup from the second half to the first half of 2023. What's allowed you to accelerate that? Then maybe can you talk about the general environment out there? I think most people probably would have taken the over for most of the capacity expansion start dates out there. I guess within that overall environment, what are you seeing that's allowing you to kind of execute better than expected on your projects?
Sure. This is Martin. I think one thing you have to remember now is DGD 3 is pretty much a carbon copy of DGD 2. That helped us. All the major equipment, we changed a little bit, but just tweaks. We had a lot of the engineering done sooner than you typically would have. Now, obviously, we knew that when we funded it, but just getting out and the market while steel prices and everything were up, we kind of beat all that to the market. We had placed orders before that happened. The delivery is good. The shop space is there. The labor situation's really good on the Gulf Coast where we're building. All those things and then just having experience. We moved over experienced contractors from DGD 2 that had just built one of these units.
All the work, the structural work, the concrete work, structural steel's already going up. We just got a really quick start out of the gates, and we expect to be able to maintain that. I'd say in a nutshell, that's it. An experienced construction team and getting out in front of these price increases and shop space has been really good for us.
Yeah, this is Lane. I want to emphasize what Martin just said. Part of what we're able to do here is it's not just really in this space, but we have a really good project execution group. We're in the process of building Diamond Green 2. It's actually accelerated and brought in its schedule. We just took all that and transferred it to Diamond Green 3. It just sort of speaks to our capability to not only operate well, but we can execute projects very well and not just in our refining space, but also in the renewable diesel space.
Great. Thanks. Congratulations. It's pretty impressive, though. Maybe a separate question on RINs and the RVO. There's been obviously a lot of noise lately, a lot of volatility in those markets.
Following the Supreme Court's ruling on SREs and with the upcoming RVO, with yourselves involved now in a pretty material way on both sides of the issue, on the gasoline side and on the biofuels side, any thoughts as we head into how you think the EPA is going to try to balance things? Or how you look at the market playing out with RVOs over the next couple of years?
This is Rich Walsh. I'll take a crack at that. There is a lot of noise on this, but when you really sort it all out, it comes down to EPA's going to have to issue these RVOs. They clearly are kicking them out to get past a lot of the infrastructure discussion and not to have this issue rear up in the middle of their efforts to try to push forward their infrastructure bill. We would expect that once you clear this, EPA's going to have to issue an RVO. We're almost all the way through 2021. By the time they could get a rule proposed and out, the year's almost certainly going to be past it. You're looking at maybe a 2021, 2022 combined rule, or at least them coming out at the same time.
And I think that'll, you know, and the other reality is they recognize that they need to set an RVO that's achievable and obtainable. We expect them to do that. On the SREs, the Supreme Court ruling really focused on only one issue was appealed up. That was on these continuity of the SRE ruling. The other aspects of the Tenth Circuit ruling that kicked those SREs back to EPA are still there, and EPA's got them back under, and they haven't issued an SRE since 2018. I think the prospect for SREs probably doesn't really change with the Supreme Court ruling. I mean, EPA's still got a whole host of other issues that they have to sort through that came out of the Tenth Circuit ruling that still stands. How do you guess what's going to happen on this?
The reality is they've just got to set an attainable and achievable mandate, and that's what they'll have to do.
All right. I appreciate the comments there. Thank you.
Thank you. Our next question is coming from Matthew Blair of Tudor, Pickering, Holt. Please go ahead.
Hey, good morning. I wanted to follow up on Martin's response on the LCFS question. Martin, I think you said that you expect CARB to move the goalpost to keep credit prices around $200 a ton. Just two follow-ups on that. One, mechanically, do you know how that would work? Does CARB have unilateral authority to do something like that, or do they need legislative approval? Is there a public comment period? And then two, what would you expect the refiner response to be if that happened? Just thinking about Valero, you have twp refineries in the state that are incurring LCFS costs. There's some other refiners in the state that currently don't have RD production. Is that something that refiners would fight? Could they fight it? Any more color there?
Well, what's different with the CARB regulations, with the LCFS, to answer your last question first, that obligation goes down to the rack so that the price is passed on for the refiner in California, which is a contrast to the way the RFS works. I wouldn't expect to see a fight from the refiners on that. The other question's more interesting. You know CARB has... There's been several statements out there about moving the goalpost. Now, t o answer your specific question, I'm not sure I can, what is required there. We're going to have to do a little looking into that. My understanding is they have the ability to do that, but we'll have to check on that. Yeah, I mean, that's, you know-
Great. Thank you. I'll leave it there.
Thank you. Our next question is coming from Jason Gabelman of Cowen. Please go ahead.
Hey, morning. I wanted to ask on 2Q two aspects that could have been transitory. First, on biofuel blending, and there was some thought that maybe blending biofuels instead of buying RINs minimizes the cost of RINs you incur, but it's unclear if the actual sales and costs flow that way or not. Can you just elaborate on if you're still seeing the same benefit from blending, as you historically have, in that it avoids having to go out and buy out RINs, or are you incurring some cost that is similar to having to go out and buy RINs? Then the second question, also on transitory items, on the co-product impacts on 2Q. Are those headwinds dissipating and turning into tailwinds as oil prices are declining? Are different products moving in different ways? Thanks.
I think on your first question, whether you're out buying the RIN or doing the blending, you're kind of achieving the same thing. The market price of the RIN is what it is. Either way, I'd say you get to the same result.
Yeah. On the second question, there are byproducts that we make in the refineries that don't move lockstep with crude price. Things like asphalt, petcoke, sulfur, LPGs. In the long haul, they do. It takes it longer. In other words, once crude moves up or moves down, those have a tendency to sort of take longer to get to their equilibrium state with crude. You'd expect it for whatever reason, if crude prices were down, those would improve. We're not speculating that crude prices will be down for the entire quarter. That is how it works.
Sorry, can I just follow up on that first answer quickly? Is that to say there's no real benefit from going out and blending biofuels versus buying RINs? I was under the assumption that if you're blending biofuels, you're sidestepping buying RINs, and there's kind of an embedded benefit in doing that.
Well, I would say there's a benefit, right? Obviously, everybody just can't buy RINs. You're going to have to move the biofuels, too. Certainly, we're looking at both sides of that equation. If the market's functioning properly and there's people that have to meet obligations, so you're going to have some blending. In a properly functioning market, I'm just saying you're going to get to the same place, but you're going to do both.
All right. I'll leave it there. Thanks.
Thanks. At this time, I'd like to turn the floor back over to Mr. Bhullar for closing comments.
Thanks, Donna. We appreciate everyone joining us today. Please stay safe and healthy, and feel free to contact the IR team if you have any additional questions. Have a great day, everyone. Thank you.
Ladies and gentlemen, thank you for your participation. This concludes today's event. You may disconnect your lines at this time, and have a wonderful day.