Valero Energy Corp
NYSE:VLO
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Valero Energy Corp
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Greetings, and welcome to the Valero's Fourth Quarter 2021 Earnings Conference Call. At this time, all participants are in a listen-only mode. A question-and-answer session will follow the formal presentation. [Operator Instructions]. 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. Please go ahead.
Good morning, everyone, and welcome to Valero Energy Corporation's fourth 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 and reconciliations and disclosures for adjusted metrics mentioned on this call. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call.
I would now like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our filings with the SEC.
Now, I'll turn the call over to Joe for opening remarks.
Thanks, Homer, and good morning, everyone. We saw continued improvement in our business during the fourth quarter with refining margins supported by strong product demand.
In our system, we ended the year with gasoline demand at pre-pandemic levels and demand for diesel actually higher than pre-pandemic levels. We also saw a significant jet fuel recovery as domestic and international travel opened up, increasing from approximately 60% of pre-pandemic levels at the beginning of the year to approximately 80% at the end of the year. Product inventories were low as a result of the refining capacity rationalization that's taken place in the last 2 years and weather-related impacts from Winter Storm Uri and Hurricane Ida.
On the crude oil side, OPEC+ increased production throughout the year with improving demand supplying the market primarily with sour crude oils, resulting in wider sour crude oil discounts to Brent crude oil.
As a result of all these dynamics, we saw a steady recovery in margins throughout the year, particularly for our complex refining system.
In regards to our ethanol segment, ethanol prices were near record highs in the quarter, supported by strong demand and low inventories. Strong margins, coupled with solid operational performance across all of our segments, generated record quarterly operating income for our ethanol segment and record overall fourth quarter earnings for Valero.
I am proud to say that 2021 was our best year ever for employee and process safety. In fact, we've set records for process safety for 3 consecutive years. These milestones are a testament to our long-standing commitment to safe, reliable and environmentally responsible operations. And despite the pandemic and weather-related challenges in 2021, our growth projects remained on track. We started up the Pembroke cogeneration unit in the third quarter of '21, which provides an efficient and reliable source of electricity and steam, and enhances the refinery's competitiveness.
In addition, the Diamond Green Diesel expansion project, DGD 2, commenced operations in the fourth quarter on budget and ahead of schedule. The expansion has since demonstrated production capacity of 410 million gallons per year renewable diesel as a result of process optimization, above the initial nameplate design capacity of 400 million gallons per year. This expansion brings DGD's total annual renewable diesel capacity to 700 million gallons.
Looking ahead, the DGD 3 project at our Port Arthur refinery is progressing ahead of schedule and is now expected to be operational in the first quarter of 2023. With the completion of this, 470 million-gallon per year plant, DGD's total annual capacity is expected to be 1.2 billion gallons of renewable diesel and 50 million gallons of renewable naphtha.
BlackRock and Navigator’s large-scale carbon sequestration project is also progressing on schedule and is still expected to begin start-up activities in late 2024. Valero is expected to be the anchor shipper with 8 ethanol plants connected to the system, which should provide a higher ethanol product margin.
The Port Arthur Coker project, which is expected to increase the refinery's utilization rate and improved turnaround efficiency, is expected to be completed in the first half of 2023.
On the financial side, the guiding framework underpinning our capital allocation strategy remains unchanged. We remain disciplined in our allocation of capital, which prioritizes a strong balance sheet and an investment-grade credit rating.
In 2021, we took measures to reduce Valero's long-term debt by approximately $1.3 billion. We ended the year well capitalized with $4.1 billion of cash and $5.2 billion of available liquidity, excluding cash. And our net debt to capitalization was 33%.
We continue to honor our commitment to stockholders, defending the dividend across margin cycles and delivering a payout ratio of 50% in 2021. And as recently announced, the Board of Directors has approved a quarterly dividend of $0.98 per share for the first quarter of 2022.
Looking ahead, we remain optimistic on refining margins, with low global light product inventories, strong product demand, global supply tightness due to significant refining capacity rationalization and wider sour crude oil differentials.
We also remain optimistic on our low-carbon businesses, which we continue to expand with the growing global demand for lower carbon intensity products. We've been leaders in the growth of these businesses and maintain a competitive advantage with our operational and technical expertise.
In closing, our team's simple strategy of pursuing excellence in operations, deploying capital with an uncompromising focus on returns and honoring our commitment to stockholders, has driven our success and positions us well.
So with that, Homer, I'll hand the call back to you.
Thanks, Joe. For the fourth quarter of 2021, net income attributable to Valero stockholders was $1 billion or $2.46 per share compared to a net loss of $359 million or $0.88 per share for the fourth quarter of 2020. Fourth quarter 2021 adjusted net income attributable to Valero stockholders was also $1 billion or $2.47 per share compared to an adjusted net loss of $429 million or $1.06 per share for the fourth quarter of 2020.
For 2021, net income attributable to Valero stockholders was $930 million or $2.27 per share compared to a net loss of $1.4 billion or $3.50 per share in 2020. 2021 adjusted net income attributable to Valero stockholders was $1.2 billion or $2.81 per share compared to an adjusted net loss of $1.3 billion or $3.12 per share in 2020.
For reconciliations to adjusted amounts, please refer to the financial tables that accompany the earnings release.
The refining segment reported $1.3 billion of operating income for the fourth quarter of 2021 compared to a $377 million operating loss for the fourth quarter of 2020. Fourth quarter 2021 adjusted operating income for the refining segment was $1.1 billion compared to an adjusted operating loss of $476 million for the fourth quarter of 2020.
Refining throughput volumes in the fourth quarter of 2021 averaged 3 million barrels per day, which was 483,000 barrels per day higher than the fourth quarter of 2020. Throughput capacity utilization was 96% in the fourth quarter of 2021 compared to 81% in the fourth quarter of 2020. Refining cash operating expenses of $4.86 per barrel in the fourth quarter of 2021 were $0.46 per barrel higher than the fourth quarter of 2020, primarily due to higher natural gas prices.
The renewable diesel segment operating income was $150 million for the fourth quarter of 2021 compared to $127 million for the fourth quarter of 2020. Adjusted renewable diesel operating income was $152 million for the fourth quarter of 2021. Renewable diesel sales volumes averaged 1.6 million gallons per day in the fourth quarter of 2021, which was 974,000 gallons per day higher than the fourth quarter of 2020. The higher operating income and sales volumes were primarily attributed to the start-up of Diamond Green Diesel expansion project, DGD 2, in the fourth quarter.
The ethanol segment reported record operating income of $474 million for the fourth quarter of 2021 compared to $15 million for the fourth quarter of 2020. Adjusted operating income for the fourth quarter of 2021 was $475 million compared to $17 million for the fourth quarter of 2020. Ethanol production volumes averaged 4.4 million gallons per day in the fourth quarter of 2021, which was 278,000 gallons per day higher than the fourth quarter of 2020. And as Joe mentioned earlier, the higher operating income was primarily attributed to higher ethanol prices, which were supported by strong demand and low inventories.
For the fourth quarter of 2021, G&A expenses were $286 million and net interest expense was $152 million. G&A expenses of $865 million in 2021 were largely in line with our guidance.
Depreciation and amortization expense was $598 million and income tax expense was $169 million for the fourth quarter of 2021. The annual effective tax rate was 17% for 2021, 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 $2.5 billion in the fourth quarter of 2021 and $5.9 billion for the full year. Excluding the favorable impact from the change in working capital of $595 million in the fourth quarter and $2.2 billion in 2021, and the other joint venture members, 50% share of Diamond Green Diesel's net cash provided by operating activities, excluding changes in DGD's working capital, adjusted net cash provided by operating activities was $1.8 billion for the fourth quarter and $3.3 billion for the full year.
With regard to investing activities, we made $752 million of total capital investments in the fourth quarter of 2021, of which $353 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance and $399 million was for growing the business. Excluding capital investments attributable to the other joint venture members, 50% share of Diamond Green Diesel and those related to other variable interest entities, capital investments attributable to Valero were $545 million in the fourth quarter of 2021 and $1.8 billion for the year.
Moving to financing activities. We returned $401 million to our stockholders in the fourth quarter of 2021 through our dividend and $1.6 billion through dividends in the year, resulting in a 2021 payout ratio of 50% of adjusted net cash provided by operating activities for the year. And our Board of Directors recently approved a regular quarterly dividend of $0.98 per share, demonstrating our sound financial position and commitment to return cash to our investors.
With respect to our balance sheet at year-end, total debt and finance lease obligations were $13.9 billion and cash and cash equivalents were $4.1 billion. The debt-to-capitalization ratio, net of cash and cash equivalents was 33%.
In the fourth quarter, we completed a series of debt reduction and refinancing transactions that together reduced Valero's long-term debt by $693 million. These debt reduction and refinancing transactions, combined with the redemption of $575 million floating rate senior notes due 2023 in the third quarter, collectively reduced Valero's long-term debt by $1.3 billion.
At the end of the year, we had $5.2 billion of available liquidity, excluding cash.
Turning to guidance. We expect capital investments attributable to Valero for 2022 to be approximately $2 billion, which includes expenditures for turnarounds, catalysts and joint venture investments. About 60% of our capital investments is allocated to sustaining the business and 40% to growth. Approximately 50% of our growth capital in 2022 is allocated to expanding our low-carbon businesses. For modeling our first quarter operations, we expect refining throughput volumes to fall within the following ranges: Gulf Coast at 1.66 million to 1.71 million barrels per day; Mid-Continent at 395,000 to 415,000 barrels per day; West Coast at 185,000 to 205,000 barrels per day; and North Atlantic at 430,000 to 450,000 barrels per day. We expect refining cash operating expenses in the first quarter to be approximately $4.80 per barrel.
With respect to the renewable diesel segment, we expect sales volumes to be approximately 700 million gallons in 2022. Operating expenses in 2022 should be $0.45 per gallon, which includes $0.15 per gallon for non-cash costs such as depreciation and amortization.
Our ethanol segment is expected to produce 4.2 million gallons per day in the first quarter. Operating expenses should average $0.44 per gallon, which includes $0.05 per gallon for non-cash costs such as depreciation and amortization.
For the first quarter, net interest expense should be about $150 million and total depreciation and amortization expense should be approximately $600 million.
For 2022, we expect G&A expenses, excluding corporate depreciation to be approximately $870 million.
That concludes our opening remarks. Before we open the call to questions, we again, respectfully request that callers adhere to our protocol of limiting each turn in the Q&A to 2 questions. If you have more than 2 questions, please rejoin the queue as time permits. Please respect this request to ensure other callers have time to ask their questions.
[Operator Instructions]. Our first question today is coming from Theresa Chen of Barclays.
Joe, I'd like to revisit your comments earlier about the refining margin outlook through 2022. I mean clearly, we seem to have a pretty positive setup with lean global inventories and significant amount of refining rationalization that's happened since and even slightly before the pandemic began while demand continues to recover and remain resilient. So looking through the rest of this year, can you just give us a sense of puts and takes on the variables that could detract from this thesis, either risk to the downside or upside from here?
Sure, Theresa. Thanks a lot. Why don't we let Gary take a look at -- take a crack at this?
Sure, Theresa. If you look -- I mean, I'll just kind of go through some of the things we're seeing in our system. We saw good recovery last year, both gasoline and diesel and even good recovery in jet fuel demand. And we expect that rebound to continue through 2022. We started the year, gasoline demand is off a little bit from what we would expect. Some of that is just seasonality. But even if you go back to 2019, we were in 2019 at this time of the year, we're off about 7% with the spike in COVID cases and also some weather impacting gasoline demand as well. But I would tell you already, our 7-day average is only off about 3% of where it was in 2019. So it looks like this latest surge in COVID cases we’re already coming out of it.
And so with where gasoline inventories are, very bullish gasoline moving forward. As you already pointed out, we expect to see gasoline demand back to 2019 levels, which was close to peak gasoline demand, and we'll be trying to feed that demand with significantly less refining capacity. So we expect the gasoline markets to be very tight. When you move to diesel, of course, diesel inventories are not only low in the United States, but they're low globally. Diesel demand actually in our system has been about 7% of where it was in 2019. So some of those factors, in particular, weather that are negatively impacting gasoline are actually -- are having a positive impact on diesel demand. So we see very strong diesel demand. And we actually don't see a clear path in the near future to be able to restock those investors in turnaround activity that's occurring in the industry, along with the rationalization that's occurred.
So for us, both gasoline and diesel look very constructive moving throughout the year. Jet demand will be the unknown. Our expectation is that as we get through this wave of COVID, much like we saw last year, domestic air travel will pick back up fairly rapidly but it will be a longer period of time before international travel picks back up.
So although we expect to be closed back to 2019 levels by the end of the year, probably not fully recovered. I think to me, when you talk about the wild card, really the wildcard for this year is what happens in the crude market. Obviously, a lot of tightness in the crude markets today, certainly having an impact on differentials and so for us, it's kind of when do we see OPEC begin to ramp up production. As global oil demand picks up, we would expect OPEC to increase production. A lot of that will be medium and heavy sour barrels, which would be constructive to wider differentials moving throughout the year as well.
That's great color. So I got to ask the capital allocation question. You have been so consistent on your messaging as well as execution around this. And with the progress that you've made on reducing debt, generating free cash flow for the past couple of quarters and generally positive momentum on the near-term refining outlook. Are we at an inflection point where we may soon see a step-up in cash return to shareholders?
Jason?
Yes, this is Jason. I'll take that. And you're right, we've made good progress on our goals. We have said when we started coming out of this situation, we rebuild our cash and target keeping more on hand around $3 billion. We've done that. We had $4.1 billion at the end of the year. We also said we're really going to start working on delevering. And in the third and fourth quarters of last year, we did delevering transactions paid off about $1.3 billion net, brought our net debt to cap down to 33% at the end of the year, and our goal is to ultimately get back to our 20% to 30% long-term target we've had. And the pace is going to depend on margins and cash generation.
But getting on to buybacks and the return of cash to shareholders. As you said, things are looking better now. For 2021, the payout was 50% with just the dividend and some minimal buybacks related to the employee plans. But with the margin increase in the fourth quarter and they're continuing to be strong during the first quarter so far, if this pattern of recovery does continue, we do anticipate we'll be doing buybacks this year to meet our target. And we feel we can both continue to our pattern, our goal of having aggressive debt paydown this year and also meet our shareholder return commitment via projects -- via buybacks, I'm sorry. We definitely don't think they're mutually exclusive and it's all driven by our framework and targets we've had in place for several years.
Our next question is coming from Manav Gupta of Credit Suisse.
I just -- I had first question was on DGD. What we are seeing out there is number of projects getting delayed, long lead equipment not getting through. Everybody is kind of lagging. You are an exception, your project keeps moving forward. And I know you always tell me, you have the best people. But besides best people, what else are you doing right, which is allowing you to move the time line forward versus everybody else going backwards?
Wow! I don't -- should we even say anything?
I'm still going to say we have the best people. Hey, Manav, this is Lane. We also completed Diamond Green 2, right? So we have a really good understanding of what the project execution looks like. We have the same business partners that are largely executing Diamond Green 2. And we've been able to really improve the schedule, and it's really just -- we've been -- we’ve built 2 of these, we're in our third, and it's just a really good team all the way around, not just our people, we have good business partners as well. And we also are permitting, we permit these even better. So just....
Yes. And there's -- Lane, there's been a lot of lessons learned as we went through 1. And so I mean…
That’s what I mean. We've built 1, we’ve built -- we just finished 2 and we've learned all through all those things. We are definitely -- we have the advantage of being an early mover in this space.
Perfect, guys. My second follow-up very quickly here is it looks like your partner is moving ahead with kind of an acquisition, which would give you guys more used cooking oil, more animal fats. At this stage, I think there was a point to get in more animal fats from international to feed DGD 3. How is the feedstock situation looking for DGD 3? Are you very close to what you would need when DGD 3 is up and running in terms of feedstock now?
Yes, Manav, this is Martin. Obviously, our plan is to continue to feed DGD 1, 2 and 3 with waste feedstock. We feel good about that. The market -- feedstock market has tightened up relative to soybean oil. And we knew that was coming with the start-up of DGD 2. We changed trade flows. We've moved everything around, and that's had an impact on the market. And frankly, when we contemplated DGD 2 and 3, we expect that feedstock to appreciate relative to soybean oil and we expected carbon pricing to appreciate.
So we're kind of where we expected to be here. And yes, the feedstock situation, it's a moving target, but it's all tied to global GDP growth. And just to sum it up, yes, we expect to be able to feed it.
Our next question is coming from Phil Gresh of JPMorgan.
The Gulf Coast refining margins in the fourth quarter were the best since 2015, if I have that right. And they're even better than 4Q '19 when we were talking about IMO 2020 and feedstock advantages and things like that. So I was just curious if there's anything more to elaborate on about the strength of the Gulf Coast margins that we saw in the quarter and how you think about the sustainability of that?
Yes. So I think a lot of -- typically in the Gulf Coast, when we see stronger capture rates, it's tied to feedstock optimization. And so certainly, we've been doing a lot around some of those fuel oil blend stocks and running more of those in our system, which has helped supported higher capture rates.
Got it. Okay. And then second question, just a follow-up on some of the commentary there on renewable diesel. The gross margins there, down sequentially. It sounds like you expected some of that, but the capture rate, the indicator there was, I think, a bit lower than maybe some had expected. Were there any transitory factors there, in your opinion, in the quarter as you started up Phase 2 and whether it's with feedstock or other factors? Or is this how you think about kind of a run rate moving forward?
Sure, Phil. This is Martin. So margin capture in 2021 was all about the feedstock price. In first half of '21, feedstock prices were low relative to soybean oil, which resulted in some really high margin capture. In the fourth quarter, the prices were high relative to soybean oil and that gave us a lower margin capture at 75%.
With the start-up of DGD 2, we're going to have tighter prices for a while. We expect feedstock to be around soybean oil going forward for the immediate future. And then we'll see how that plays out in the next few months after that. But we expect it to be right around soybean oil, which would incur closer to this 100% type margin capture. And that's what we experienced throughout 2019. If you go back and look at those numbers, we averaged right around 100% margin capture. So that's kind of how we expect things to shake out in the next few months.
Our next question is coming from Roger Read of Wells Fargo.
I want to come back, if possible, to the crude tightness comments, just what you're seeing in terms of differentials, what you'd expect? And then are we highly dependent here on OPEC putting more oil in the market? Or is there some other factor at work? And one of the reasons I ask is some of the closures that we saw on the refining side tended to be a light suite unit. So if physical demand is down on that side, is that also accounting for some of the tightness of the differentials?
Yes, Roger, it's Gary. I think there's a number of factors that contributed to the tightness, not simply OPEC. We saw the winter weather have an impact on heavy Canadian production from Western Canada. We had disruptions from supply in Ecuador. There's been -- the pipeline issue between -- the pipeline between Iraq and Turkey that took barrels off the market. So a number of factors.
We think going forward, again, not only get OPEC production ramping up. We expect to not only see the Western Canadian production come back, we actually think it will grow with some of the logistics projects coming back on. And so most of that production that was off the market is coming back.
In addition to that production coming on the market, the OPEC production growing will take some of the pressure off the crude markets and certainly pressure off the crude differentials.
And then my unrelated follow-up question is coming to you, Jason. Like the insight on the possibility of getting back to more normal cash returns model in '22. I was curious, though, given the significant improvement in working capital in '21, are we at risk of seeing some of that reverse in '22? Or when you think about the outlook, do you assume a neutral working capital event and maybe we should assume something going the other way?
Yes. Well, our movements in working capital generally follow flat price. So when we're forecasting, we just assume neutral cash on working capital as our basis.
So just a quick reminder. If prices go up, positive prices go down, it's going to eat working capital?
Right. That's right.
Our next question is coming from Prashant Rao of Citigroup.
I wanted to circle back on the capital allocation piece a little bit. You've done a great job reducing debt. It looks like you'll be able to take another chunk out this year, got high balance sheet cash. And it sounds like you're very positive on buybacks. I just sort of wanted to ask about the dividend. I know if it might be a bit premature at this point, but given that we're looking at what could be an above mid-cycle here in earnings. You've gotten debt controlled and the yield is starting to come in. Currently, just I annualized a little bit under 5% and tighter than that if the share price continues to work, is taking a hard look at the dividend, something that potentially increase something that you might think of this year? Or is it too soon to start talking about that?
Yes. This is Jason. It's probably a little soon given what we just came through. But we always look at it. Our commitment is to have a sustainable dividend with a yield at the high end of our peer group, and that's where it is now, where the peers are and the market is, we think it's in a good place.
Okay. Perfect. And then just...
Prashant, at this time last year, there was a big question on sustainability of the dividend, right? A lot can change in a short period. Now you never questioned it. You always had faith, stuff like that. But anyways, it’s interesting how things come around.
It's true. It's like a different world altogether, right, Joe?
Yes. There it is.
Just another quick question. Ethanol, obviously, historically, high performance here. This is the best quarter we've seen since you've been reporting quarterly results at ethanol. Just wondering a little bit about strength carryover. I think when we discussed this a couple of months back, there were some cautious -- cautious read across as to what happens in 2022 given how volatile the ethanol market is and all the puts and takes. I was just wondering if big picture how to think about how -- where we -- level set where we are entering 2022 think about what the cadence might be there? Some of that strength carrying over, but also there's a lot going on in terms of policy, gasoline demand, a whole bunch of factors there. So just wonder if we could get some color and maybe a little bit of clarity as to how we should be thinking about that as we look into '22?
Prashant, this is Martin. Well, obviously, fourth quarter was a great quarter for ethanol. When you look at it, what really set that up is, we -- in the third quarter, the margin started off really weak. And we were also at the end of crop year corn. So that this wasn't corn available in the industry is pretty -- very low stocks. So there was a lot of run cuts, a lot of early maintenance taken and the plants really didn't rebound. And I'm talking across the industry, I'm not talking just Valero, and get rates back up until early October. And then rates exceeded. I mean in early October rates exceeded the 5-year averages. But what was interesting even with higher rates, inventory just never built. So when you have a low inventory situation that leads to high margins, and that's what we saw.
So now the last few weeks of the year and the first few weeks of 2022, we've had significant inventory build. So the margins have come off dramatically. But that being said, we're still probably where we typically are in the first quarter for ethanol margins. And I think what we always are looking at, at ethanol now, though, is the longer term and that's the carbon capture. That's going to provide a great opportunity for us, both from the 45Q and the LCFS. And also we're producing -- start to produce more and more gallons of cellulosic ethanol from corn fiber. So we're optimistic about both of those. We're also just confident that ethanol is going to remain a part of the domestic fuel mix. We expect higher octane blends in the future, namely 95 RON, which means more ethanol blending. And globally, the renewable fuel mandates are going to drive export growth.
So we feel really good about ethanol going forward, maybe not this quarter, next quarter. But longer term, we feel really good about ethanol.
Our next question is coming from Doug Leggate of Bank of America.
Joe, I'm sorry, I'm going to hit the capital allocation question 1 more time, maybe a slightly different angle. So the balance between dividends and buybacks is really what I'm kind of focused on here because, I mean, you could easily buy back 5-plus percent of your stock. That's a pretty healthy dividend growth for an ordinary business and I remind your business. So I'm just kind of curious how you think about the balance going forward as you reconsider the right level of debt perhaps and the right balance between that 40% to 50% cash allocation to cash returns between the dividend and the buyback. I know it's a broad question, but I'm just kind of curious how -- I guess what's behind us, Joe, is in years gone by, there's been criticism of buybacks at a high price level. I'm wondering if the buyback is more a tool to manage the dividend burden going forward?
Yes. No, Doug, it certainly would be and when you think about where the yield has been particularly last year, I mean, we've been flushed with cash last year, we had bought back a ton of shares, but we weren't.
And you're right, it is a double-edged sword, right? We end up with good cash flows and typically a high stock price all at the same time. So that's why it's hard to create a formulaic approach to how we look at doing this. And so I think Jason has laid it out, coming out of COVID, we had a very specific set of priorities that we wanted to put in place. And I think he covered those. What I'll do is, look, we got a good strong CFO. We'll see what he thinks here. You've got anything you'd like to share?
Yes, everything you said was accurate. And you have to -- we have to -- we have a balanced dividend because as we've proven through the last downturn, we're going to defend it in the downturn. So you have to be wary of making it too high. And the buybacks give you the flywheel.
Yes. So Doug, I wouldn't say -- I mean, we always look at the dividend, and we'd like to increase it. I think there's a time when it will be right to do that. And it's a burden that we've been able to carry. Certainly, it's easy in a good margin environment like we have today. But in the down margin environment, as Jason said, we’ve defended it. And it was a bit of a load. But we're committed to it, and we just don't want to get overextended.
And it's well positioned versus the peers. Our first step is to look versus our peers, we committed to be up near the top of the end and as long as we're the highest, that box is checked.
I want to be respectful to everyone else, and I'm going to take my second question on the same topic, if you don't mind, because I'm looking at, for example, what some of the Canadians have done, think about actual companies that have long-life sustainable assets. Obviously, your business is very similar to that in some respects in terms of the annuity nature. So I wonder then, with some folks did question your dividend last year, I know that’s on my hat, but why then wouldn't you use your balance sheet, take your balance sheet to a much stronger level, so that kind of concern can be taken out of the investment case. So in other words, why is 20% to 30% the right level? Why not go lower given the drop that we all saw in the past year? And I'll leave it there.
Doug, that's a fair question. And I can tell you, that's 1 of the things that Jason and Homer are looking at consistently. The capital markets were very accessible last year, even in the downturn. And rates were so attractive that we were able to really do a good job of financing the business through this. But again, you never really know. Jason?
Yes. That's right. One thing we do to address this is hold a higher cash balance. But we also want to have an efficient capital structure and debt is pretty cheap right now. The 1 to 0 debt would give you the maximum flexibility and kind of resilience, but then you have a cost of a higher cost.
But Doug, are you proposing that we would like lever up to buy back shares or something along those lines?
Well, it's really -- yes, it's really more that so you're opportunistically positioned to lean on the balance sheet when you need to without the market speculating about the dividend. It's really more because I think your business can support on annuity dividend discount model type of approach, but the balance sheet needs to be rightsized to achieve that. And again, it was just really try and take that volatility out of the go-forward investment case. But I've taken my close of time, Joe, so I appreciate the answers and….
Okay. We'll see you soon.
Our next question is coming from Paul Sankey of Sankey Research.
Can I ask you guys about Europe? Just from your perspective, as a major refiner there. What's going on as regards demand, the impact of natural gas prices, crude slates, the whole bit?
Yes. So this is Gary. I guess what we're seeing in terms of demand is they're kind of ahead of where we are in recovery from the latest spike in COVID cases. If you look at our 7 day in the UK, we're up about 10% of where we were month to date. So starting to see good recovery in mobility and gasoline demand in the system. Again, very similar situation on diesel. ARA stocks are very low. So diesel looks very constructive as well.
On the natural gas side, you see some switching of crude diets as a result of the high natural gas prices still $30 an MMBtu in Northwest Europe. So you see some people kicking out medium and heavy sour grades of crude running more light sweet. I think where we've seen it the most is optimization around hydro processing capacity. So people idling and cutting hydrocracking capacity as a result of very high natural gas prices, which again puts less diesel in the market and is 1 of the reasons why we're experiencing all the tightness around diesel that we are.
Excellent answer. Can I just follow up with California. We've seen margins come off quite a bit there. But more importantly, could you talk a bit about how renewable diesel will play through in that market where you're exposed to both sides. I just wonder what your perspective is because we could see a situation, obviously, where the market gets quite challenged, I think, by renewables.
Yes, Paul, this is Martin. Renewable diesel has held up really well from a demand side in California. It's kind of amazing to me going through COVID what we've seen out there. Obviously, deficits have decreased, and they've decreased because of less carbo or gasoline use and less diesel use, but renewable diesel and for the first half of the year, and that's the latest stats we have is around 23% of the diesel pool in California. So it's -- we're blending in an R23 state-wide, which is pretty amazing. And a lot of imports coming into California to renewable diesel. So it's kind of held up remarkably well. And you can say, well, maybe that's why the credit price is down. But I think really, the credit price has got a lot more to do with just less deficits than it has to do with additional credits from renewable diesel.
So we -- that's a great market for us. What really got hurt demand-wise was more in Europe on renewable diesel and probably more in Canada, too, with just the kind of waiting for the CFS. So we expect those 2 to rebound and with that more demand globally.
Understood. Could you just throw the answer forward a little bit? As we look over the next couple of years in terms of how the supply demand, the balance might play out? And I'll leave it there. Sorry, not to make you laugh today, Joe, but...
Paul, I'll tell you what. We'll have a chance for that here pretty soon, won't we?
I think if you play it forward, there's really nothing that stops renewable diesel from -- you can blend it really any rate with renewable diesel, right? There's 85% renewable diesel sold in California today. I think CARB's projections are to get somewhere around R40 by 2030. I think a lot of people think that it could be higher than that. So that's California, but you've also got other states considering LCFS. You've got the CFS in Canada that we're looking forward to by the end of this year. And the Canadian decelerate the size of California's market. So that's going to be a big market for us, and we expect that people will over generate credits early when they can, right? That's what happened in California. There was early credit generation, building up a credit bank, and we expect to see the same thing in Canada, which is good for renewable diesel demand.
Our next question is coming from Paul Cheng of Scotiabank.
Two questions, please. First is for Martin. I think within the renewable diesel, another product seems to be getting some excitement by some of your peers, SAF. Just want to see whether the company have any interest in where the economy and what leads to change in order for the economy to be compatible with renewable diesel from your standpoint for you to be interested. And if you -- at that point, what kind of investment you will need to make in order to make the switch? So that's the first question.
The second question is probably for Lane. North Atlantic, the fourth quarter margin capture was really good, it’s great. Just want to see if there's any one-off events or also that within the 2 facility in Europe and also that -- in capacity, I mean, which is a stronger unit in terms of the margin capture in the fourth quarter?
Okay. It's Martin. I'll get started there, Paul. I think we were all looking at the Build Back Better Bill and what was in that on a tax credit basis for SAF and what we saw that incentive level proposed in that bill was not sufficient to attract additional investment to make SAF versus the base case of producing renewable diesel with an existing unit. However, we're still progressing SAF production through our gated engineering process; and concurrently, we're developing customers. There are plenty of customers interested in SAF but a favorable tax credit, something else is going to be required or tax credit or something else to really get over the hump to where SAF is economic to produce relative to producing renewable diesel.
That being said, we're still confident that SAF production is a question of when and not if. We think the margins will eventually work. The SAF is the only way to reduce the carbon intensity of air travel.
How big is the -- sorry, Lane. Just wanted to follow up on what Martin said. How big is the gap in terms of the incentive for you to fund SAF to be attractive enough compared to the renewable diesel? And also technically that what kind of investment you need to make and how big is the investment for you that to make DGD that to be able to produce that, call it, 20% or 30% in SAF?
Yes. On the gap, I mean, we're somewhere probably around the $0.70 a gallon gap still, Paul, to make it economic. On the investment, we're still going through our gated process. So we don't have a number on that yet. We have preliminary numbers, but we don't have a number that we're ready to share yet.
Okay. Thank you. Lane?
All right. So yes, what's interesting about the 2 refineries we have in the Atlantic Basin is Quebec is seasonally stronger in the fourth and the first quarter, it's largely a distillate, very specialized distillate producing refinery configured, whereas Pembroke is really more of a gasoline producing configured refinery. So that's kind of how they work out. So really, in terms of the fourth quarter performance, it's really Quebec well on their margin capture. And obviously, you have the issues with around high natural gas prices over in the UK Obviously, that helped sort of hurt their margin capture in Pembroke.
And Lane is there any one-off item that you're benefiting in the quarter? Or that -- it's just that you guys have done a phenomenal job in the operation and be able to fully capture the benefit of that in the market?
I like the second answer, but it's a -- yes. Quebec ran -- they both ran really well in the quarter. So...
Our next question is coming from Sam Margolin of Wolfe Research.
Wanted to just circle back to the industry capacity questions. A few other analysts on the call have alluded to a lot of closures over the past 12 months, but there are some third parties and some management in the industry that are suggesting that the number of closures is even higher than any of us are aware of or any kind of report that we would see might confirm. And so I wonder what your thoughts on that are?
And then secondly, there's a 2-part question, but only one. Theoretically where cracks are today, you would think that capacity rationalization would stop here or slow down. But there's other factors that may be driving some closures. So if you think that this trend could continue based on noneconomic factors, would love your input on that, too?
Sam, it's Lane. So I think we are trying to study the data right now because what we see the similar issue in terms of what where utilization is and versus closures. And again, it's just sort of what we're sort of preliminary deciding or looking at as we think that there's probably some slowdowns that are occurring maybe because of maintenance deferrals or turnaround deferrals in the industry. We don't -- that's not something we know, but it's a theory as to what you're seeing. And certainly, where margins are now the call on capacity is pretty much max.
So other than the turnarounds and the outages, the refinery utilization ought to be in this 90% to 95% range. Once you get all the DOE data worked out to make sure all the refineries do you think shouldn't be in and everything. That's kind of where we see it as well.
Our next question is coming from Ryan Todd of Piper Sandler.
Maybe just 1 quick follow-up on your comments on California from earlier. I know you had talked about some of the longer-term lease issues of low carbon fuel standard credits. Do you have a view on for the next 12 months where you think the LCFS credit go from here? We've gone from 200 to 150-ish. Do you see further downside? Or do you think we stabilize here?
That's a good question. This is Martin. What's difficult about this is you're always driving with your rearview mirror, right? The last -- the data lags by 6 months and not complained about that. It makes sense. It's a lot of data. But -- so we're always kind of -- we've got -- at the end of this month, we'll get the third quarter data. I think what's interesting is when you look at it, the credit price obviously depends on credit generation versus deficit generation and COVID certainly reduced deficit generation and it has been since the second quarter of '20. So you have to think the credit prices have been reduced by COVID.
And then the other thing that's interesting to me is when you look at the credit generation in 2Q '21, I'd say that it certainly surprised me to the upside. But when you dig into that, there's really 2 line items in the credit generation that stand out. The first was that bio CNG, bio compressed natural gas was 13% of all the 2Q '21 credits, and that line item was up 190% versus 2019. And second, off-road electricity generated 9% of all credits. Now this is off-road, not on-road, and that was up 146% versus 2019. And more interestingly, on the off-road, 71% of those credits came from e-forklifts. so when you think about the bio CNG, the off-road, the e-forklifts, you just wonder if that pace of credit generation can continue on the infrastructure and just really the -- gets in the way, right? I don't know how many times you can replace your forklift to get an e-forklift, but it seems like that would run out at some point. So we'll see how that shakes out.
But if you think about those 2 line items, that's, what, 21%, 22% of the credits in California from 2 line items there, which really were very small in the past. So that's just kind of an interesting data. And then the other is biodiesel, renewable diesel and on-road electricity credit generation as a percent of total credits were all flat for 2Q '21 versus 2019 as a whole. That's just a little color. Hopefully, that helps.
That's great. And then maybe just one overall. I know you've talked a lot about what you've seen generally in terms of demand, particularly here in the U.S. Any comments in terms of what you're seeing on the product export side that may indicate what you're seeing on international product demand, particularly in your primary export markets?
Yes, this is Gary. So I would tell you, we're probably seeing -- we're not seeing the recovery in Latin America quite as fast as we've seen in North America or the UK. So demand is still down a little bit. We're seeing good export demand into the region. I would expect in the first quarter, our exports will be down a little bit, not really an indication of demand in Latin America, but more a function of maintenance activity occurring, especially in the U.S. Gulf Coast during the quarter and really good domestic demand. But the demand is there in Latin America in our typical export markets.
Our next question is coming from Jason Gabelman of Cowen.
I wanted to dovetail off a comment that was just made, maintenance in the Gulf Coast. It looks like guidance or throughput is down quarter-over-quarter for 1Q from 4Q about 300,000 barrels a day. Can you just discuss if what maintenance activity you're going to have on 1Q, if there are other one-time items impacting that guidance? And if you think that's indicative of the industry as a whole, just given it seems like there was a lot maintenance delayed due to COVID over the past couple of years.
And then my second question is, hopefully, one you can answer kind of on geopolitics and what's going on with Russia. Valero imports a lot of intermediate feedstock from Russia and can you just discuss maybe the margin kind of enhancement that provides and how you're more broadly thinking about both the risks and opportunities these geopolitical issues with Russia present for your company?
So this is Lane. I'll take the first one. So we don't really comment directly on our turnaround activity going into the quarter. The volumes are the proxy for that, so you can just sort of decide what that means. And we certainly don't -- we also don't comment on our peers on what we think they're doing with respect to turnarounds. This is just sort of a policy for us.
Gary, you want to talk about Russia?
Yes. So obviously, we don't really until any kind of sanctions are announced, we don't really know what they would entail. What I can tell you is that when we've seen things like this happen in the past in other locations, it simply results in a change in trade flows. So what we would expect to happen here is some of those intermediates that we're running today will be run somewhere else throughout the world. And wherever those end up going, they'll kick out feedstocks that make it available for us to run.
So certainly, as a commercial team, we're looking at what those are today and making sure we have them approved in our system and are ready to run them if we need to in the future.
Our next question is coming from Connor Lynagh of Morgan Stanley.
Maybe sticking with major exporters. I was wondering what you guys made of the discussion around Pemex potentially ending crude exports? And what do you see as the implications? Do you think it's likely to occur? And what do you think the implications on particularly the Gulf Coast refining industry would be?
Yes. So this is Gary. I think Lane has been pretty public on our views on being able to meaningfully change refinery reliability and utilization. He's kind of said 2 turnaround cycles and a lot of capital. So it looks like their goals are pretty aggressive. But if they're able to increase refinery utilization, if it does focus refinery starts up, certainly, it would decrease the amount of crude for export. Our view is that the first destinations to be cut will really be European destinations and Asian destinations for export from Mexico. [It goes first]. Our experience has been that as they increase refinery runs in Mexico, they increase the export of high-sulfur fuel oil, and that's a good feedstock for our high complexity U.S. Gulf Coast system that actually serves as a nice complement to a lot of the light sweet grades we run in our U.S. Gulf Coast system. We've had a long-standing great relationship with Pemex, and we expect that to continue long into the future.
Got it. Helpful context. Maybe just returning to the capacity question, but in a global sense. The closures, obviously, you had sort of a net decline in some areas and you're sort of at least in theory, flipping back to growth at a global capacity level over the next couple of years here. I mean do you -- are you concerned about that? Do you see that meaningfully altering the -- to your earlier point, product flows or crude flows? Just how do you think about that impact on your margins?
This is Lane. I mean, we read the same journals you guys do and trade magazines, and we have people that keep up with refinery closures and refineries starting up. Obviously the Middle East has some refinery starting up. China has some. I guess we sort of believe that China has this longer-term plan of having larger refineries run instead of what we call the teapot refineries.
But at the end of the day, it's hard to really sort of have a real strong view on where all this really heads. I always go back to when the refinery -- the Indian refinery alliance was starting up, and we were concerned then, and we from our experience were able to review those refineries, stress and calculated their import parity into our marketing. At the end of the day, what happened is most of the barrels stayed in the region. So you just -- these are difficult things to work through. But what we do is we run our assets. We make sure they're competitive not holding here in the U.S. but everywhere in the world. And we know that as long as there's [rent] out there in this industry, we'll get our share of it. So...
Thank you. At this time, I'd like to turn the floor back over to Mr. Bhullar for closing comments.
Great. Thanks, Donna. Thanks, everyone, for joining us today. Obviously, if there's anything you want to follow up on, feel free to ping the IR team. Thank you, and have a great week.
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