Ladies and gentlemen, thank you for standing by, and welcome to the Valero Energy Corporation's First Quarter 2020 Earnings Call. At this time, all participants are in a listen only mode. After the speaker presentation, there will be a question and answer I would now like to hand the conference over to your speaker, Mr. Homer Buller, Vice President of Investor Relations. Please go ahead, sir.
Good morning, everyone, and welcome to Valero Energy Corporation's Q1 2020 Earnings Conference Call. With me today are Joe Gorder, our Chairman and Chief Executive Officer Lane Riggs, our President and COO Donna Tietzman, our Executive Vice President and CFO Jason Fraser, our Executive Vice President and General Counsel 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 1 on our Web site atvalero.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. Well, we've all had a very challenging start to the year with significant impact to our families, communities and businesses worldwide brought on by the COVID-nineteen pandemic. The ensuing collapse of economic activity due to stay at home orders and travel restrictions has driven down demand for our products, particularly gasoline and jet fuel. Despite these extraordinary challenges, we're blessed to be able to continue supporting our community partners and organizations on the front lines that help people most in need in response to the COVID-nineteen pandemic. Across the country, we see neighbors and strangers helping one another and demonstrating genuine human kindness.
With that in mind, our ethanol operations produced hand sanitizer for distribution to hospitals, emergency responders and other organizations and I'm proud of our employees for their innovation and efforts to make this possible. Valero entered this economic downturn in a position of strength and our team has been thorough, decisive and swift in our operational and financial response to the current environment. Operationally, we've adjusted the throughput rates at our refineries to more closely match product supply with demand to ensure that our supply chain does not become physically infeasible. We also temporarily idled a number of our ethanol plants and reduced the amount of corn feedstock processed at the remaining plants to address the decreased demand for ethanol. Financially, we remain well capitalized.
We started the year with a solid cash balance. Due to the uncertainty in the markets and attractive rates available to us, we thought it'd be prudent to strengthen our financial position further. We entered into a new $875,000,000 revolving credit facility, which remains undrawn and we raised $1,500,000,000 of debt for additional liquidity. We also temporarily suspended buybacks in mid March. In addition, we decided to defer approximately $100,000,000 in tax payments that were due in the Q1, along with approximately $400,000,000 in capital projects for the year, including slowing the Port Arthur Coker and Pembroke Cogen projects, which pushes out their mechanical completion by 6 to 9 months.
That being said, we continue to make progress on several of our strategic projects. We completed the Pasadena Terminal project, which expands our products logistics portfolio, increases our capacity for biofuels and the St. Charles alkylation unit remains on track to be completed in 2020. And we're continuing to make progress on the Diamond Pipeline expansion and the Diamond Green Diesel project, both of which should be completed in 2021 subject to COVID-nineteen related delays. The Diamond Green Diesel joint venture also continues to make progress on the advanced engineering review of a potential new renewable diesel plant at our Port Arthur, Texas facility.
So the actions we've taken are consistent with the capital allocation framework we've had in place for several years. We continue to prioritize our investment grade credit rating and non discretionary uses of capital, including sustaining capital expenditures and our dividend. And you should continue to expect incremental discretionary cash flow to compete with other discretionary uses, primarily organic growth capital and buybacks. Our framework has served us well and we'll continue to adhere to it in the future. In closing, the health, safety and well-being of our employees and the communities where we operate remain among our top priorities.
Our prudent management of operations has allowed us to weather a global shutdown like this without layoffs. And while a tremendous amount of uncertainty remains in the near future, our operational and financial flexibility allow us to navigate through today's challenging macro environment. Our advantaged footprint with the flexibility to process a wide range of feedstocks coupled with a relentless focus on operational excellence and a demonstrated commitment to stockholders positions our assets well as our country and the world return to a more normal way of life. So with that, Homer, I'll hand the call back to you.
Thanks, Joe. For the Q1 of 2020, the net loss attributable to Valero stockholders was $1,900,000,000 or $4.54 per share compared to net income of $141,000,000 or $0.34 per share for the Q1 of 2019. Q1 2020 adjusted net income attributable to Valero stockholders was $140,000,000 or $0.34 per share compared to $181,000,000 or $0.43 per share for the Q1 of 2019. Q1 2020 adjusted results exclude an after tax lower of cost per market or LCM inventory valuation adjustment of approximately $2,000,000,000 For reconciliations of actual to adjusted amounts, please refer to the financial tables that accompany this release. The refining segment generated an operating loss of $2,100,000,000 in the Q1 of 2020 compared to $479,000,000 of operating income for the Q1 of 2019.
Q1 2020 adjusted operating income for the refining segment, which excludes the LCM inventory valuation adjustment was $329,000,000 First quarter 2020 results were impacted by low product margins related to the COVID-nineteen pandemic and the rapid decline in crude prices. Refining throughput volumes averaged 2,800,000 barrels per day, which was in line with the Q1 of 2019. Throughput capacity utilization was 90% in the Q1 of 2020. Refining cash operating expenses of $3.87 per barrel were $0.28 per barrel lower than the Q1 of 2019, primarily due to lower natural gas prices. Operating income for the Renewable Diesel segment was $198,000,000 in the Q1 of 2020 compared to $49,000,000 for the Q1 of 2019.
After adjusting for the retroactive blenders tax credit, adjusted renewable diesel operating income was $121,000,000 in the Q1 of 2019. The increase in operating income was primarily due to higher sales volumes. Renewable diesel sales volumes averaged 867,000 gallons per day in the Q1 of 2020, an increase of 77,000 gallons per day versus the Q1 of 2019. 20.20
compared to
$3,000,000 of operating income in the Q1 of 2020 compared to $3,000,000 of operating income in the Q1 of 2019. The Q1 of 2020 adjusted operating loss, which excludes the LCM inventory valuation adjustment was 69,000,000 dollars The decrease from the Q1 of 2019 was primarily due to lower margins resulting from lower ethanol prices and higher corn prices. Ethanol production volumes averaged 4,100,000 gallons per day in the Q1 of 2020. For the Q1 of 2020, general and administrative expenses were $177,000,000 and net interest expense was 125,000,000 dollars Depreciation and amortization expense was $582,000,000 and the income tax benefit was 6 $16,000,000 in the Q1 of 2020. The effective tax rate was 26%, which was impacted by an expected U.
S. Federal tax net operating loss that can be carried back to years prior to December 2017 enactment of tax reform in the U. S. Net cash used in operating activities was $49,000,000 in the Q1 of 2020. Excluding the unfavorable impact from the change in working capital of $1,100,000,000 as well as our joint venture partners' 50% share of Diamond Green Diesel's net cash provided by operating activities, excluding changes in its working capital, adjusted net cash provided by operating activities was 9 $54,000,000 With regard to investing activities, we made $705,000,000 of capital investments in the Q1 of 2020, of which approximately $468,000,000 was for sustaining the business, including costs for turnarounds, catalyst and regulatory compliance.
Approximately $237,000,000 of the total was for growing the business. Excluding our partners' 50% share of Diamond Green Diesel's capital investments, Valero's capital investments were approximately 666,000,000 Moving to financing activities, we returned $548,000,000 to our stockholders in the Q1 of 2020. $401,000,000 was paid as dividends with the balance used to purchase 2,100,000 shares of Valero common stock. The total payout ratio was 57% of adjusted net cash provided by operating activities. As of March 31, we had approximately $1,400,000,000 of share repurchase authorization remaining.
And last week, our Board of Directors approved a quarterly dividend of $0.98 per share, further demonstrating our solid financial position and commitment to return cash to our investors. With respect to our balance sheet at quarter end, total debt and finance lease obligations were $11,500,000,000 and cash and cash equivalents were $1,500,000,000 The debt to capitalization ratio net of cash and cash equivalents was 34%. In April, we closed on a $364 day, dollars 875,000,000 revolving credit facility, which remains undrawn. Including this credit facility, we had over $5,000,000,000 of available borrowing capacity. Turning to guidance, we now expect annual capital investments for 2020 to be approximately 2 a reduction of $400,000,000 from our prior guidance.
The $2,100,000,000 includes expenditures for turnarounds, catalysts and joint venture investments. For modeling our 2nd quarter operations, we expect refining throughput volumes to fall within the following ranges: U. S. Gulf Coast at 1.325000000to1.375000000 barrels per day U. S.
Mid Continent at 315,000 to 335,000 barrels per day. U. S. West Coast at 215,000 to 235,000 barrels per day and North Atlantic at 15,000 to 335,000 barrels per day. We expect refining cash operating expenses in the second quarter to be approximately $4.50 per barrel.
Our ethanol segment is expected to produce a total 2,000,000 gallons per day in the Q2. Operating expenses should average $0.49 per gallon, which includes $0.12 per gallon for noncash costs such as depreciation and amortization. With respect to the Renewable Diesel segment, we expect sales volumes to be 750,000 gallons per day in 2020. Operating expenses in 2020 should be $0.50 per gallon, which includes $0.20 per gallon for non cash costs such as depreciation
and amortization.
For the 2nd quarter, net interest expense should be about 145,000,000 and expenses, excluding corporate depreciation, to be approximately $825,000,000 And we still expect the RINs expense for the year to be provisions in the CARES Act as well as the COVID-nineteen pandemic and its impact on our business, small changes in assumptions yield a wide range of outcomes resulting in a low degree of confidence in any estimate of the effective tax rate. So at this point, we're not providing any guidance on it. 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 and A to 2 questions. If you have more than 2 questions, please rejoin the queue as time permits.
This helps us to ensure other callers have time to ask their questions.
Thank you. Our first question will come from Doug Terreson with Evercore ISI. Please go ahead.
Good morning, everybody.
Good morning, Bill.
So global refined product supply is falling in response to the declines in demand that we're seeing with more competitive plants probably reducing output less than others. And on this point, I wanted to get your insights on Atlantic Basin and global storage levels, whether you think we're nearing capacity and if so, when might we get there? So just some fundamental color on these market areas if you have it. And then second, because refiners are completely shut down often face challenges when they restart, if they restart. I want to see if you kind of frame the pros and cons for us of those decisions and also whether the new fuel specs might affect restarts in the current scenario.
So the questions are on market fundamentals and potential capacity outcomes.
Got it.
Okay, Doug, this is Gary. Yes, on your question on market fundamentals in the North Atlantic basin, we were staring at that pretty hard a few weeks ago and thought we were going to have an issue with that region filling up with products, but really been encouraged by the reaction of the industry to cut rates and to make less gasoline and diesel. At least the API yesterday showed that PADD 1 had a small draw on gasoline, which is encouraging. But at this stage, it looks like the industry has done a good job to balance supply with demand and we're not as concerned about filling up on inventory.
Okay, good.
Hey, Doug, this is Lane. I'll answer the second question. So you're exactly right. Whenever the risk of everybody, I'm sure most refiners try to push their refiner utilization down to somewhere near minimum, which normally is 60% to 65% for a given unit. But so when because the risk of shutting one down very much puts you at risk of when you try to start back up, it's not going to start up and you have to go into a full blown turnaround.
Now with that said, we actually did shut down our St. Charles SEC. It's a big SEC and it was because we had just finished the turnaround. So we saw that as being a way to take off some gasoline producing capacity for our system and not take that risk. In terms of fuel quality, it's just there's a lot investment out there in terms of lower sulfur.
It just depends on, for some reason, a GDU or UFD unit has a problem on startup. But other than that, I don't as I think about that for us, I haven't seen that be a big problem for us.
Okay. Thanks a lot, guys.
Thanks, Troy.
Thank
you. Our next question will come from Theresa Chen with Barclays. Please go ahead.
Good morning. Thank you for taking my questions. First question, just on the depth and duration of the demand shock. Gasoline margin seems to be responding to the industry lowering utilizations and margins have improved, but the diesel side has seen some volatility recently. I'm not sure if it's just reflecting real economic contraction in activity.
Can you just talk about what's happening there on the diesel side?
Yes, Theresa, this is Gary. So I think as we talked about the industry did a good job of balancing supply and demand on the gasoline side. For the most part, along with that, we were cutting refinery crude runs with the expectation that would bring diesel balance is pretty close to supply being in balance with demand. However, the jet demand destruction was just so severe and everyone started blending jet into diesel. It caused the diesel yield from refineries to be really at record levels.
And even despite the lower refinery utilization, we've seen diesel production outpacing demand causing the inventory build. I think we are seeing at least this week starting to see some indications in the market that people in the industry, including ourselves are making some adjustment to their operations to bring the diesel yields down, which should be supported to the diesel fundamentals moving forward.
Got it. And in terms of the recent force majeure declarations, whether it be Flint Hills, your refining neighbor in Corpus or Continental as a producer or PENEX declaring force majeure on gasoline imports, do you see an acceleration of this? Do you think the reasoning would likely hold up in the court? And can you just talk about how you see these developments evolving as both an entity that can declare force majeure as a counterparty on which force majeure could be declared against?
So Theresa, we're trying to okay. Are you asking kind of a legal perspective on force majeure? Are you asking kind of do we expect the market to continue to do this?
A lot or more.
Okay. So Gary, you want to Yes.
So I can tell you most of our certainly on the crude side of the business, most of our contracts have a 30 day cancellation and we've been trying to tell our suppliers we expect to hold them to that. And so, so far we haven't really seen much of a disruption in crude supply as a result of the force majeure as you're reading about in the press.
Got it. Thank you for taking my questions. Again, I hope you all stay safe and well in these challenging times.
Yes, likewise. Likewise. Thank you.
Thank you. Our next question will come from Manav Gupta with Credit Suisse. Please go ahead.
Hey, so at the start of the call, you mentioned weaker gasoline demand. What I'm trying to understand is Texas is lifting the order on Friday. Florida has minimum number of cases. So those 2 are big demand states and looks like their orders have been lifted at least a partial reopen by end of this week. And then there are about 16 states that have come behind them with their prospective reopen plans.
So what I'm trying to understand is, yes, gasoline demand is bad right now. But as one after another of these states do start opening, like when do we start seeing a rebound in the gasoline demand as these states do start coming online?
That's a good question. Let me give you anecdotal answer and then Gary can give you what we're seeing in the system here in Lane. But I mean, in San Antonio proper, we have because I'm serving on some committees that are working on some issues here, but we've seen a 14% increase in traffic over the last couple of weeks. So people are starting to get out more. And as you said, we're going to be opening up and I think there probably is a pent up demand for folks to get out of their houses and get mobile and to shop again and to go to restaurants again.
So I do think we're going to see more activity and not only here, but much more broadly, particularly through the South. Gary, within the system, we've also seen some change in demand.
Yes, we have. So we saw a very sharp fall off in demand really in the last 2 weeks in March, kind of got to a point in our system where we're seeing demand about 55% of what we would call normal. For the 1st couple of weeks in April, it seemed to have stabilized around that level, but now we're starting to see demand pick back up already. So if you look at the 7 day average in our rack systems, it's about 64% of normal. So already about a 9% increase of where we were kind of early April.
And as you mentioned, where you're really seeing the pickup is in the Mid Continent, the Gulf Coast regions as some of these stay at home orders are lifted. We're seeing a fairly significant sharp increase in demand.
Thanks guys. A quick follow-up, your benchmark indicator on the newbuild diesel side was almost down $0.45 but the realized margin actually was up quarter over quarter. I'm trying to understand how did you feel successful and managed to beat your own benchmark and deliver a beat on the renewable diesel side?
Manav, this is Martin. On the benchmark, you have to realize we're using a soybean oil price. So our actual feedstock costs are going to differ from that. There's other impacts too, contractually what we're doing this year versus last year. So I'm not going to give you a hard and fast answer on that, but it's we just you're kind of seeing the strength of renewable diesel and the strength of Diamond Green there.
Thank you for taking my questions.
You bet. Take care.
Thank you. Our next question will be from Roger Read with Wells Fargo. Please go ahead.
Hey, thanks. Good morning.
Good morning, Roger.
Well, tons of stuff to ask here. But I guess where I'd like to go, first question really, what are you seeing in terms of the crude side of the market? How has that been flowing through in terms of we had negative crude prices for a day, availability of different lights and heavies and maybe how that's flowing through. Maybe some guidance on what capture can be in such a uncertain market condition?
Yes, Roger, a lot of volatility in the crude markets and we've certainly been changing our purchase signals from week to week, kind of moving throughout the quarter. I think for quite some time now, we've been signaling really maximum light sweet along with heavy sour and we haven't seen the economics of the medium sours as much. We got into March and medium sours became economic and we ramped up medium sours. However, that I would say we've kind of returned back to the place where we were before to where we're back kind of maximizing light sweets and heavy sours in our system. And certainly in some regions, you're seeing real wide market dislocations on some of the light sweets that we're buying, especially in the Mid Continent region, Line 9 through Quebec is providing us with a big benefit.
And then we're balancing those light sweet purchases with a lot of different heavy sour feedstock. So kind of step back into some of the high sulfur fuel blend stocks along with some heavy sour crude that we're sourcing from Canada and South America.
Yes, I'm going to go out on a limb and say you're not having any trouble finding crudes at this point.
No, no trouble in that area at all.
All right. That's not one to get Joe to laugh. 2nd question on the regulatory side. I had a couple of parks here, but we're going to have a real issue with hitting any sort of ethanol blending this year. So where do you stand on or where do you think the market stands maybe on getting some relief there?
And then I was curious if there's any other regulatory headaches in front of you at this point, stuff we don't normally think about, but whether it's the winter grade, December grade exclusions that were given into May or any other sort of headwinds we should think about on the regulatory side?
Okay. Jason, you want to speak to that?
Yes. Yes, I can definitely talk a little bit about the RFS. Of course, with the large drop in gasoline and diesel demand and the harm to our industry, the compliance cost for the RFS does stick out a little more and it's definitely not helping things. And RIDs are still pretty high. They didn't really drop at the price of our products.
So 5 governors recently sent a letter to the EPA requesting the exercise of their severe economic harm waiver authority to reduce RBOs for 2020. We definitely agree with those governors and believe the EPA has the authority and the basis to grant those waivers and lower the volumes. As far as other regulatory headwinds, I
can't think of any headwinds right now. So the guys can. So we'll just take them 1 at a time, Roger.
Appreciate that. Thank you, guys.
You guys take care.
Thank you. Our next question will come from Phil Gresh with JPMorgan. Please go ahead.
Yes. Hi, good morning.
Hi, Bill.
First question, you had mentioned demand at about 64% of normal. And your utilization guide for the quarter looks like it's in the low 70s. Would you say that today you're operating kind of below that midpoint and the expectation with that guidance is that utilization would have ramp over the quarter? Or would you say that you intend to kind of have a more stable utilization and if demand gets better, we start to see inventory
draws. Hey, Matilda, this is Lane. So if you think about it, the low 70s on a throughput basis, not all of which goes into gasoline. So we're trying to make sure that we are careful to match our feedstock plans with where we think demand is. Now, pent into that is a slight some recovery towards the end of it, but our buying habits right now have to be on the assumption that crude will be available and that we're going to run our assets to meet demand and not necessarily let structure drive us to maybe outrun demand or anything like that.
Okay. And just broadly, how do you think about, you think about the macro on the gasoline and the diesel side, over the next, call it, 1 to 2 quarters, how do you think about the inventory progression for the industry based on the way you've been modeling it?
Well, Gary took a shot at that earlier. I guess I can take another shot at it and then Gary can tune whatever I have to say here. I think the industry has done a really good job with respect to gas plant. We were when it first started, that was our primary concern. And I think the industry responded with appropriate rate reductions and including us.
And where we are today is you have, like Gary mentioned, jets dropping into diesel. So how I think that will play out is there are signals right now out there to essentially drop diesel in the gas oil, which will replace some BGO purchases into these conversion units. So you should see some diesel disruption. And then everybody is going to have to stare at how much crude they really think they need to meet demand. And so ultimately, it comes back to demand versus how does this crude supply.
Obviously, there is a lot of crude. So you don't have to reach out very long or far, get your supply chain very committed, then you can ramp up accordingly or cut accordingly depending on how that plays out.
Okay, great. And then my follow-up is just on CapEx. How much flex do you see in your capital spending as you move into 2021? It sounds like most of the CapEx that you're cutting back on this year was more related to growth projects, but just wanted any color as you look out. Thanks.
Yes. We would expect if we needed to, it would be something commensurate with the $400,000,000 that we talked about and gave the guidance for this year.
Okay, great. Thank you.
Thank you. Our next question will come from Doug Leggate with Bank of America. Please go ahead.
Thank you. Good morning, everyone.
Hey, Joe, it
seems like a long time since we had our virtual dinner. So I hope you guys are all doing well.
Sure, it sure has. Thanks, Doug.
So, I have two quick questions. First of all, I don't know if John is there, but I wanted to ask about working capital, the mechanics of any potential unwind and how you would expect the working capital to the trajectory through the year? I know it's a bit of a moving feast. And I guess a related question, which is my second question, also financial on the balance sheet. I know you're at 34% net debt to cap.
I think that's probably about the highest level you've had in quite a while. Obviously, there's no liquidity issues. But I'm just curious as to where you see the balance sheet headed over the medium term and how would you look to move it back? And I guess what I'm really trying to understand is, if and when things normalize, would you tend to run with a more robust balance sheet going forward after this? Or how would your behavior change it relates to just treatment of buybacks, balance sheet, dividends, things of that nature?
And I'll leave it there. Thank you.
Great.
All right.
Well, I'll start with the working capital. No, you're correct. As we've seen prices level off a bit and then hopefully now as they start to recover with the economy waking back up, we would expect to see that working capital draw reverse itself. I can't tell you how quickly that will happen. That is really all dependent on how quickly we see these prices recover.
And to answer the balance sheet question, obviously, yes, the debt cap has gone up a bit here of late. Our intentions would be as everything gets back to normal to also normalize that balance sheet a bit when we raised the $1,500,000,000 we did that in short term maturities and not in 10s 30s with the idea that that would become repayable much quicker than a longer term issuance. So our intent would be to kind of get back to where we were pre all of this as quickly as we can. And again, the liquidity, as you mentioned, is absolutely key today. So we are definitely in the cash preservation mode right now, but we have a very strong liquidity level and are very comfortable with where we're at today.
Donna, can I just ask for some clarification on the working capital? You run a I assume a net payables position. I was really more interested in the mechanics. I understand we've had a big drop in crude prices. So obviously, that hurts you.
But do you anticipate that was a big move obviously in Q1, but do you anticipate any additional moves in terms of use of working capital after the sharp you've had in oil prices? Or do you think the worst is kind of behind us there?
Well, I think you can expect that a lot of this started in mid March and continued through the April timeframe. So you should probably expect some of that to have carried into April. But as I mentioned, things are leveling off and hopefully now we're looking at improvement from this point forward. So we shouldn't see that same kind of level of cash being consumed.
All right. Appreciate it. That's it from you guys. Thank you very much. Good luck.
Thanks, Doug. Take care, buddy.
Thank you. Our next question will come from Neil Mehta with Goldman Sachs. Please go ahead.
Hey, Steve. Good morning and hope all of you are doing well. I just wanted to follow-up on this question of demand and we've talked a lot about on this call 2020 demand conditions. But Joe and team, I want to get your perspective on sort of the structural questions of demand, particularly for 2 products, gasoline and jet. And so gasoline, the thoughts around work from home and does that create a change in social behavior that has an impact on low gas demand?
And jet the willingness of the consumer to travel. I think all of us are just trying to figure out whether there is a long term impact from some changes that we've seen here over the last month or do you view this as more cyclical?
Yes, Neal, this is Gary. So I think we are taking those things into account. So where we saw a fairly sharp decline in demand to this 55% level, we would expect the recovery to be more gradual on the demand side as people continue to work from home. We see some offsetting things, Certainly, people working from home, but then you're going to have people driving more and probably using mass transit less going forward. It's just because of social distancing is hard when you're on mass transit.
So overall, we see a fairly gradual recovery in demand, but gasoline demand getting back close to where it was pre COVID. On the jet side, I think we believe that the lower jet demand is probably here with us longer. And it probably is a late year type recovery for people are going to get back and start flying again or requires a vaccine or something on the medical side to happen where people start to feel comfortable flying again.
That's great. Thank you. The follow-up is just on the dividend. I think the message you're trying to deliver here is that the dividend is a core priority and something that you're committed to. But just wanted to get your perspective on that and hear how you guys are thinking about the sanctity of your dividend?
Okay, Neil. I'll take a first crack and then I'll let Donna also have a shot at this. But with the situation we're dealing with right now with the pandemic, we consider to be a fairly short term in nature and obviously our team is running the business for the long term. And as the guys have mentioned, we're already seeing improvements in demand, which we think are going to continue as people return to more normal activities. So let's look at how we've managed the business, what we've said for several years now and how we're managing it going forward, okay.
We've got this capital allocation framework in place that we've adhered to for years. And within that framework, we consider the use of cash for sustaining CapEx and turnarounds and then the dividends to be non discretionary. And then the discretionary uses are acquisitions, growth projects and share repurchases and there's the competition that we have for those dollars within those three categories. So with that in mind, think about what we've done and the actions that we've taken today, okay. We've reduced our discretionary capital spending and our share buybacks And we're not considering any acquisitions until there's certainly further improvements in the market.
So those three things are playing out the way they should within the context of that capital allocation framework. But if you look at additional actions that has been taken, we have a very capable proactive Board of Directors and they declared the dividend last Friday. And they have the same confidence in our business and this team that I have. So the things that we've talked about for years are the things that we've implemented and that we use both when margins are really strong and when margins are weak like they have been here over the last 6 or 8 weeks. And so in my view, relative to the dividend, we've got a long way to go before we need to take any action there.
Donna, anything you would like to add?
No. I mean, just all along, we have maintained a conservative balance sheet for the purpose of being able to survive times like this.
Great guys. Very clear.
Thanks, Neil.
Thank you. Our next question comes from Prashant Rao with Citigroup. Please go ahead.
Thank you. Good morning. Thanks for taking my question. My first question is on the balance sheet and specifically on debt. I wanted to sort of touch back on that.
You guys took good advantage of the low interest rate environment and the strength of your financial position with that $1,500,000,000 in recently issued debt. I'm just wondering, depending upon how the recovery here goes economically, are there further opportunities ahead to take advantage of these low interest rates, maybe potentially refi or retire other parts of the current debt perhaps that plays into this as well. So any color there would be appreciated. Thanks.
Sure. So the problem with refinance this is something that we look at all of the time, not just in this environment, but on a regular basis. The issue typically with retiring refinancing current debt out there is we have make whole provisions in all of our agreements. So effectively, what we're doing is paying the investor the impact of the current load prices anyway. So from an economic perspective, that rarely works out to be a good deal.
That being said, we continue but we're always looking for odd moments in the market where things may not trade as efficiently as others. Many times those are smaller opportunities and not larger opportunities. But again, we'll continue to look for those ideas, but I wouldn't say that, that would happen in any big way.
Okay. Thank you. That's clear. My follow-up is sort of a pre differential question. We've seen a lot of disparities, some disconnects between what we see on the screen and the physical market, I guess, the financial and the ability of refiners to capture some of those dislocations?
And how cautious should we be in thinking about that as we look forward and as we model here? And did some of those pre differential advantages maybe be preserved into further quarters or months ahead given that utilization rates are low right now? So I wanted to get a sense of those. There's a lot of working parts in there, but get a sense of how those of us who aren't operating experts might be able to think about that from a modeling perspective?
Sure. This is Gary. Kind of
a couple of ways on
the crude side. Some of our contracts, some of our supply contracts on the crude side are based on a monthly average price. So obviously, when you had the dislocation that happened at the end of the month, it does figure into the monthly average and will ultimately make its way to our delivered crude costs. And then we also I can't say that we anticipated the crude going negative like it did, but we certainly saw the potential for weakness as you got the contract expiry. So we did probably go into that period of time a little on the short side to give us the opportunity to go out and buy some of those discounted barrels and we've done that.
And then to your point, if we had room to absorb in our system, we'll run those barrels. If not, there's places where we're putting those barrels into storage and you'll see that benefit in months to come.
Thanks.
Thank you. Our next question will come from Paul Cheng with Scotiabank. Please go ahead.
Hey, guys. Good morning.
Good morning, Paul.
I just want to wish everyone and the team and your family safe and healthy. Joe and Gary, can you talk a bit about the export market? Because I think that they've been holding up reasonably well in the Q1, but seems like they start to be having some crack. I'm actually quite concerned because I think Latin America probably have a lot of infected cases that they probably didn't know yet. So maybe you can help us understanding that what you're seeing, particularly in the last 2 or 3 weeks, have you seen any trend?
Okay. Paul, this is Gary. So really our April volumes, we don't have the final accounting volumes done yet, of course, but our April export volumes are down about 10% from what we did in the Q1 or more typical type numbers. So you're not really seeing it in April, but in May, with what we're selling forward, you're seeing a far lower demand in the Latin American countries than what we've typically seen kind of support. On the distillate side, you did see a fall off in diesel exports.
Some of that is just been because the U. S. Inventories were very low. And so the U. S.
Market was stronger and we were better to keep the barrels in the domestic market than to ship them abroad. But on the distillate side, we saw exports falling off around 60% of normal. Gasoline has been more 10%. Where we're selling wholesale barrels like into Mexico, we've been surprised at how well those volumes have held up. So yesterday in Mexico, we moved 85% of what we were moving in the Q1.
So our wholesale volumes of barrels that we're selling in country are holding, but we are seeing the export markets fall off.
Thank you. And Gary, you talked about the gas, the storage is not going to reach the 10 top in the Atlantic basin. Can you talk about in the group 3 or in the inland market?
Yes. So that was the other area that we had a lot of concern on. And again, you could see in the mid continent refiners adjusted and it looked like we may fill up in a couple of weeks and now they've kind of adjusted gasoline balance with the demand and we're seeing inventory draws. And the Mid Continent is one of the areas that we've actually seen the best recovery in demand out of all the regions.
Can you talk about California because we've seen a sharp improvement in the margin over the last couple of weeks, but is there any particular reason driving that?
Yes. So that really is more driven, I would say, from the production side. I the refining industry has done a good job of bringing units offline and getting production balanced with demand. We've actually seen some inventories draw on PADD V and so that's led to the strength in the gasoline market.
All
right. Thank you.
Thanks, Paul.
Thank you. Our next question will come from Benny Wong with Morgan Stanley. Please go ahead.
Hey, good morning guys. Thanks for taking my question.
I hope everybody on the line is safe and
healthy. My first question is really on planned maintenance. We've seen a
lot of facilities defer maintenance work,
just given the challenges of COVID.
Just looking a little bit further out, when
we're back to more of
a normal environment, would you expect a little bit of pent up maintenance activity that needs to be had by then?
Or do you think there's enough flexibility for guys to kind
of do the work during this period of reduced runs and shutdowns right now?
So, Vinny, I'll just use this is Lane. I'll just give you our behavior as a proxy for that. We were fortunately good positioned in that the second half of the year, we had a low sort of planned turnaround basis. So we just didn't have a lot of planned turnarounds. And so when we looked at all of our so we look at our turnaround, we look at our maintenance, we're making sure that we maintain our plants just like we do in our framework and very carefully.
But we did sort of push some discretionary maintenance into next year and I'm sure a lot of people are going to do that. At some point, obviously, people have to do turnarounds. People who are deferring turnarounds and doing a lot of that, at some point that does catch up and we'll just have to see. And then at some point, you have to take a turnaround. There was a question earlier that I answered too.
If somebody shut a unit down that is a long somewhere near the end of its run cycle, there will be some risk to starting it up, which may force them to take the turnaround early.
Got it. Thanks, Linda. That's super helpful. My second question is on the renewable diesel side. Just curious with this economic shutdown, the impact it's had on demand and even on the feedstock side.
And just taking a little further out, any risk that these events might cause some of the jurisdictions that are looking at adopting LCFS to maybe those plans being delayed?
Okay. This is Martin. I think if you step back and put DGD in perspective, right, we've got a great first order in the book. We're running at full capacity and our outlook hasn't changed as we're committed to the long term strategy of growing the business. With COVID-nineteen, carbon prices dropped slightly, but the rent has escalated entirely offset that and the gallon blenders tax credit dollar per gallon is in place.
On the feedstock availability, you have understand, we're running 275,000,000 gallons a year now. We have plans to go up to 4 times that amount and we still believe we can secure the feedstock for that. So this is kind of a there's disruptions, but it's not significant. We're not concerned about keeping feed in front of the unit. As far as what it does for the LCFS, I think all this is rather temporary.
And as I characterize it as a bump in the road, but I don't think it's going to slow anything down materially and certainly in the rearview mirror, I don't think it's going to be that significant.
Yes. I don't Jason, I don't know what you think, but I don't think anybody is going to back off of LCFS type regulations.
Yes. I don't think so. You may see a little bit of slow with them actually enacting rules and bills just because they've taken a lot of recesses with the social distancing. So the legislature, a lot of statements really slowed down over the last couple of months. So we're starting to see them talk about coming back and get back into session.
I think Arizona and
California are coming back. We're just talking about it yesterday. But you
could see that a little bit
it. Thanks, guys. Appreciate the thoughts. Please stay safe.
Got it. Thanks guys. Appreciate the thoughts. Please stay safe.
You too. Thanks.
Thank you. Our next question will come from Brad Heffern with RBC Capital Markets. Please go ahead.
Hey, good morning, everyone. Another question on capture. I think some of the things that have been discussed so far have been around crude discounts and sound like they're positive for capture. I'm just wondering with these refineries running in these sort of unusual constraints, load utilization and maybe FCC is being shut down. Are there decrements we need to be thinking about to capture as well, either as it relates to how much you can optimize the system or maybe the production of intermediates or something along those lines?
So, Brett, this is Lane.
So I would just say on with respect to anything it might be something to think about. The conversion units create volume gains, whether they're hydrocrackers or SCCs. So to the extent that we're cutting SCCs and hydrocrackers to meet the demand that we think there are, you'll have a you could have a negative your volume gain isn't there that helps in your margin capture. I would say outside of that, I don't know if there's anything else with how we're operating to directly impact that.
Okay, got it. Thanks. And then maybe one for Martin, just on the ethanol business, you guys gave the guidance of 2.0 for this quarter, down a little bit more than 50%. Is there a reason that you're not running it lower than that, just given that we're seeing negative margins on the screen here even before OpEx? Thanks.
Okay. Sure. Well, as you know, we've got 8 of our plants down and 6 running. So we're actually running lower than 50% today. This demand destruction really hit home in ethanol, right?
Significant cuts have been made across the industry. We cut, if you look at the April EIA information, it would tell you is that demand is implied demands less than 50% of last year. So we think we're in the right spot. Ultimately, this will recover right and global renewable fuel mandates will drive export growth. Domestically, we'll get going again and ethanol is going to be in the gasoline pool and we'll see incremental demand as a result of fuel efficiency standards and year round E15 sales.
Okay. Thanks all. Stay healthy.
You too.
Thank you. Our next question will come from Sam Margolin with Wolfe Research. Please go ahead.
Good morning, everybody. Hope all is well.
Hi, Sam.
I've got a sort of outlook question. Gary, you mentioned that your light sweet throughput was up in the quarter. That's probably because crude production was up in the U. S. Still in the Q1.
That doesn't look like it's going to continue. I mean, in the environment where U. S. Crude production declines and really doesn't return to levels that it's at today for 3 or 4 years, how do you think that affects your business and your capital allocation decisions? Do you think we're going to reenter an environment that's very complexity oriented?
Or do you is there something else that might be less obvious that you're paying attention to anything around that theme would be helpful?
So, hey, this
is Lane. Sam, I would say in terms of capital allocation, if you think about the things that we're investing in on the refining side, it's the coker, right? There's other small caps that always we work on our feedstock flexibility, but to the extent that there's something that has a feedstock feed element to that's really more about positioning yourself to continue to run for heavy sour. We built the 2 crude units to run domestic. I think we think obviously you have to destock, even though there's some production losses going in this, you're going to have to destock domestic crude for a while as there is a recovery.
So we're not making big investments to run additional domestic crude because we think we've done that. So we don't have this sort of project in the future to try to take more advantage of that. So we think we've done it. But we don't really have a lot of projects, big projects that are even pointed at trying to take advantage or do something different on our feedstock selection.
And then just a follow-up on feedstock. You mentioned that high sulfur fuel oil kind of components still look attractive, certainly on a percentage to Brent basis, the discount is pretty wide. How do you balance that with sort of your throughput utilization decisions? I would imagine there's some there's at least some incentive across the board to maybe run ahead of demand, but where do you sort of draw the line between regular way business and what might cross into trading or something that you don't want to be involved?
That's a really good question. So what I would say is we all of our refineries are essentially just open capacity, right? It's a little bit it's an interesting place to be when you're trying to do your planning and doing relative value to feed stocks into it is open. So we are pretty basic. We are doing our best to try to optimize our feedstock collection into matching demand and trying to be very careful not to run ahead of demand even though there'll be structure that might try to incentivize you to do so.
So we are being very paying particular attention to doing that. But we're doing but Gary mentioned that we started out, we were sort of a lot of domestic crude and heavy and then as this thing unfolded and we saw gasoline get weak, which would have disadvantaged. Domestic crudes, we sort of went to medium sour and really low up on heavy. And as we've seen gasoline start to pick up and it looks like that's in line, you're seeing us sort of work back, I think, to sort of our traditional posture. It's just we're going
to be running less of it.
All right. Thanks so much.
Thank you. Our next question will come from Ryan Todd with Simmons Energy. Please go ahead.
Great. Thanks. Maybe just one
high level strategic one for me. I know it's hard to speculate at this point, Joe, but if you're looking at the crystal ball, are there any structural changes you see down the line that are likely to impact your business and may impact the way you allocate capital? I know you talked a little bit about potential longer term impact to demand. But as you think about overall as you run your business, operational practices, regional preferences within the portfolio, long term calls on capital, are there any structural things coming out of this that you think that you're thinking about in terms of Valero down the line?
Yes. No, we're always thinking about it, right? But you can't run I said this earlier, I think you can't run the business based on a short term set of circumstances. And so we're reassessing our long term strategy all the time and we meet with our Board on it to review it every year. But if you look at what we've done, okay, and kind of our approach to the business, I don't know that anybody sitting in the room here with me would consider refining to be a long term growth story, okay.
It's really it's a business where I think the industry has set itself now to basically match supply and demand going forward. And so the way we look at it is we run the business to maximize the margin that we can capture within the business. And so our capital is focused on optimization projects and logistics projects, which allow us to lower our cost structure of things coming into the plants and going out of the plants. And then just how do we get a little more value out of every stream it is that we process. That's the view that we've adhered to now for several years and I think it's the view that we're going to adhere to going forward.
So it's a little early right now for me to say that there's any fundamental changes other than those that we've already implemented around capital, a greater focus on the renewables, the greener fuels going forward, which we've done with the ethanol business and with the renewables renewable diesel business. But other than that, I just don't envision anything, any major change of direction right now.
Great. I appreciate it. Thank you. That's all for me.
Thank you. Our next question will come from Jason Gabelman with Cowen. Please go ahead.
Thanks for taking the questions. I wanted to ask about the regional guidance that you provided. You mentioned that Mid Con demand has been getting stronger. That regional utilization guidance is kind of at the lower end of the range. North Atlantic also and then U.
S. West Coast, looks like those assets are going to be the highest running at the highest utilization rates in 2Q. So can you just discuss some of the puts and takes by region that results in that dispersion of run rates? Thanks.
Yes. It's Lane. I'll take a stab. Our view when Gary is talking about the Mid Con and it's getting better, when you think about refinery operation, when you have a refinery setting in the mid continent, if you get out of balance, it can become you might end up shutting a refinery down. So we have taken the position on where we are essentially landlocked to be very cautious on our feedstock plants with the assumption there's plenty of oil to go get it if we needed to whatever reason we believe that demand is picking up.
So it's really around where was demand versus expectations and where were our concerns about sort of the feasibility of our operations where we were landlocked is all these policies around COVID impacted demand. So that's really where I think Gary's thoughts were. It's just now we see that the Mid Continent has sort of bottomed out, seems to be recovering a little bit better. So we have a run our plan is to make sure that we have we are shorting our supply chain and that we can manage it and respond to it quickly and not get ourselves to where we're over committed on supply chain in the event that we have that creates a problem for us if something doesn't quite happen the way that we hope it does. And that's really the narrative all the way across every system that we have.
We're just being very careful trying to match the demand with that region with an understanding that the West Coast, the Mid Continent is not you have to get that right. If you don't get if you get it wrong, you get into some having to do very uneconomic things to fix those problems. The Gulf Coast is a big system, can go into a lot of different pipeline servicing a lot of different parts the country and then ultimately export to sort of satisfy its balance. But even there, we're being very cautious. Our North America I mean, the Atlantic is really we have we're doing some work in both of those refineries in the second quarter.
Got it. Thanks. And just a follow-up on a longer term margin outlook. Clearly, it looks like demand is starting to improve from the bottoms, but there's a lot of global refining capacity out there that's not being utilized right now. And historically, refiners have reacted pretty quickly to changes in demand.
So I'm just wondering what your outlook is over the next year. Even if demand recovers, if it doesn't come fully back, is there a risk that there's slack in the global refining system that could limit the gains in refining margins until demand more fully recovers? Thanks.
Yes, this is Gary. I would say certainly there is that risk. But again, I would point to we've been very encouraged by the discipline the industry shown. And we're hopeful that maybe what you saw in March in the case that demand fell off sharply and it took a couple of weeks for refineries to modify their operations to come back closer to being in balance with demand, you see a reverse of that as demand picks up and we set our operations to run at lower production rates, maybe you get some big draws. But there's no way for us to really speculate how the industry is going to respond as demand recovers.
Got it. Thanks for the time.
Thank you. Our next question will come from Matthew Blair with Tudor, Pickering, Holt. Please go
ahead. Hey, good morning, Joe. Glad to hear everyone is safe.
Thanks, Matthew.
If I take midpoint refining throughput guidance against your $450,000,000 OpEx guidance, it looks like your projected total OpEx to be coming down by about $90,000,000 versus Q1 levels. Is that $90,000,000 simply your energy savings on running the boilers at lower rates? Or are there other areas where you've been able
to cut costs as well?
Yes. This is Lane again. So if you think about our cost structure in the refinery, we have variable costs and fixed costs. And the variable costs, it's an interesting thing to think about because in a $1.80 sort of Henry Hub pricing environment, variable costs, which for us includes FCC catalyst, chemicals and natural gas to fire our boilers and our heaters. There's really somewhere now down between 15% 25%, whereas maybe in years past where natural gas was much more expensive, would have been a bigger component.
So yes, natural gas purchases is a part of that. It's not it's really if you look all the way down the line, we sort of we have our variable costs, if we've cut SEC cows, we've cut natural gas, but we've also we also see our we've reduced our contractor headcount some and looking at very carefully our sort of discretionary maintenance also bring that down and again try to be very careful with operating costs.
Sounds good. And then, could you also talk about your ability to capture contango in this market, both for U. S. Barrels as well as for your offshore barrels? There's been some reports that refiners are looking to procure additional storage, maybe even like renting out Jones Act Tankers.
So can you just walk through all that?
Yes. Well, certainly, the market structure is such that if you can put barrels in tankage or whether that's floating storage or tankage in Cushing, the market pays you to do that. In terms of our everyday purchases, a lot of the market structures built into the prices you see and you don't necessarily get a big benefit from market structure except for mid continent barrels that we purchase And we tend to see a bit when we're in contango versus when the market structures of backwardation. It's a pretty complex discussion and I would ask you if you want to go into that in detail, you can call Homer and we could set up a discussion to go into more detail about that.
Sounds good. Thanks guys.
Thanks, Matthew.
Thank you. Ladies and gentlemen, thank you Thank you. Ladies and gentlemen, thank you for participating in today's
question and
answer session. I would now like to turn the call back over to management for any further remarks.
Thanks, Sherry. We appreciate everyone joining us today and hope everyone stays safe and healthy. If you have any follow-up questions, as always, don't hesitate to reach out to the IR team. Thank you.
Ladies and gentlemen, this concludes today's conference call. Thank you for your participation. You may now disconnect.