瓦萊羅能源 (VLO) 2020 Q1 法說會逐字稿

Ladies and gentlemen, thank you for standing by, and welcome to the Valero Energy Corporation's First Quarter 2020 Earnings Call.

(Operator Instructions) I would now like to hand the conference over to your speaker, Mr. Homer Bhullar, Vice President of Investor Relations.

Please go ahead, sir.

Good morning, everyone, and welcome to Valero Energy Corporation's First Quarter 2020 Earnings Conference Call.

With me today are Joe Gorder, our Chairman and Chief Executive Officer; Lane Riggs, our President and COO; Donna Titzman, 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 one on our website at valero.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-19 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 need in response to the COVID-19 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 would be prudent to strengthen our financial position further.

We entered into a new $875 million revolving credit facility, which remains undrawn.

And we raised $1.5 billion of debt for additional liquidity.

We also temporarily suspended buybacks in mid-March.

In addition, we decided to defer approximately $100 million in tax payments that were due in the first quarter along with approximately $400 million 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 blending and enhances flexibility for exports.

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-19-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 nondiscretionary 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 first quarter of 2020, the net loss attributable to Valero stockholders was $1.9 billion or $4.54 per share compared to net income of $141 million or $0.34 per share for the first quarter of 2019.

First quarter 2020 adjusted net income attributable to Valero stockholders was $140 million or $0.34 per share compared to $181 million or $0.43 per share for the first quarter of 2019.

First quarter 2020 adjusted results exclude an after-tax lower of cost or market, or LCM, inventory valuation adjustment of approximately $2 billion.

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 $2.1 billion in the first quarter of 2020 compared to $479 million of operating income for the first quarter of 2019.

First quarter 2020 adjusted operating income for the refining segment, which excludes the LCM inventory valuation adjustment, was $329 million.

First quarter 2020 results were impacted by low product margins related to the COVID-19 pandemic and the rapid decline in crude prices.

Refining throughput volumes averaged 2.8 million barrels per day, which was in line with the first quarter of 2019.

Throughput capacity utilization was 90% in the first quarter of 2020.

Refining cash operating expenses of $3.87 per barrel were $0.28 per barrel lower than the first quarter of 2019, primarily due to lower natural gas prices.

Operating income for the renewable diesel segment was $198 million in the first quarter of 2020 compared to $49 million for the first quarter of 2019.

After adjusting for the retroactive Blender's Tax Credit, adjusted renewable diesel operating income was $121 million in the first quarter 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 first quarter of 2020, an increase of 77,000 gallons per day versus the first quarter of 2019.

The ethanol segment generated an operating loss of $197 million in the first quarter of 2020 compared to $3 million of operating income in the first quarter of 2019.

The first quarter of 2020 adjusted operating loss, which excludes the LCM inventory valuation adjustment, was $69 million.

The decrease from the first quarter of 2019 was primarily due to lower margins resulting from lower ethanol prices and higher corn prices.

Ethanol production volumes averaged 4.1 million gallons per day in the first quarter of 2020.

For the first quarter of 2020, general and administrative expenses were $177 million, and net interest expense was $125 million.

Depreciation and amortization expense was $582 million, and the income tax benefit was $616 million in the first quarter 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 the December 2017 enactment of tax reform in the U.S.

Net cash used in operating activities was $49 million in the first quarter of 2020.

Excluding the unfavorable impact from the change in working capital of $1.1 billion, as well as our joint venture partner's 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 $954 million.

With regard to investing activities, we made $705 million of capital investments in the first quarter of 2020, of which approximately $468 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance.

Approximately $237 million of the total was for growing the business.

Excluding our partner's 50% share of Diamond Green Diesel's capital investments, Valero's capital investments were approximately $666 million.

Moving to financing activities.

We returned $548 million to our stockholders in the first quarter of 2020.

$401 million was paid as dividends with the balance used to purchase 2.1 million 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 $1.4 billion of share repurchase authorization remaining.

And last week, our Board of Directors approved a quarterly dividend of $0.98 per share, further demonstrating our sound 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 $11.5 billion, and cash and cash equivalents were $1.5 billion.

The debt-to-capitalization ratio net of cash and cash equivalents was 34%.

In April, we closed on a 364-day $875 million revolving credit facility, which remains undrawn.

Including this credit facility, we had over $5 billion of available borrowing capacity.

Turning to guidance.

We now expect annual capital investments for 2020 to be approximately $2.1 billion, reflecting a reduction of $400 million from our prior guidance.

The $2.1 billion includes expenditures for turnarounds, catalysts and joint venture investments.

For modeling our second quarter operations, we expect refining throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.325 million to 1.375 million 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 315,000 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 of 2 million gallons per day in the second quarter.

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 noncash costs such as depreciation and amortization.

For the second quarter, net interest expense should be about $145 million, and total depreciation and amortization expense should be approximately $580 million.

For 2020, we expect G&A expenses, excluding corporate depreciation, to be approximately $825 million.

And we still expect the RINs expense for the year to be between $300 million and $400 million.

Lastly, due to the impact of beneficial tax provisions in the CARES Act as well as the COVID-19 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.

(Operator Instructions)

(Operator Instructions) Our first question will come from Doug Terreson with Evercore ISI.

So global refined product supplies 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 have 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.

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 APIs yesterday showed that PADD 1 had a small draw in 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.

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 refinery utilizations down to somewhere near minimum, which nominally 60% to 65% for a given unit.

But so we -- 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 FCC.

It's a big FCC.

And it was because we had just finished a 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 of investment out there in terms of lower sulfur.

It just depends on, if for some reason, a GDU or ULSD unit has a problem on start up.

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.

Our next question will come from Theresa Chen with Barclays.

The first question is on the just depth 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.

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 balances 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, that people in the industry, including ourselves, are making some adjustment to their operations to bring the diesel yields down, which should be supportive 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 Pemex declaring force majeure on gasoline imports, do you see an acceleration of this?

Do you think the reasoning would likely hold up in court?

And can you just talk about how you see these developments evolving as both an entity that can declare force majeure or 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?

Or are you asking kind of do we expect the market to continue to do this?

The latter, more.

Okay.

Gary, you want to?

Yes.

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 expected 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 majeures you're reading about in the press.

Our next question will come from Manav Gupta with Crédit Suisse.

In sort of the call you mentioned weaker gasoline demand.

What I'm trying to understand is Texas is lifting the order on Friday.

Florida has a minimum number of cases.

So those two are big demand states and looks like their orders will be 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 an anecdotal answer, and then Gary can give you what we're seeing in the system, him and 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 demands.

Yes, we have.

So we saw a very sharp fall off in demand really in the last two weeks in March.

Kind of got to a point in our system where we were seeing demand about 55% of what we would call normal.

For the first 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 state home orders are lifted.

We're seeing a fairly significant sharp increase in demand.

A quick follow-up.

Your benchmark indicator on the renewable 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 successfully manage to beat your own benchmark and deliver a beat on the renewable diesel side?

So 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 to 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.

Our next question will be from Roger Read with Wells Fargo.

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 an uncertain market condition?

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 Québec 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 oil blend stocks, along with some heavy sour crudes 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.

Second question on the regulatory side in a couple of parts here.

But we're going to have a real issue with hitting any sort of ethanol blending volumes this year.

So where do you stand on -- or what 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 to summer grade exclusions that we've 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 in the harm of our industry, the compliance cost for the RFS does stick out a little more, and it's definitely not helping things.

And RINs are still pretty high.

They didn't really drop with the price of our products.

So five governors recently sent a letter to the EPA requesting they exercise their severe economic harm waiver authority to reduce the RVOs for 2020.

We definitely do 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 right now.

Or the other guys can.

So we just take them one at a time, Roger.

Our next question will come from Phil Gresh with JPMorgan.

Yes.

So 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 the utilization would have ramped 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?

Phil, this is Lane.

So if you think about it, the low 70s is on a throughput basis, not all of which goes into gasoline and diesel.

What we're trying to make sure is that, 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 is to be on the assumption that crude will be available, and then 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 -- if you think about the macro on the gasoline and the diesel side, over the next, call it, one to two 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 gasoline.

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, jet dropping into diesel.

So how I think that will play out is there are signals right now out there to essentially drop diesel into gas oil, which will replace some VGO purchases into these conversion units, so you should see some diesel destruction.

And then everybody is going to have to stare at how much crude they really think they need to meet demand.

And so ultimately, 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 to 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 want any color as you look out.

Yes.

We would expect if we needed to be something commensurate with the $400 million that we talked about and gave the guidance for this year.

Our next question will come from Doug Leggate with Bank of America.

Joe, it seems like a long time since we had our virtual dinner.

So hope you guys are all doing well.

It sure has.

Thanks, Doug.

So two quick questions.

First of all, I don't know if Donna is there, but I wanted to ask about working capital and 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 what -- how would you move -- 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?

So how would your behavior change as it relates to just treatment of buybacks, balance sheet, dividends, things of that nature?

And I'll leave it there.

All right.

Well, I'll start with the working capital.

Now, you're correct, Doug.

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 net debt to 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 $1.5 billion, we did that in short-term maturities and not in 10s and 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, 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 drop 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 time frame, 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.

Our next question will come from Neil Mehta with Goldman Sachs.

Hope all of you are doing well.

I just wanted to follow up on this question of demand.

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 two products, gasoline and jet.

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's a long-term impact from some of the changes that we've seen here over the last month?

Or do you view this as more cyclical?

Yes.

Neil, this is Gary.

So I think we are taking those things into account.

And 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 the 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 the 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 before people are going to get back and start flying again, or requires a vaccine or something on the medical side to happen to where people start to feel comfortable flying again.

That's great.

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 the 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 it to be 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 demands, 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 nondiscretionary.

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 to date, 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.

And 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 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.

Our next question comes from Prashant Rao with Citigroup.

So my first question is on the balance sheet and specifically on debt.

I wanted to sort of touch back on that.

You guys have good advantage of the low interest rate environment and the strength of your financial position with that $1.5 billion 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 structure, lower your overall interest expense?

Donna, you made a comment about sort of the appetite for longer tenor versus shorter tenor debt, so perhaps that plays into this as well.

So any color there would be appreciated.

Sure.

So the problem with refinancing -- 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 or 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 low prices anyway.

So from an economic perspective, that rarely works out to be a good deal.

That being said, we continue -- we're always looking for an odd moments in a 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.

That's clear.

My follow-up is sort of a crude differential question.

We've seen a lot of disparities and some disconnects between what we see on the screen and the physical market, I guess the financial and the physical market.

We get some questions on the ability to aid that disparity and what that means for the ability of refiners to capture some of those dislocations?

How cautious should we be in thinking about that as we look forward and as we model here?

Did some of those crude differential advantages maybe be preserved into further quarters or months ahead given utilization rates are low right now?

So I sort of want 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 have 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 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.

Our next question will come from Paul Cheng with Scotiabank.

I also want to wish -- first want to wish everyone and the team and your family are 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 first quarter.

It 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 are seeing, particularly in the last two or three weeks?

Have you seen any trend?

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 first quarter 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 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 falloff in diesel exports.

Some of that has 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 into 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 first quarter.

So our wholesale volumes, barrels that we're selling in-country, are holding.

But we are seeing the export markets fall off.

And Gary, you talked about the gas.

The storage is not going to reach the tank tops probably in the Atlantic Basin.

Can you talk about 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 and demand out of all the regions.

Can you talk about California?

Because we've seen a sharp improvement in the 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 think the refining industry has done a good job of bringing units off-line and getting production balanced with demand.

We've actually seen some inventories draw on PADD 5, and so that's led to the strength in the gasoline market.

Our next question will come from Benny Wong with Morgan Stanley.

Hope everybody on the line is safe and healthy.

My first question is really on the 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 Benny, I'll just use -- this is Lane.

I'll just give you our behavior as a proxy for that.

We were fortunately in a good position in that the second half of the year, we had a low sort of planned turnaround basis.

So we 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 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.

So people who are deferring turnarounds are doing a lot of that.

At some point, that does catch up, and we'll just have to see.

And at some point, you have to take a turnaround.

And there was a question earlier that I answered too.

If somebody shut a unit down that is along -- 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.

That's super helpful.

My second question is on the renewable diesel side.

Just curious with this economic shutdown, the impact we've 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 quarter 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-19, carbon prices dropped slightly, but the RIN has escalated entirely offset that.

And the gallon Blender's Tax Credit dollar per gallon is in play.

On the feedstock availability, you have to understand we're running 275 million gallons a year now.

We have plans to go up to 4x 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 I'd 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 slowdown in them actually enacting of laws and bills just because they've taken a lot of recesses with the social distancing.

So the legislature in a lot of the states have really slowed down over the last couple of months.

But we're starting to see them talk about coming back and get back into session.

I think Arizona and California are coming back.

We were just talking about it yesterday.

But you could see that -- a little bit of delay in that.

But I don't think it changes the long-term trend or their views.

Our next question will come from Brad Heffern with RBC Capital Markets.

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, low 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 Brad, 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 gain whether they're hydrocrackers or FCCs.

And so to the extent that we're cutting FCCs from the hydrocrackers to meet the demand that we think there are -- you'll have -- 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 that would directly impact that.

Okay.

Got it.

And then maybe one for Martin.

Just on the ethanol business.

You guys gave the guidance of 2.0 million 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?

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 that demand is -- implied demand is 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.

Our next question will come from Sam Margolin with Wolfe Research.

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 first quarter.

That -- it doesn't look like it's going to continue.

I mean, in the environment where U.S. crude production declined and really doesn't return to levels that it's at today for three or four 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 is there something else that might be less obvious that you're paying attention to?

Anything around that theme would be helpful.

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 is over the coker, right.

There's other small caps that always we work on our feedstock flexibility.

But to the extent that if there's something that has a feedstock or feed element to -- that's really more about positioning yourself to continue to run sort of heavy sour.

We built the two 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.

And so we don't have this sort of projects in the future to try to take more advantage of that because 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.

Okay.

Good.

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 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 this 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 values of feedstock into it, it's open.

So we are pretty basic.

We are doing our best to try to optimize our feedstock selection into matching demand and trying to be very careful not to run ahead of demand even though there will be a structure that might try to incentivize you to do so.

So we are being very -- paying particular attention to doing that.

But we're -- 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 loaded 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.

Our next question will come from Ryan Todd with Simmons Energy.

Maybe just one.

A 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 that 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 impacts 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 -- 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 our renewable diesel business.

But other than that, I just don't envision anything -- any major change of direction right now.

Our next question will come from Jason Gabelman with Cowen.

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?

Yes, this is Lane.

I'll take a stab at that.

Our view -- when Gary is talking about the Mid-Continent and it's getting better, when you think about a 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 plans 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 it was demand versus expectations and where were our concerns about sort of the feasibility of our operations where we are 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.

It seems to be recovering a little bit better.

And so we had a run -- but our plan is to make sure that we have -- we are shortening our supply chain and that we can manage it and respond to it quickly and not get ourselves to where we're overcommitted 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 some very uneconomic things to fix those problems.

The Gulf Coast is a big system.

You can go into a lot of different pipelines, servicing a lot of different parts of the country and then ultimately export to sort of satisfy its balance.

But even there, we're being very cautious.

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.

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 they're slacking the global refining system that could limit the gains in refining margins until demand more fully recovers?

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's 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.

Our next question will come from Matthew Blair with Tudor, Pickering, Holt.

Glad to hear everyone is safe.

If I take midpoint refining throughput guidance against your $450 million OpEx guidance, it looks like your projected total OpEx will be coming down by about $90 million versus Q1 levels.

Is that $90 million 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 a refinery, you have variable costs and fixed costs.

And the variable cost -- and 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 catalysts, chemicals and natural gas to fire our boilers and our heaters, there's really somewhere now down between 15% and 25%.

Whereas maybe in years past where natural gas was much more expensive, we've done 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, which we've cut FCC catalysts, 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 to also bring that down, again, trying 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 structure is built in to 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 in 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.

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, Cheri.

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.