瓦萊羅能源 (VLO) 2017 Q1 法說會逐字稿

Good morning, and welcome to the Valero Energy Corporation Reports 2017 First Quarter Earnings Results Conference Call.

My name is Vanessa, and I will be your operator for today's call.

(Operator Instructions).

Please note that this conference is being recorded.

And I will now turn the call over to your host, Mr. John Locke, Vice President Investor Relations.

Sir, you may begin.

Good morning, and welcome to Valero Energy Corporation's First Quarter 2017 Earnings Conference Call.

With me today are Joe Gorder, our Chairman, President and Chief Executive Officer; Mike Ciskowski, our Executive Vice President and CFO; Lane Riggs, our Executive Vice President of Refining Operations and Engineering; Jay Browning, our Executive Vice President and General Counsel; 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.

Now I'd 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 a few opening remarks.

Well, thanks, John, and good morning, everyone.

Our team again delivered solid operating results and distinctive financial performance during a quarter where we saw heavy maintenance activity and soft margins.

Our continued focus on safety and reliability in our plants has been key to our ability to capture the available margin.

In the first quarter, we saw healthy domestic and export demand for refined products, driven by low prices, seasonal weather conditions in North America and Europe and a resurgence of domestic oil patch activity.

Latin America also continued to be a strong source of demand for gasoline and diesel.

On the crude supply side, we continued to see rig count increases in the U.S., particularly in the Permian Basin.

As production ramps up and more domestic sweet crude makes its way to the Gulf Coast, our refineries in the Mid-Continent and the Gulf Coast are prepared to capture the feedstock opportunities.

While RIN prices have declined relative to 2016, there is still a significant headwind for the quarter.

At this level, RINs expense remains an issue for us, so we continue to work with regulators.

Turning to our refining segment.

In the first quarter, we completed a heavy turnaround schedule at our Venetia, Texas City, St.

Charles and Meraux refineries.

Our employees and contractors safely executed these projects.

With the majority of our planned maintenance for the year behind us, we should be ready to capture available market opportunities.

In our ethanol business, we had record production volumes for the quarter as higher ethanol prices and strong demand for ethanol exports supported production rates.

Also in the first quarter, we invested $641 million of sustaining and growth capital.

Construction is progressing on the Diamond Pipeline, with completion expected at the end of this year.

Work on the Diamond Green Diesel plant expansion, the Houston alkylation unit and the Wilmington cogeneration plant is continuing as planned.

Turning to our MLP.

As we disclosed in our 10-K for 2016, we created a new VLP segment to align how we manage and allocate resources.

Growth in our VLP segment is critical to Valero's strategy to optimize the supply chain.

The third party acquisition of the Red River pipeline in January is a good example of VLP executing this strategy, which is focused on assets that are key to Valero's operations or that will supply third-party volumes without taking on commodity risk.

Lastly, regarding cash returns to stockholders.

We paid $629 million in cash through dividends and stock buybacks, so we believe we're in good shape to exceed our payout target for the year.

This payout demonstrates the company's free cash flow generating capability, even in a soft margin environment.

So with that, John, I'll hand it back over to you.

Thank you, Joe.

For the first quarter, net income attributable to Valero stockholders was $305 million or $0.68 per share compared to $495 million or $1.05 per share in the first quarter of 2016.

First quarter 2016 adjusted net income attributable to Valero stockholders was $283 million or $0.60 per share.

For reconciliations of actual to adjusted amounts, please refer to page 3 of the financial tables that accompany our release.

Operating income for the refining segment in the first quarter of 2017 was $647 million compared to $915 million for the first quarter of 2016, which has been revised retrospectively to reflect the new VLP segment.

First quarter 2017 operating income was in line with first quarter of 2016 adjusted operating income of $652 million.

Refining throughput volumes averaged 2.8 million barrels per day, which was in line with the first quarter of 2016.

Our refineries operated at 91% throughput capacity utilization in the first quarter of 2017, which reflects turnarounds that occurred at the Venetia, Texas City, St.

Charles and Meraux refineries.

Refining cash operating expense of $3.85 per barrel were $0.39 per barrel higher than the first quarter of 2016, mainly due to a higher level of maintenance activity and higher energy cost in the first quarter of 2017.

The ethanol segment generated $22 million of operating income in the first quarter of 2017 compared to $39 million in the first quarter of 2016.

Adjusted operating income for the first quarter of 2016 was $9 million.

The increase from the 2016 adjusted amount was primarily due to higher the ethanol prices and record production volumes.

Operating income for the VLP segment in the first quarter of 2017 was $70 million compared to $43 million in the first quarter of 2016.

The primary drivers for the increase in operating income are contributions from the McKee, Meraux and Three Rivers Terminals and the Red River pipeline, which were acquired subsequent to the first quarter of last year.

The Red River pipeline operations acquired in January have been integrated into VLP and are performing as expected.

For the first quarter of 2017, general and administrative expenses, excluding corporate depreciation, were $190 million and net interest expense was $121 million.

Depreciation and amortization expense was $500 million and the effective tax rate was 26% in the first quarter of 2017.

The effective tax rate was lower than expected mainly due to a reduction in the statutory rate in Québec and favorable settlements from several state income tax audits.

With respect to our balance sheet at quarter end.

Total debt was $8.5 billion and cash and temporary cash investments were $4.5 billion, of which $66 million was held by VLP.

Valero's debt to capitalization ratio, net of $2 billion in cash, was 24.1%.

We have $5.4 billion of available liquidity, excluding cash, of which $720 million was available for only VLP.

We generated $988 million of cash from operating activities in the first quarter.

Excluding a working capital benefit of $151 million, net cash generated was $837 million.

With regard to investing activities, we made $641 million of growth and sustaining capital investments, of which $245 million was for turnarounds and catalyst.

Moving to financing activities.

We returned $629 million in cash to our stockholders in the first quarter, which included $315 million in dividend payments and $314 million for the purchase of 4.7 million shares of Valero common stock.

As of March 31, we had approximately $2.2 billion of share repurchase authorization remaining.

Our guidance for 2017 capital expenditures of $2.7 billion remains unchanged.

This amount, which includes turnarounds, catalyst and joint venture investments, consists of approximately $1.6 billion for sustaining and $1.1 billion for growth.

For modeling our second quarter operations, we expect throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.69 million to 1.74 million barrels per day; U.S. Mid-Continent at 440,000 to 460,000 barrels per day; U.S. West Coast at 285,000 to 305,000 barrels per day; and North Atlantic at 455,000 to 475,000 barrels per day.

We expect refining cash operating expenses in the second quarter to be approximately $3.70 per barrel.

Our ethanol segment is expected to produce a total of 3.8 million gallons per day in the second quarter.

Operating expenses should average $0.39 per gallon, which includes $0.05 per gallon for noncash costs, such as depreciation and amortization.

We expect G&A expenses, excluding corporate depreciation for the second quarter, to be around $170 million, and net interest expense should be about $115 million.

Total depreciation and amortization expense should be approximately $500 million and our effective tax rate is expected to be around 30%.

That concludes our opening remarks.

Before we open the call to questions, we again respectfully request that callers adhere to our protocol of limiting each turn in the Q&A to 2 questions.

This will help us ensure that other callers have time to ask their questions too.

If you have more than 2 questions, please rejoin the queue as time permits.

(Operator Instructions) And we have our first question from Benny Wong with Morgan Stanley.

You had some positive market commentary in your press release this morning.

I'm just curious to hear your thoughts around -- product balances for refining [ rents ] expected to pick up strongly and where you expect the demand to come to meet that?

Yes, Benny, I think what we've seen is early -- and I'll talk about gasoline first, early in the year, we saw that gasoline demand looked to be down a little bit and when we looked at the data more specifically, you can see it was a lot weather-related, especially on the West Coast, you had a rainy season, which caused demand to be down.

As we progressed through the quarter, our March volumes looked to be fairly consistent with what we saw last year.

So I think we think domestic demand will be fairly consistent with what we saw last year, but we're seeing a stronger pull on exports than what we saw last year, particularly to Latin America, there appears to be a good pull of gasoline into Mexico and South America.

On the distillate side, really, for the whole first quarter, we saw slightly better distillate demand, some of that was due to a little bit colder weather.

We've seen good agricultural demand, and then as we start to see the upstream recover, we're starting to see a pull there as well on the distillates.

And then, distillate exports are also strong again, same, we're seeing some exports to Europe, but mainly strong export demand into Latin America.

Great.

Really appreciate the color.

And just in regards to the splitting of the VLP results.

Can we read into this as a signal to expect a lot more growth and drop-down activity in this area?

I don't -- we don't provide guidance on our dropdowns as it relates to the VLP.

I mean, we're in good shape.

We do provide the distribution growth plans for the next 2 years, but we have high coverage rate at VLP, and so we're not going to provide any of the drop-down guidance.

And Benny, I think, and John can talk a little bit, too.

He and Mike -- we went through this process of trying to decide, did we want to go ahead and create the segment.

We felt we needed to create the segment so that there was more line of sight to what it is.

And then, the question becomes what do you put in the segment.

We decided to keep it as clean as possible.

And just be sure that everybody had a line of sight to the fact that this is the way we manage the business, and we wanted it to be very clear and clean.

So the portfolio of assets that we have at Valero that are still droppable, all of that EBITDA that's droppable into VLP is there, but we didn't want to cloud it by including that.

So anyway, it's a pretty straight up segment.

Our next question comes from Phil Gresh from JP Morgan.

First question, just want to come back to Joe, your commentary in RINs.

Do you view that the quarterly run rate here as a fair number for the full year?

I think you were expecting a higher number when we were coming out of last quarter.

And then, just generally, your thoughts on what's happening right now, thoughts on the preliminary RVO standard, point of obligation potential.

I know there was a hearing going on yesterday where the U.S. Appeals Court was questioning the EPA's authorities and suggesting Congress should be responsible for fixing the renewable fuel standards.

So it seems like there's a lot of information out there.

Yes.

Phil, that's a good question.

And I'll let Gary talk a little bit about the RIN market and then Jason can just give you an update on the regulatory front, if that's okay.

Yes.

So I think, we certainly saw, especially D6 RINs fall off early in the year.

We're not really ready to revise our guidance at this time.

We're going to keep our guidance where it is.

And we'll just see how successful we are on some of these things about moving the point of obligation and what happens to RINs.

Okay.

And regarding the 2018 -- sorry, regarding the time line for releasing the 2018 RVO targets, we think they're going to try to hit the November 30 deadline.

They're going to try to stay on target.

To meet that, they need to push the proposed rule out by late May or early June.

And on those oral arguments you mentioned that occurred yesterday on the lawsuit relating to the 2014 to 2016 RFS targets.

We understand, there were a lot of questions and the judges were pushing the EPA on the grounds that they used to grant the waiver and their questions, I think, they were kind of signaling that maybe the EPA could have used another ground, which would have been even more defensible than the one that they did.

They based it on inadequate domestic supply of biofuels versus -- causing severe economic harm.

But we wouldn't read too much into the questions or the oral argument.

We do think the EPA properly issued the waiver when they did it.

And one thing that we would note is, in the arguments and the questions from the judges, it was clear to us that our arguments that the point of obligation should be evaluated in setting the RVO numbers, which was what we claimed in the case, had some traction.

The judges seem to buy into that, so we were encouraged by that.

Now what we think's going to happen with the point of obligation overall, kind of to give you an update on the process we're going through.

The comment deadline on our petition to change the point of obligation was February 22.

The EPA has now received all the comments and they're reviewing them.

We think the majority of the comments that were filed are in favor of our position.

And with the new team at the EPA, we're really hopeful.

We think when they look at the facts, we expect them to resolve this question in our favor.

And on timing, which is what a lot of people are asking.

There's no specific deadline on the EPA.

We think they're diligently looking at this and there's a lot of concern and urgency because of the harm, the high RINs prices are doing to the refining sector.

So we think it could be done in the next 6 months if they push it.

Okay, great.

I appreciate the color.

Second, just be on light medium and light heavy differentials.

We've started to see some tightening here in the second quarter, which I presume is mostly due to the effects of the OPEC cuts starting to flow through.

Is that consistent with what you guys have been seeing out there?

And generally, how are you thinking about light medium, light heavy differentials?

Yes.

I think that is consistent.

We saw that when OPEC announced their cuts that there wasn't a big market reaction and I think a lot of that was we feel like there was a demand offset to the supply offset.

So we had lower refinery demand with turnaround season.

And then, they weren't burning as much oil, so there wasn't that much of an impact.

And then we also think that a disproportionate amount of the cuts went to the Far East and not to the U.S. market.

As the U.S. has kind of come out of turnaround season, you're starting to see a bigger impact of those cuts on the medium to light differential.

And I think where we are, as we just kind of are waiting to see if really the OPEC countries are committed to our market or not.

So, so far, they've kind of sent the volume they want to send, but we got in last week where the differentials were to the point where economic signals were starting to point us to switch to a more domestic light sweet diet and back out the medium sour from the Middle East.

What we've seen this week, it's starting to widen back out, so I think they recognize that.

I think they're committed to maintaining market share here.

And we've kind of seen a floor on that medium to light spread because of you started to see refineries switch to the lighter diet.

And so this week, it's improved about $0.50 from where we were last week.

Our question comes from Paul Cheng with Barclays.

I think this may be for Gary, the first question.

Gary, I believe you guys have mentioned, you are spending about $350 million a month in the secondary costs outside the feedstock, it means that to bring either the feedstock or the crude or the product from point to point.

And that is a major area where that you think optimization and improvement could be.

Can you give us some example, what could be done?

And how big is the magnitude?

Are we talking about a potential 10% is the reasonable medium-term objective of benefit?

Or higher or lower?

Any kind of number that you can share?

Yes, Paul.

So it's really impossible for us to give guidance of [ carry ] because so much of what's rolled into this is outside of our control.

So just to give you an example.

Freight rates play a big role in that overall $350 million of spend.

Things that we're doing is, renegotiating terminal deals that we have, making sure that our barge utilization is as efficient as it can.

And so what we'll try to do is work with John.

We have some dashboarding tools that we're using to measure our progress and we'll try to work with him to see if there's something we can share with you guys going forward, but I can't really give you a dollar target.

Okay.

Second one, Joe.

In terms of the organic investment opportunity in the company, where do you see the biggest opportunity for the next, say, 2 or 3 years?

Well, Paul, I think it's in the refining side of the business and the midstream side of the business.

I'll let Lane talk a little bit about the projects that we've got going on in refining, and then maybe Rich wants to share a little bit about anything we got going on in the logistics side.

But Rich, don't tell them anything secret.

We will keep it a secret here.

Yes.

I know you would, Paul.

All right.

Paul, it's Lane.

So we still a strategic outlook where we think, we are always looking at our assets with respect to feedstock flexibility and really, there are sort of 2 lines that we invest there.

One is, look at sort of the natural capital arbitrage as it sits in refining to make sure we can fill it out the way we'd like and make sure we have access to the right feedstocks.

The other way we invest in that is in Rich's area, and that's getting connectivity to terminals or docks with respect to getting the products out or the feedstocks in.

So really, when we think about feedstock flexibility, it's really the opportunity to invest both refining and logistics.

We also have sort of a long-term outlook that we think octane's going to be valuable and we're in the process of building our Houston alky.

We're looking at other octane capability throughout our system.

And so that's really the other one.

And the final one, we're building the cogens at both Wilmington and we're looking at one at Pembroke.

And this was in response to where we think that sort of natural gas -- or price where there's an arbitrage between where -- how the utilities are going to provide power costs versus our ability to make it ourselves using natural gas.

Paul, this is Rich.

Part of the organic stuff that we've got going on is, right, we've been vocal about the Diamond Pipeline.

That's gone through the DRB process and has full funding approval.

We're about 40% complete on that.

Going forward, the organic stuff that we look at kind of is supportive of Gary's $350 million of secondary costs, which are pipelines and terminal expenses, and we look at opportunities to organically grow into some of these markets and get around third-party costs.

So Gary's secondary costs provide us an opportunity to look at organic projects.

And again, we can't talk about those because we're still going through the gating process.

But for this year, the $1 billion of strategic capital, about 50% of that is for the logistics projects to address some of Gary's secondary costs.

And we expect that, that kind of thinking or that kind of strategic capital going forward would continue.

Paul, just more broadly on this.

We have talked about the fact that we're interested, from a strategic perspective, in integrating more assets that go into the refinery and moving product out of the refinery.

And that's not a short-term strategy.

That's a long-term strategy, along with the other things that we're doing: safety, reliability, and environmental focus, and then shareholder returns is the third component.

So I think the strategy that we've got in place today, certainly, we have line of sight to the next couple of years.

But it's a strategy that I believe works long-term.

It allows us to continue to increase the value of the business.

So we're very comfortable with it.

And again, Rich and Lane are both developing projects.

We scrub them hard, and then we'll just see which ones we want to proceed with going forward.

But the focus is clearly around the core business of refining and marketing and around ethanol.

Our next question is from Doug Leggate with Bank of America.

This is [ Clay ] on for Doug.

Earlier, you mentioned still strong export into Latin America.

And I'm guessing that's probably due to still load utilization in the region.

I'm just wondering if that's a sustainable trend or if you see that improving at any point this year?

Yes.

So I think some of it is certainly related to refinery utilization in the region and as mechanical availability has fallen off, it's opened the door for us to supply the market.

But going forward, in addition to that, we also see that there's some good demand growth trends that we're starting to see, particularly in Brazil, which had, had negative demand growth.

It looks like it's turned positive.

So I think even as refinery utilization improves, you'll see demand growth in the region, which should allow us to continue to see that as a good export market.

Okay.

Second question is just on the cash returns to shareholders.

They came in above guidance in this quarter, when guidance is obviously 75% of net income.

Just wondering what key considerations were in this quarter in regards to the buyback level?

Was it cash flow, balance sheet cash, operating outlook?

Any color would be appreciated, and I will leave it there.

Yes.

You're exactly right.

When we look at what our payout is going to be for the quarter, we do look at our expected discretionary cash flow that's going to be generated that particular quarter.

We also look at our excess cash balance that we may have in determining what we want to pay out for that particular quarter.

So for this quarter, we paid out a little over 200% of net income, but when you look at our cash flow, excluding the working capital benefit, it's about 75% of our cash flow.

And that's how we'll look at it going forward.

Our next question comes from Ed Westlake from Crédit Suisse.

Just wanted to return to 2 conversations.

One is the $1.1 billion of growth capital.

Appreciate you don't want to talk about specifics.

But do you think the top of the funnel of the opportunity set for that $1.1 billion is getting larger as the U.S. producers get back to work?

Trying to think about how many years you have of projects identified to drive that self-help component of total shareholder return?

So Ed, this is Lane.

So when you think about our capital budget, our talking numbers is we nominally spend about $2.5 billion on CapEx a year, $1.5 billion of which is turnarounds, sustaining capital.

It's really about $1 billion.

So you can think about, I would say a long-term run rate of $1 billion, and that's kind of what we think that we naturally, with our assets can manage well and do sort of with our strategic outlook.

We absolutely believe and already, I'd say most particularly Rich's stuff is largely in the area of expanding logistics, connectivity, our refining operation.

And trying to run this for the oil shale play.

To the extent it will get bigger, we would certainly have a conversation and talk about whether we see a larger opportunity in that.

But really, our message is about $1 billion a year we're going to try to manage the business around.

Okay.

And then I don't want to waste too many on policy, but I guess I should ask if we're going to have corporate tax plan coming out tomorrow.

Not so much on corporate taxation, but on BAT, whether you've heard, whether the oil industry would be exempt or what the latest is what you're hearing on the BAT, border adjustment tax?

Yes.

Hang on a second here.

This is Jason again.

Yes, we think the livelihood of the BAT being included in the tax reform's declined substantially.

It's definitely one of the more controversial aspects of tax reform, and with the difficulty Republicans had with health care, we don't see them wanting to take on another fight or create another fight within the party.

And the BAT clearly splits the business community.

You have people for it and against it.

So for that reason, we think that's probably one of the first things they'll move away from as they try to move forward and get a win on tax reform.

Our next question comes from Brad Heffern with RBC Capital Markets.

Gary, I was wondering if we can follow up a little bit on the earlier OPEC conversation.

I was wondering specifically about some of the Latin American heavy grades, if you've seen any sort of decline in availability?

I know in the first quarter, there were concerns about Maya availability.

Has that continued?

And maybe if you've seen Venezuela volumes declining?

So what we've seen I guess overall is it does look like Venezuela's production is falling off some, but their internal consumption for their refineries has kind of fallen off almost at a commensurate amount.

So exports from Venezuela have been fairly constant actually.

And then we're seeing actually a growth in Brazilian production, so we're seeing more Brazilian barrels on the market.

And then, on the Maya question, we've continued to receive our contract volumes from Mexico fairly consistently.

Okay.

Got it.

And then, maybe sticking with you, Gary or maybe Lashway.

On the Diamond Pipeline, obviously, we know the cost of the project.

But I was wondering if you could give any color as to how it's expected to affect the laid-in crude cost at Memphis or any sort of EBITDA contribution for VLO that you can provide?

Yes.

So the way we view it, I mean, without giving too much specifics.

Today, we're at a U.S. Gulf Coast plus cap-line tariff, you get a laid-in cost for Memphis' crude.

And we believe that with the Diamond Pipeline, we'll be at a U.S. Gulf Coast minus.

And so it'll be a significant change for the Memphis refinery.

It's kind of hard to give EBITDA estimates because you're kind of doing a market read in order to be able to get that, but we believe it will have a significant impact on Memphis.

Our next question is from Roger Read with Wells Fargo.

I guess, maybe going back to some of the questions earlier on the light, heavy diff and where the narrowness of the differential incentivize going back to a light barrel.

Thinking a little more forward and using maybe a consensus expectation for light production in the U.S., Gary, where do you see your ability to run light barrels if the differentials are favorable?

Is that a 100,000 or 300,000 or potentially, much higher than that if the differentials are favorable kind of number?

Yes.

So we believe our capacity to process the light sweet crude is about 1.4 million barrels a day.

So if you look at our investor relations presentation, there's a pretty good slide there showing our ability to swing between grades.

But overall, our total processing capacity is about 1.4 million barrels a day of light sweet capacity in the system.

And over the past year, you've run closer to which level?

Well, I'm not sure on the volume.

Do you know, Lane?

I think we've been more like 1.1 million, or 1 million, today.

If you look at historically where we were, that was probably about the case.

Since the last time we had really compelling economics to run light crude, we finished both of these topper projects, at Houston and in Corpus.

So we are in a position to run more even than we did last time.

So...

And would we need to see substantially wider light differentials?

And I'm kind of thinking LLS against Brent right now, is that the right marker?

Or should we think more of a -- it's an Eagle Ford or a Midland barrel at the Gulf Coast?

Yes.

So the rule of thumb we always use is that the medium sours need to be discounted by 5% to your light sweet alternative.

So that's not 5% discounted to Brent.

That would be a 5% discounted to whatever you're paying for Eagle Ford, and that's why last week, with where the medium sours were priced in the Gulf, our light sweet alternative favored going ahead and running light sweet.

And then, my last question, just an accounting question.

With the break out of VLP, we saw a change in year-over-year refining margins.

I think it's fairly straightforward.

But we also saw a decline in reported OpEx of about $0.10.

And I was wondering, is that tied to VLP or is that something else that's going on?

No, that is tied to VLP.

Our next question comes from Paul Sankey with Wolfe Research.

Can I first ask just a relatively short-term question, which is just about your crude imports and how those are shifting with seemingly not much impact from OPEC cuts.

I was just wondering if you can confirm that.

Anything that you could add on Venezuela and Mexico would be interesting, would be part one.

And then, to help you give you some time to think.

Joe, there was a mention there of a long-term bullish view on octane.

I was just wondering, how else you're thinking long-term about strategy, there's a kind of a peak oil demand argument that's very widespread right now.

Could you address really what you think of the long-term challenges and opportunities are for Valero in terms of how the market's shifting?

I guess I'll start with the crude question.

Really, the imports we're getting from Venezuela and from Mexico have been fairly flat.

We're not seeing much of a change there.

The big change really, on the medium sours, we've shifted a little bit.

We've seen more of an impact from both Saudi Arabia and Kuwait on the medium sour barrels we import from there.

And we backfilled those with some additional South American grades and Canadian grades.

And then, recently, over the last few weeks, we have actually started at one of our refineries to maximize some light sweet and replaced some of the medium sour we were importing there.

So Paul, on the strategy, and I mentioned it earlier.

I think the things that we're doing today, and they're very much focused on making us the best refining and marketing operation out there, and I believe that based on the independent surveys, that we really are the best.

But we continue to raise the bar for ourselves and try to drive it forward.

Again, that's not a short-term activity.

That is a long-term activity that we'll continue to do going forward.

Now if you think long-term about the markets, okay, and the demand for our products more specifically, you say, well, is U.S. demand going to continue to grow going forward?

I think our forecast would be that in the next 5 to 10 years, you might see a slight decline in gasoline demand in the U.S. Diesel will be determined by economic activity.

And so we'll just see how that goes.

But as Gary mentioned earlier, we are seeing decent diesel demand and a lot of that is being driven by the increase in activity that we've got in the E&P side of the business.

If you think longer term and you think about where demand's going to grow, everything we read is that, globally, you're going to have increased demand for all of our products.

And so our focus will go beyond the U.S. borders, and we'll take a look at opportunities to increase our market presence in different international markets.

And one of the things that Rich and his team are focused on are establishing a footprint in some of those market so that we have better access to them on a ratable basis.

So I don't think you should expect us to shift the strategy materially going forward.

Clearly, midstream growth is something we're focused on, continuing to improve our refining and our renewables operation are something we're focused on.

And then, we've talked in the past about the possibility to take some of the streams that we're producing today and high grade them by legging into the petrochemical business.

That's something that's probably a little bit longer term, but it is something that we're actively looking at these days and trying to figure out what is a way for us to enter that type of business, boiling the frog rather than diving in head first and see if we can't create another earning stream for the company.

Understood, Joe.

I mean one of the obvious responses to potential threats is ongoing operational improvements you've talked about.

How much more do you think you can do in terms of the utilization, which we've seen steadily rising for you guys and the operational costs, how much further do you think you can drive those down?

And I'll leave it there.

Yes.

Paul, I'll let Lane talk about that a little bit.

Paul, as Joe alluded to, I mean, using [ Fahlman metrics ], we are sort of in our own space with respect to availability.

But we continue to try to get better because when we look at our entire portfolio, and not all of our assets are first quartile mechanical availability whereas many of them are.

We can always work on the ones that aren't.

And we have great programs to get us in that area.

In terms of cost, the real cost focus is what was talked about earlier, that's in our effort to reduce secondary costs.

And Gary talked about it, it's through commercial efforts and negotiate -- use our size to negotiate better and then let Rich figure out places where we can build assets that will directly allow us to essentially charge ourself with the cost of that and ultimately move those into droppable assets under the MLP.

Our next question comes from Blake Fernandez with Howard Weil.

A question for you, I think, probably for Mike on the tax rate.

It just seems like the past few quarters, it's continuously come in below kind of expectations.

I know you gave a guidance for 1Q, but I'm just trying to get a sense of maybe, I guess, the Québec piece of it probably feels more sustainable.

So any thoughts around that continuing to trend lower than what we've seen historically?

I guess I would -- how I would characterize that is we do have a few audits that are underway.

And that we don't know the exact timing on when those will be settled.

So here, this past quarter, we did settle a couple of our state audits favorably, which resulted in a reversal of some reserves, which then lowered the tax rate.

So I think our 30% number is a good number, unless we have some of these other events occur that allows us to lower the rate.

Okay, fair enough.

The second question is on the CapEx budget.

I know you kind of tackled the growth piece of it, but mine is on the sustaining capital part.

$1.6 billion.

I know that includes some Tier 3 compliance.

And I guess, I'm just wondering, as you kind of get that -- get through that this year, is there an opportunity for that to move lower into the future?

Or should we just be thinking of always kind of some type of compliance that's going to land in there, so it's really the $1.6 billion is probably a good number go forward?

So Blake, this is Lane.

I answer this in a couple of ways.

One is, I would say our -- we believe, and the guidance we've given, it's more of about $1.5 billion, of which, I would say, $1.2 billion to $1.3 billion is like truly sustaining capital.

Somewhere around $200 million or $300 million is what we think, normally is sort of regulatory spend.

It's not -- we sort of put into sustaining capital, but it's not like we're -- we're not rebuilding our assets or maintaining them.

It's something that having to do due to regulatory things.

We're a little bit higher this time due largely to Tier 3. Our Tier 3 spend is about $500 million, of which much of it -- we'll continue to spend up until the time that we have to be in compliance, which is January 1, 2020.

And so -- and the bulk of it -- really, the bulk of that spend will be in '18 and '19.

Our next question comes from Ryan Todd with Deutsche Bank.

Maybe you've touched on this a couple of times, maybe you want to follow-up on midstream growth opportunities.

Can you characterize a little bit the environment for, I guess, for growth opportunity and returns that you're seeing in that side of the business?

I think we've seen -- we've continued to see midstream operators take skinnier economics in order to compete in some regions.

And those are certainly in areas of kind of crude transport in some of the more popular growth basins, which I think you guys have generally avoided up to this point.

But as you think about your opportunities to deploy incremental capital, are you seeing downward pressure on returns in those types of businesses?

Any thoughts on dynamics in that part of the business would be great.

Ryan, let me just try to be sure we're clear.

So there's 2 things we're looking at, right?

One are the organic growth projects that we're doing.

I would say that we're not reducing our return thresholds on organic growth projects in the midstream part of the business.

And we kind of target a -- whether it be a drop or whether it be an organic growth project, we want to be at like a 12% pretax IRR regardless, okay?

Now if you're thinking in terms of M&A and the valuations that we're seeing on midstream assets, I'd say that they're pretty doggone aggressive, okay?

Rich, you want to...

Yes.

The bid-ask is very wide and depends on how aggressive people want to be on this.

I mean, we're always interested in and looking at these opportunities, given that they'd be strategic for Valero.

But today, we would say it's like, Joe said, it's very aggressive right now out there.

Yes.

I mean you saw, Ryan, you saw the recent deal that was done around Navigator.

And I don't know what the rate of return might be on that, but it was a very aggressive bid, it seemed.

So I guess we should expect you guys to be more focused on organic opportunities than inorganic, is that safe to say at least in the near term?

No, I wouldn't say that.

We're going to continue to do what we've done.

And Mike runs the M&A group here.

I mean, we're going to look at everything that's out there and try to make a determination.

In a perfect world, we'd find a bunch of assets where we can earn the types of returns we want to do the deal in VLP, and it would provide some kind of strategic synergy for Valero Energy also.

And we evaluate it looking at it both ways.

We have probably liberalized our strategy around VLP a little bit.

Historically, I've said that we look at the projects from Valero Energy's perspective first, and then decide if we can or can't do it at VLP.

And I would tell you that, that still is the primary motivation.

But we are looking at transactions now that would be somewhat more third-party, that the user of the asset would be a third-party, but it would bring value to Valero in some way.

So we're adjusting our perspective as we go.

Okay.

And then, maybe one more on payout.

And I realize that you've already touched on this a few times and it seems to come out every quarter.

But how do you think about your willingness to expand the balance sheet to return cash to shareholders, not just on a quarterly basis because I realize there's volatility around that and fourth and first quarters tend to be particularly weak, but your willingness to expand the balance sheet, outspend cash flow to buy back stock on an annual basis over the course of the year.

Is that something you're willing to do on a more sustainable basis?

And at what point is leverage a limiting factor?

Well, I don't think we would be -- we wouldn't lever up material amounts to increase our share buy -- or we wouldn't lever up at all to increase our share buybacks.

What we do look at, like I said, is we look at our discretionary cash flow that we expect to earn for the next quarter or the next couple year -- quarters.

We balance that with our capital requirements that we have and the other things that we have in place that we have to cover, debt service, whatever it is.

So we are forward-looking in that.

Our plan is not to hoard cash, however, and our plan is to remain competitive with our peers in payout, but we would not lever up our balance sheet to pay -- to return cash to shareholders.

Our next question comes from Fernando Valle with Citi.

My question was back on the organic expansion, and if you would consider growing in wholesale in Mexico following the liberalization in the market, and there's been a strong pull of gasoline of late, is that an area where you'd consider growing the wholesale business?

Yes.

Is it place where it -- given the succinct answer, is it a place where you're currently exploring opportunities for growth?

Have you made any advancements already?

Or still very early?

Well, okay.

I told Rich I didn't want him revealing secrets, right?

But, no obviously, we're looking at it.

I mean, we sell, Gary, you sell a lot of barrels into Mexico today, okay?

And I think everybody out there's going to be looking at Mexico as a growth opportunity.

And it's certainly one that is very logical for us to pursue.

And so I think you should assume that it's something that we plan to be involved in.

And not only Mexico, but other Latin American countries also.

Our next question comes from Sam Margolin with Cowen and Company.

So my first question is about crude exports from the U.S. They've been rising really rapidly and it's a little bit surprising that you would think as exports grow, the exporter would have to give up price but you don't really see it reflected in the markers that we have access to at least in the Gulf.

And so maybe these exporters have other commercial things underneath the marker.

But I just -- just generally, how do you see this playing out?

Most people believe that exports need to keep rising.

Is it eventually going to be reflected in the prices that are offered broadly to domestic refiners?

Or is it going to be something where the point of these exports is to keep those markers stable and basically domestic refiners wouldn't get the same advantage?

Yes, Sam, this is Gary.

I think you're going to continue to see volatility in the markets.

And so we see that the domestic markers get a little strong.

And then weaken again and you see imports come, and then you see exports rise again.

We've been very active exporting to our refiners in our system.

We've been exporting to Québec for quite a while now and in the first quarter, we exported volume to Pembroke and ran our first Permian Basin barrels in the Pembroke refinery and saw good economic advantage to do that.

Okay, that's helpful.

And then, I guess this is sort of a follow-up on Ryan's question about the capital structure.

Valero is making a lot of investments to address third-party costs and increase reliability and flexibility.

The effect is kind of to bring the range of earnings through the cycle higher on sort of a continuous basis.

So just to piggyback on kind of what Ryan was asking in a different way, does that allow the company to sort of support a little bit -- a little bit higher leverage?

The industry exited a period of deleveraging recently and I wonder if some of these investments that bring long-term advantages could lead to that maturing?

Or reversing even?

I'll let Mike speak to the levels of leverage, okay?

But I mean, very clearly, what we're trying to do is create higher lows and higher highs in our EPS.

And we really like to distinguish ourselves as a company that is able to produce earnings in challenging margin environments.

And I think we've demonstrated that over the last several quarters.

So the kind of the self-help focus is something that we're just going to maintain as part of what we do going forward.

Whether it allows us to achieve higher levels of leverage, I mean, Mike?

Well, I guess theoretically, you could say that would be the case.

However, we have provided a debt-to-cap range of 20% to 30% that we're comfortable with.

Maintaining our investment grade credit rating is very important to the company.

And a debt level within that range, we think we do that.

Our next question comes from Chi Chow with Tudor, Pickering, Holt.

Back on your feedstocks, can you talk about how does the running more light crude in your system impact yields, capture rates or anything else from a process standpoint?

And specifically, are you seeing any issues with the reported high API gravity of the incremental barrels coming out of the Delaware Basin?

Chi, it's Lane.

So it just really depends, certainly in our Mid-Continent refineries, there's times that we can see the lighter part of our refiners get constrained by these higher APIs.

And then, there's times where the gravity comes back in line and we're off of them.

We have a longer-term view that these crudes are getting lighter.

We look at the same data, I'm sure that you are, so we hit those constraints.

We don't -- now with that said, we don't hit those constraints quite as much in our Gulf Coast refineries because we have a little more flexibility in finding other feedstocks and crudes to blend with these things to make sure that we're always up against that constraint.

So it's a little easier to optimize around these lighter crudes than it is in the Mid-Continent.

I guess, and looking at the Gulf Coast results, your index -- the Valero index of the region was up, I think $2.35 a barrel year-over-year versus 1Q last year.

But the realized margin in the quarter was up only $0.35.

Was that shortfall in capture mainly due to the planned maintenance or was there something else going on there?

Chi, this is Gary.

I would tell you, the biggest impact we had was really on the heavy feedstocks we bring into the system compared to the Maya marker, that moved quite a bit.

So our heavy feedstocks were more expensive relative to the Maya marker.

And some of that was just Maya was much more competitive in the first quarter than what we either saw in the first quarter or what we had year-over-year.

Gary, but I think you said that you're not having problems on Maya delivery, but the pricing has tightened up, is that fair?

Well, so -- yes, the Maya pricing and deliveries were fine, but the other heavy sours that we're buying versus the Maya pricing was not as competitive in the first quarter as what we've seen previously.

Is that trend, do you think that will continue?

We saw that Pemex has tightened up the K factor on Maya for May.

(inaudible)

We see that come and go.

There's times where Mexican crude's very competitive and times where they kind of fall where they're not.

So that's why we kind of have a diversified strategy on pulling the South American grades and Canadian grades and it looks like it has come in some already and I would expect that to come in and continue to come in.

We now have a follow-up question from Paul Cheng with Barclays.

Any kind of rough estimate in terms of the opportunity cost loss in the first quarter due to the planned and unplanned outages?

Paul, this is Lane.

So our planned outages in the first quarter was a -- the opportunity cost was $231 million.

So as you've heard us talk, we've had -- it was a fairly heavy turnaround quarter.

In terms of unplanned outages, it was about $40 million.

All right.

And this is not just an expense, but also you're including the loss profit debt, the way how you guys calculate, right?

Gross profit and expense?

Yes, it includes expense.

Okay.

We have no further questions at this time.

I will now turn the call back over to John Locke for closing remarks.

Okay.

Thanks, everybody, for joining the call today.

Please contact me or the IR team if you have any additional questions.

Thank you.

And thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.