瓦萊羅能源 (VLO) 2019 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Valero Energy Corporation's First Quarter 2019 Earnings Conference Call.

(Operator Instructions) As a reminder, today's conference maybe recorded.

I'd now like to introduce your host for today's conference, Mr. Homer Bhullar.

Sir, please go ahead.

Good morning, everyone, and welcome to Valero Energy Corporation's First Quarter 2019 Earnings Conference Call.

With me today are Joe Gorder, our Chairman, President and Chief Executive Officer; Donna Titzman, our Executive Vice President and CFO; Lane Riggs, our Executive Vice President and COO; Jason Fraser, our Executive Vice President and General Counsel; and several other members of Valero's senior management team.

If you've 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 like to direct your attention to the forward-looking statement disclaimer contained in the press release.

In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws.

There are many factors that could cause actual results to differ from our expectations, including those we've described in our filings with the SEC.

Now I'll turn the call over to Joe for opening remarks.

Thanks, Homer, and good morning, everyone.

Our system's flexibility and the team's relentless focus on safety enabled us to deliver positive earnings and an otherwise weak margin environment during a period of heavy maintenance.

The first quarter presented us with tough market conditions.

Differentials on medium and heavy sour crude oils were compressed by a number of factors, including OPEC and Canadian crude production curtailments and Venezuelan sanctions.

We also started the year with gasoline inventories at record high levels and the gasoline crack at historic lows.

Despite this challenging backdrop, our premier assets and prior investments that have improved our feed stock and product flexibility enabled us to achieve positive earnings and operating cash flow.

We demonstrated the flexibility of our system by processing a record volume of 1.4 million barrels per day of North American sweet crude oil as well as a record amount of Canadian heavy crude in the quarter.

The Diamond Pipeline and Line 9B continued to provide cost advantaged Cushing and Canadian crudes to the Memphis and the Québec City refineries, respectively.

We also continued to maximize product exports into higher netback markets in Latin America.

Our investments that are expected to grow the earnings capability of the company continue to move forward.

The Houston alkylation unit and the Central Texas pipelines and terminals project remain on track to be operational in the second and third quarters, respectively.

The Pasadena terminal, St.

Charles alkylation unit, and Pembroke cogeneration unit are all on track to be complete in 2020.

The Diamond Green Diesel expansion and the Port Arthur Coker are expected to be complete late 2021 and 2022, respectively.

Turning to capital allocation.

We continued to adhere to our disciplined framework.

Our annual CapEx for both 2019 and 2020 remains at approximately $2.5 billion and you should expect incremental discretionary cash flow to continue to compete with other discretionary uses, including cash returns, growth investments and M&A.

With respect to cash returns to stockholders, we paid out 55% of adjusted net cash provided by operating activities for the quarter and we continue to target an annual payout ratio between 40% to 50%.

Turning to financing activities.

We completed a $1 billion public debt offering in March at a coupon of 4% with the proceeds being used primarily to redeem $850 million of 6 1/8% senior notes, due in 2020.

We also funded the buy-in of VLP with $950 million of cash on hand in the first quarter.

Now, looking ahead, we remain constructive for the rest of the year.

Product fundamentals continue to improve with gasoline and distillate inventories now below their 5-year averages.

Additionally, product shortages, particularly in Central and South America, should continue to support robust exports.

The impending IMO 2020 fuel oil spec should also lead to higher gasoline and distillate cracks along with improvement in the medium and heavy sour crude differentials.

Our advantaged footprint with its flexibility to process a wide range of feedstocks and reliably supply quality fuels to consumers here and abroad, coupled with a relentless focus on operations excellence and a demonstrated commitment to stockholders continues to position Valero well for any market environment.

So with that, Homer, I'll hand the call back to you.

Thanks, Joe.

For the first quarter of 2019, net income attributable to Valero stockholders was $141 million or $0.34 per share compared to $469 million or $1.09 per share in the first quarter of 2018.

First quarter 2018 adjusted net income attributable to Valero stockholders was $431 million or $1 per share.

For reconciliations of actual to adjusted amounts, please refer to the financial tables that the company just released.

Operating income for the refining segment in the first quarter of 2019 was $479 million compared to $811 million for the first quarter of 2018.

The decrease from first quarter 2018 was mainly attributed to significantly weaker gasoline margins and narrower medium and heavy sour crude differentials.

Refining throughput volume averaged 2.9 million barrels per day, which was lower than the first quarter of 2018, primarily due to maintenance activities.

Throughput capacity utilization was 91% in the first quarter of 2019.

Refining cash operating expenses of $4.15 per barrel were $0.32 per barrel higher than the first quarter of 2018, mostly due to maintenance related expenses and lower throughput in the first quarter of 2019.

The ethanol segment generated $3 million of operating income in the first quarter of 2019 compared to $45 million in the first quarter of 2018.

The decrease from first quarter of 2018 was primarily due to lower ethanol prices.

Ethanol production volumes averaged 4.2 million gallons per day in the first quarter of 2019, an increase of 104,000 gallons per day versus the first quarter of 2018, primarily due to added production from the 3 ethanol plants acquired in November 2018.

As noted in the earnings release, we are reporting the renewable diesel segment beginning this quarter.

The segment generated $49 million of operating income in the first quarter of 2019 compared to $195 million in the first quarter of 2018.

Excluding the adjustment shown in the accompanying earnings release tables related to the 2017 Blender's Tax Credit recorded in early 2018, first quarter 2018 adjusted operating income was $35 million.

Renewable diesel sales volumes averaged 790,000 gallons per day in the first quarter of 2019, an increase of 419,000 gallons per day versus the first quarter of 2018.

The adjusted operating income and sales volumes increased from the first quarter of 2018 primarily due to the expansion of the Diamond Green Diesel plant in the third quarter of 2018.

For the first quarter of 2019, general and administrative expenses were $209 million and net interest expense was $112 million.

Depreciation and amortization expense was $551 million and income tax expense was $51 million in the first quarter of 2019.

The effective tax rate was 23%.

With respect to our balance sheet at quarter end, total debt was $10.1 billion, and cash and cash equivalents were $2.8 billion.

Valero's debt-to-capitalization ratio after giving effect to the redemption of the [$850 million] (corrected by the company after the call) senior notes occurring today was 26%.

At the end of March, we had $5.4 billion of available liquidity, excluding cash.

We generated $877 million of net cash from operating activities in the first quarter.

Excluding the favorable impact from a working capital increase of approximately $130 million, net cash generated was $747 million.

With regard to investing activities, we made $726 million of capital investments in the first quarter of 2019, of which $453 million was for sustaining the business, including costs for turnarounds, catalysts and regulatory compliance.

Moving to financing activities.

We returned $411 million to our stockholders in the first quarter.

$375 million was paid as dividends with the balance used to purchase 414,000 shares of Valero's common stock.

The total payout ratio was 55% of adjusted net cash provided by operating activities.

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

We continue to expect annual capital investments for both 2019 and 2020 to be approximately $2.5 billion, with approximately 60% allocated to sustaining the business and approximately 40% to growth.

Included in that amount are 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 1.72 million to 1.77 million barrels per day; U.S. Mid-Continent at 425,000 to 445,000 barrels per day; U.S. West Coast at 220,000 to 240,000 barrels per day; and North Atlantic at 450,000 to 470,000 barrels per day.

We expect refining cash operating expenses in the second quarter to be approximately $4 per barrel.

Our ethanol segment is expected to produce a total of 4.7 million gallons per day in the second quarter.

Operating expenses should average $0.38 per gallon, which includes $0.05 per gallon for noncash costs such as depreciation and amortization.

With respect to the renewable diesel segment, we expect sales volume to be 750,000 gallons per day in 2019.

Operating expenses in 2019 should be $0.45 per gallon, which includes $0.16 per gallon for noncash costs such as depreciation and amortization.

For 2019, we continue to expect G&A expenses, excluding corporate depreciation, to be approximately $840 million.

The annual effective tax rate is still estimated at 23%.

For the second quarter, net interest expense should be about $115 million and total depreciation and amortization expense should be approximately $560 million.

Lastly, we expect RINs expense for the year to be between $300 million and $400 million, which is approximately $100 million lower than the previous guidance, primarily due to lower RINs prices.

That concludes our opening remarks.

(Operator Instructions)

(Operator Instructions) Our first question comes from the line of Douglas Leggate with Bank of America Merrill Lynch.

This is Kalei on for Doug.

I've got one and a follow-up.

I really want to talk about the gasoline rally recently.

When you kind of deconstruct the recent move higher, seasonality and constraints played a big role and both of these are nondiscretionary.

And what I think the market is worried about and why the rally is stalled is that the potential for industry utilization to ramp up and kill the crack.

So what I'm hoping that you can speak to and help us understand are maybe some of the factors that could keep this from happening, in particular, I'm looking at the inland spreads and the quality spreads on the water and because of this, I think, I have a hard time believing that there is the incentive to max run.

And maybe we got a coincidence on your fourth quarter where the throughput was within guidance and not ahead, which has been the case recently.

And I guess, if this point is true then maybe this rally has a bit more durability than people think.

Gary, do you want to?

Sure.

Well, I can tell you it's a lot more fun talking about gasoline in April than it was in January, and we certainly feel good about the gasoline market.

When we talked in January, as you mentioned, we were looking at a year-over-year overhang of 18 million barrels of gasoline.

Since that time, since February, we've seen refinery utilization average 87%.

Now gasoline inventory is 11 million barrels below where it was last year at this time.

In addition to that, you are heading into a portion of the year where we would expect seasonal demand trends to follow where we would see a pickup in demand as you head into driving season.

In addition to that, you should see yield fall off some as we are transitioning to summer grade gasoline that have less butane in the pool.

So I think through driving seasonally we feel very good about the gasoline situation as you get into the fourth quarter, we would expect that you will see some normal seasonal patterns there as well when you begin to build inventory.

I think this year we do feel like there is an opportunity on gasoline that we haven't seen before because of the IMO 2020 bunker spec change.

Our view is that low-sulfur feedstocks that currently go into FCCs will be priced against their low-sulfur fuel oil blend value alternative and that ability to swing the low sulfur feedstock out of the FCCs and into the low sulfur fuel market will be supportive to the cracks longer-term as it results in lower FCC utilization and lower gasoline production.

But when it comes to gasoline or all aspects of the business, we manage for the long term certainly a lot of moving parts here, but we feel like we are very well positioned.

Global demand remains healthy.

Valero is the lowest cost producer and we're strategically located to export product globally, especially to the markets in Central and South America.

So we feel pretty good about it.

Got it.

And just as a follow-up.

Looking at the screen today gasoline cracks and diesel cracks seem to have finally converged.

What does mean for your yield skew this summer.

Do you still have the signals and remain in max diesel mode? .

Okay.

We're swinging -- we have swung the heavy cat naphtha into gasoline.

Our next question comes from the line of Prashant Rao with Citigroup.

I guess I wanted to talk about the crude side.

Joe, you mentioned a strong advantage of Canadian crudes on the heavy side and here we're also seeing some Maya starting to discount a bit more So, 1 of 2 parts to this question, one, I wanted to know kind of a check on how much Canadian you were running in the quarter and what your thoughts are going forward; and then two, any thoughts on the recent sort of reversion and discounting on Maya and how that might play out as we go through the year?

Yes, Prashant, good question.

Gary, do you and Lane want to?

Yes.

We did just under 190,000 a day of heavy Canadian, 49,000 of that was Crude by Rail that we delivered to Port Arthur with the remainder being pipeline delivered barrels.

We would expect those volumes to continue in that range, actually ramp up a little bit especially with the Venezuelan barrels off of the market.

On the Maya formula, there is not a lot of help in terms of additional medium and heavy sour supply coming onto the market, but where we see the opportunity for the quality diffs to improve is really heavy high-sulfur fuel oil moving weaker and we came off the highs where we are trading at 96% of Brent.

Earlier this week, we were down to 89% of Brent and our expectation is as you move closer to that IMO 2020 fuel oil spec change that high sulfur fuel oil would continue to get weaker and that will help the quality discounts move weaker as well.

All right.

I appreciate that.

And just a follow-up.

I guess switching over -- staying on feedstock side, but maybe switching over to Diamond Green Diesel.

Looking at what kind of underlying profitability [indiscernible] looks like feedstock costs there you're being able to get nominally profitable even before the low-sulfur fuel -- sorry, low-carbon fuel credit and before the Blender's credit as well.

I kind of just want to get a sense of your strategy how things have developed in terms of diversity of feedstock sourcing, how that net -- what it takes to build up that network and sort of progress along those lines.

It looks like there has been some solid progress over the last, obviously, this last several years, but now that we're disclosing it as a separate segment kind of wanted to think about how we should look at that longer term, both this year and further on?

Okay.

Well, this is Martin.

We've provided volume guidance today on an annual basis.

We're also going to be publishing the DGD margin indicator on our website.

We've been running at these higher rates now for 6 months.

Feedstock is flowing fine.

Our partnership with Darling Ingredients gives us an advantage in that space.

They process about 10% of the world's meat byproducts.

So we feel good about being able to source the feedstock and looking forward to continued growth and expansion and we're looking at this expansion to -- that Joe mentioned, an additional 400 million gallons a year that will come on in late 2021.

And in terms of sort of beyond just the soybean indicator that you've given us, sort of -- I was wondering if you can give it how diversified we could get?

If you're able to share anything, I know that we've heard in other parts of the globe there is a lot of ingenuity in terms of what can be used as feedstock source so I was just curious along maybe those lines, if you're -- how diversified you could get?

We're still running -- like we said in the past, we're running about 1/3 corn oil, 1/3 used cooking oil and then 1/3 beef tallow type, beef tallow or choice white grease.

So same mix as we've been running historically.

Our next question comes from the line of Manav Gupta with Crédit Suisse.

Joe, you talked about IMO 2020 in your opening comments.

Yesterday, there was a very positive development on that front.

Ben Hawkins, the Deputy of Commercial Regulation and Standards at the U.S. Gulf Coast Guard said that the coast guard is getting ready to enforce the new fuel specifications and expects the industry to comply.

He went on to say that there is no possibility of slow rolling and he hopes for a harmonized global approach to enforcement.

The way I see it, it's a big change from the stance some government officials were taking last October when they were talking about a phased implementation and possible delays.

So I'm trying to understand do believe the government is now more on board and the implementation program and so probability of success for rollout is materially higher than it was in October?

No.

That's a very good question.

I'll let about Jason talk about some of the specifics.

That's right.

Yes.

We do agree with everything you said.

We continue to expect IMO 2020 to be implemented and enforced on schedule as most recently indicated by those comments by the Coast Guard official you mentioned.

It seems like things have quieted down with the administration and these EIA forecasts that have come out over last several months, which didn't show a dramatic jump in prices.

That's kind of calmed the waters.

Our next question comes from the line of Blake Fernandez with Simmons Energy.

I have 2 questions for you.

One probably for Gary on the supply side obviously there is a lot of discussion with Iranian waivers and potential for OPEC to ramp back up.

I just didn't know if you had any comments on supply dynamics and how you see that may impact your inputs and maybe some of the heavy dynamics underway?

Yes.

So far, we don't have any indication of an additional OPEC barrels making their way to the market.

We don't have any coming into our system as of yet.

And we will wait to kind of hear.

And I think they're meeting in early May to determine whether they're going to ramp up production.

Okay.

Second question is on Diamond Green.

I believe there was a bill submitted to the house on a potential 2-year extension for the BTC.

And I didn't know if you had any updates or thoughts there on the lay of the land there?

This is Jason.

Of course, we support the extension of the Blender's Tax Credit.

We did see that bill introduced in the house.

There is also one that's been introduced in the senate by Grassley and Wyden, and of course this is one of Chairman Grassley's main initiatives and one of his programs he's most -- he'll most aggressively push for.

So we are hopeful that something will happen this year.

Of course, with changeover of leadership in the house the Democrats have to sort through -- the Democratic leadership, sort through their priorities for what they want to move this year, but we're hopeful something happens.

And it is an issue that has bipartisan support, which is very helpful with a split legislature like we have.

Our next question comes from Benny Wong with Morgan Stanley.

I just want to touch upon -- follow up the question from Prashant about the widening Maya.

I think we've seen widening sour differentials across the regions.

I just wanted to get your perspective what's driving this?

Is it just really the weaker fuel oil prices?

Or are you seeing other factors like coker turnarounds?

Or are you seeing simple refineries switching their crude slate today ahead of IMO 2020?

I think most of what we're seeing today is driven by several components in the formula.

We mentioned the high-sulfur fuel oil getting weaker.

The Brent TI arb widening also helps the Maya differential get weaker, and then the final thing is Midland WTS is still part of the Maya formula.

So as WTS gets weaker, it helps as well.

I think those are the key drivers.

And certainly, high-sulfur fuel oil should continue to get weaker and help the Maya spread widen out.

This is Lane.

I will add further color to that point.

So right now medium sour, you were asking about that as well, it's still a little bit out of the market with respect to its value relative to sweet and heavy, those are the 2 most economic crudes.

So there is still sort of an arbitrage that exists out there in the marketplace between medium and then that 3% discount you should see somewhat get some parity in all that when it all gets balanced again in the Atlantic Basin.

Great.

And my follow-up question is just a little bit extension on Blake's question.

Just wanted to get a temperature check on D.C. It seems like from where I'm sitting the EPA is a little bit more moderated with headlines of them signaling they're going to issue less small refinery waivers and potentially walking back the proposal to freeze the CAFE standards.

Just wondering how your discussions with them has changed and if they're kind of shifting their focus or their approach a little differently going forward?

This is Jason, again.

We haven't seen them really shift their approach.

They're definitely under pressure -- probably under constant pressure from the ethanol side to -- on the smaller refinery waivers.

That's -- they have been for years, but they seem to understand the responsibility to grant small refinery exemptions is part of the statute, it's been reaffirmed by Congress and the court several times.

There have been several appellate cases on the issue.

And so we're encouraged by Administrator Wheeler's comments during his confirmation hearing that he planned to follow the law, he understood how those programs are supposed to work.

And we hope that agency continues back and they have in the past, which is to grant the waivers where they see them to be appropriate.

Our next question comes from the line of Roger Read with Wells Fargo.

I guess, if we could go back a little bit.

I think Gary you mentioned earlier that you weren't running max diesel.

Obviously, diesel cracks are a little below what they have been, I mean, not weak by any standard.

But I was just wondering if you could dive in a little bit what you're seeing in terms of diesel or distillate demand, both here in the U.S. and then in terms of export demand?

Sure.

I think we had a little mild winter in the North Atlantic Basin than what we typically have, which hurt demand a little bit.

That was certainly offset by lower production with the lower refinery utilization.

I think moving forward certainly you're entering a time of the year where we typically see a little softer distillate demand as you don't have the heating oil demand.

I think where this year is different is with the market structure and the strong carry in the market, I think the prompt market will remain supported because as it weakens, the barrels will be bid into storage.

And so I think you'll see diesel continue to be supportive in the short term and then you get the demand kick later in the year as we approach the IMO 2020 date.

And when do -- just speaking of that on the IMO front, when do you think we really start to see it in the forward curve.

I mean, you mentioned earlier, I think, everybody would agree with you, high-sulfur fuel oil discounts puts pressure on the sweet-sour diff, but when do you think that shows up in the forward curve.

Because one of the questions we've been getting from investors is "Are we buying this from IMO?

When do I believe that IMO is actually real?

In a sense I need to see it in the curve before I want to invest wholeheartedly on that front."

So what we understand is really the last loads of high-sulfur fuel oil that head to the far east for shipping probably occurs in late September.

So you start to see an impact on the high-sulfur fuel oil market sometime in that late September, early October region.

And then on the distillate side, I think, it's probably a November, December-type time frame before you start to see an impact on the diesel side.

Okay.

That's helpful.

And I guess that's my 2 questions and I won't take up the slot formerly used by an analyst who is on break right now.

Our next question comes from Peter Low with Redburn.

The first was just on the balance sheet.

Gearing is getting towards the top end of your guided range.

I just want to know how comfortable are you with it at current?

And how you expect to prioritize degearing versus buybacks over the coming quarters?

The second was on the projects due for completion this year, particularly the Houston alkylation unit.

Can you give us any color on the extent to which you expect this to impact capture rates and earnings?

Okay.

So Donna, do you want to?

Yes, do you want to?

So.

Yes.

No.

We're very comfortable where we are on the balance sheet in the context of leverage.

We designed that target 20% to 30% to give us plenty of flexibility for growing our business and taking advantage of acquisitions as they come along.

So we're very comfortable where we are at.

We're at 27%, but we're paying some debt off today.

So that's going to bring us back down to 26%.

I'm sorry, what was the other...

Yes.

The other -- he was dovetailing it and -- Peter you tell me if this is wrong, but it sounded like you were dovetailing it into the share repurchases.

And we've been pretty clear all along that we weren't going to leverage the balance sheet to do share repurchases.

And I think that's why you saw the repurchases slightly less in the first quarter.

We used the adjusted free cash flow metric as our target and that's what we're going to live with.

We're running the business for the long term.

And we feel that all of the components that we have identified, all of the goals we've set for ourselves are relevant and we don't want to deviate from that.

So as cash flow picks up, I think, you should expect that flywheel of share repurchase to increase also, but I wouldn't tie the two directly together, the debt-to-cap and the share repurchase quantity.

The final question was Houston alky.

Yes.

And the second question.

Yes.

So on the final question on the Houston alky, it's on to schedule to start-up here in the second quarter specifically, at the end of May, maybe give it sort of June 1 start up.

So what does that mean in terms of our results, that means you're going to have 1/3 of the benefit in the second quarter and then you will have the full benefit in the third and fourth quarters.

And it will absolutely go directly to capture rate.

Some of our projects, like toppers don't go directly to improving our capture rate, we get additional volume, but this will be because you're taking NGLs and getting all the way sort of to a premium gasoline component value.

So that should show up in our capture rates in the Gulf Coast.

Our next question comes from the Sam Margolin with Wolfe Research.

I have a supply question too.

The last quarter's call there was some probing about the Venezuela sanctions and how that might affect you, but it looks like there is lot of offset supply coming on from Brazil.

Brazil production from 2018 was differed.

It looks like it's coming on now.

Is that suitable substitute for you?

Are you looking at that at all?

Or does the spec not really work?

I'm just wondering like what are the developments in your, sort of, Atlantic Basin, Latin America crude supply story since the last quarter's call and the Venezuela sanctions?

Yes.

So I will tell you since the Venezuela sanctions, about 1/3 of the barrels we're getting from Venezuela have been replaced by running incremental domestic light sweet, about 1/3 of it is incremental heavy Canadian and then 1/3 of it is just opportunistic cargoes and some of that production that you're talking about from Brazil fits into that opportunistic cargo.

We have definitely seen more volumes of Brazilian crude coming into the Gulf and also our West Coast.

Okay.

And then this has been a recurring theme now for a while that your Mid-Con segment is really starting to break out and capture versus historical rates are -- is up a lot.

It obviously has a lot to do with Diamond Pipeline.

Other operators outside of the Diamond Partnership talk about Diamond a lot, it's an interesting strategic piece for other infrastructure that wants to loop into it or connect it to some other ideas.

Are you guys still in sort of a strategic dynamic review process with Diamond?

Or are you very satisfied with the role its playing in Valero today?

And you don't necessarily want to include it in other operators' plans for trying to get crude to the Eastern Gulf?

Well, you guys, there's 2 pieces to that question, right.

There's the -- I mean, the conversation around strategic use of the pipeline but, I mean, our initial emphasis for the pipeline was to assure crude supply, and a particular crude supply, into the Memphis refinery.

You guys want to talk about that at all.

Yes.

So that's gone extremely well, and we saw a stronger contribution of Diamond Pipeline in the first quarter of '19 than we did in the first quarter of '18 and some of that is the wider Brent TI arb.

The other change in our system was the Sunrise Pipeline, which came online in the fourth quarter of '18.

That not only improved our ability to get Midland barrels to Ardmore and McKee but we are now able to get Midland barrels to Memphis, and we saw -- we certainly saw an uplift from that in the first quarter.

And I'll let Rich handle the second part.

Sure.

So it was in January, an open season on the cap line was announced and part of that reversal open season was to tie the Diamond into the Capline.

So, Plains got an open season out there that will conclude next week on the -- I think it's Monday the 29th and so they'll see whether or not there is enough interest to expand the Diamond pipeline which would then tie in to a Capline reversal, so that would be the strategic part of expanding the pipeline to get Cushing barrels to the Gulf Coast.

So, Sam, I mean from our perspective the key is, as Gary stated, is just to be sure that we retain our ability to ship the volumes that we need into the Memphis refinery and then from -- as an investor in the pipeline, I think we'll look at the options associated with a possible expansion.

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

Maybe for Gary.

I was just wondering if you can give thoughts on West Coast product supply.

Obviously, there's been a lot of outages.

We've seen some larger import activity on the gasoline side and obviously if the West Coast gets behind it can struggle to catch up during driving season.

So any thoughts on how that plays out for the year?

Yes.

So I think what we've always talked the West Coast is a little long refining capacity, but when you have maintenance activities it tightens up the market and we've seen maintenance activities on the West Coast and inventories are low heading into gasoline season, which, I think, bodes well to a fairly strong gasoline season on the West Coast.

Okay.

And then looking at the Gulf Coast crude runs this quarter, you guys ran in the most sweet you've ever run, you ran the least medium.

I'm just curious if that's sort of the most barbell-ed the system can get?

Or is there still room for more light and less medium if the spreads are telling you that?

This is Lane.

We were clearly in that mode, I sort of alluded to that earlier, maximum.

We had some turnaround activity.

Our St.

Charles refinery was in turnaround.

When you -- as you see us come out into the second and third quarters, as our refineries come out of all this, you could see us have additional capacity where we're -- have this strategy.

So we have some more room to do that.

Our next question comes from the line of Neil Mehta with Goldman Sachs.

So a couple of questions.

So I guess, the first is, you just have a number of organic projects that have come online over the course of the last year.

So just trying to think about what the earnings power would have been in the first quarter independent of some of those growth projects so we can isolate the growth on a commodity-agnostic basis.

Can you just talk about if this earnings power structurally improved relative to a year ago as some of those projects have come online?

You guys want to talk about the impact of the projects.

The only -- I'm trying to think.

The only project we really had come on that's different than the last few quarters maybe was...

Sunrise.

Oh, well, obviously, okay.

I was thinking refinery, we only had the Wilmington co-gen.

Yes.

So the Sunrise definitely had a material impact on the first quarter results for us as you were able to capture that Midland to Cushing differential on the pipeline space we have on Sunrise.

Neil, there has been a host of things though, right?

I mean, we've got the Diamond Green Diesel expansion, that we're seeing the benefits of also.

And you have seen it multiple times, but in the deck we got the fact that we believe that the projects that were completed produced another $340 million of incremental EBITDA.

So if you compare year-over-year and how we performed in kind of a similar margin environment, I think, you would find that the projects have contributed significantly to bettering the capability of the company.

But those were pipeline projects and then the Diamond Green Diesel expansion.

Right.

Yes.

That's helpful.

And just follow-up question just on the cash balances.

You guys had around $2.8 billion.

Is it fair -- is the long-term target still to move towards $2 billion, that's still the right level?

I know you were running substantially higher than that before, but how do we think about that optimal cash balance number?

Yes.

So if you look at the $2.8 billion, you'll -- we issued some debt towards the end of March, $1 billion, that was slated to refinance a maturity that is in early 2020.

Today, we paid -- we redeemed that -- those notes today.

So if you kind of pro forma the cash, which was really closer to $1.9 billion at the end of March.

So Neil, we think that's still a reasonable target.

And we'll test around it both directions and just see if it holds up longer term.

And then the other thing to keep in mind is that we bought back VLP during the quarter and that was $950 million of cash.

Correct.

So there will be times when I think you'll see the cash balance increase if we're looking at something like that.

But otherwise, the $2 billion is still probably a good point of reference for you guys to use in your modeling.

Our next question comes from the line of Phil Gresh with JPMorgan.

The first question with Diamond Green Diesel here as a new segment.

You gave us some color on throughput and then cost.

Your JV partner, I think, has given a view of EBITDA guidance of $1.25 to per $1.40 per gallon, I believe.

Your first quarter obviously was a bit below that, maybe seasonality, if you could talk to that?

But is that a right way for us to be thinking about this business?

Is that something you agree with?

Just a little bit of color to help us think about this business longer term?

This is Martin.

I think that's a good way to think about the business.

You're right on the first quarter where we were $0.85 per gallon on EBITDA.

That was negatively impacted by hedge loss of $0.37 a gallon.

So if you adjusted EBITDA it would have been $1.22.

I think a better way to look at is the last 6 months because we had a big hedge positive in the fourth quarter.

So if you look at the last 6 months, the weighted average EBITDA was $1.24 a gallon.

So right on top of $1.25.

And this hedge gain and loss is not significant over the life of Diamond Green.

It's just in these big moves and the ULSD flat price in the last 6 months.

Okay.

That's helpful.

And second question, I guess, would be a bit of a follow-up to Roger's question where he was asking about how the strip is representing expectations for the diesel crack looking out to early 2020.

I guess, is it your view that -- many times we talk about the strip is never right, but is it your view that it's just not an accurate representation of what might happen to the diesel price?

Or there were some prior comments about how maybe there's going to be more VGO feedstocks that will enter the diesel pool.

Just curious how do you think this actually plays out over the next 6 to 12 months?

Yes.

So I would say that I think the diesel forward curve is not a very good representation of what we would expect the forward market to look like.

You are seeing more contango start to edge its way into the market.

I think that will continue as you get closer to the date, but I think we'll have a stronger diesel environment than what's currently reflected in the curve.

Our next question comes from the line of Jason Gabelman with Cowen.

I wanted to ask, I know there was a question about the West Coast, but I just wanted to follow up on it.

I believe your Benicia plant has been down for a little bit.

I was wondering what the impact was on the quarter and if you have line of sight for when that asset is going to come back online?

This is Lane.

We have about 8 days of downtime in our Benicia refinery.

We had a crude leak in the furnace, and so we had to bring the entire refinery down to repair.

And so consequently, we moved a turnaround we had budgeted in the first quarter '20 into this time frame.

So we're essentially executing a turnaround so we should start the refinery upsort of mid-May-ish or somewhere in the later May, but it will be somewhere in the May time frame in terms of starting the refinery up.

The other -- sort of the other thing we had happen in the quarter that didn't get a lot of press was we had our McKee refinery had an air blower, main air blower outage and that was a big event as well in terms of our impact in the quarter, an unusual event, and sort of was a $90 million.

So if you're trying to sort of frame what the earnings potential for the first quarter could have been, the bigger event in the first quarter actually was our McKee outage.

And again, it was about a $90 million for the gross margin impact.

Got it.

And if I could ask a question on, I believe, you moved the Memphis turnaround from April of this year into 2020.

And I thought that was an interesting data point just because it seems like your peers are doing the opposite trying to conduct their maintenance in the first half of this year.

So wondering if you saw something in the market that made you alter maintenance plans there?

And then just what you are seeing more generally in the industry on maintenance activities in the first half of this year and maybe into the second half as well?

Yes.

So, unfortunately, you have some bad information.

Our Memphis refinery goes into an FCC turnaround in about a week.

So, we don't normally try to position -- take -- we will maybe nudge turnarounds around certain things, but we didn't make a huge effort to try and move our turnarounds and to accommodate IMO 2020 is because we have a lot of assets.

So, but anyway that's kind of where we are.

In terms of the industry we don't really comment on other players in the industry or what we think maintenance activity might be.

Our next question comes from the line of Matthew Blair with Pickering Holt.

So compared to a year ago, you ran substantially higher light sweet crude volumes, or at least the share of your total crude slate, and at the same time your distillate yield ticked up a little bit.

And so I was wondering if -- can we draw a direct connection there, the higher distillate yields with these lights?

Or was that just noise year-over-year?

No.

Actually what we see is as we maximize light sweet we tend to make same amount of gasoline and less, a little bit less, distillate.

So the yield shift is probably more tied to hydrocracker utilizations and what units we actually had down for maintenance rather than a change in the crude slate.

Got it.

Okay.

And then just an accounting clarification, so this $2.5 billion of CapEx the next 2 years, does that include the $550 million of spending for the Diamond Green Diesel expansion?

Yes.

It will.

I mean -- yes, not all in the year.

Okay, I mean, this is spread out over through 2021.

But yes, it does.

Our next question comes from the line of Craig Shere with Tuohy Brothers.

Lot of great comments about catalysts for improving cracks into the second half and 2020.

I guess, my question is more systematic in terms of the new mid-cycle levels we might see aided by IMO 2020.

Are you getting more confident that we could see some sustained benefit lasting 3 to 5 years here?

So really I think that question goes to what's the sustainability of the tailwind for IMO 2020.

Yes.

I think it's hard for us to predict how quickly ships put in scrubbers.

It looks like that's not going to be fast and that the impact of IMO 2020 will be longer-lasting than what we initially assumed.

But I don't know we have a lot of great data on that.

Are ships even able to put in scrubbers the way we were thinking a year ago.

It sounded like the some of the wastewater disposal becomes an issue now?

It certainly -- the most economic scrubbers are the open-loop scrubbers which put the sulfur back into the ocean.

And so as questions have come up whether they're going to be allowed to do that, it certainly presents another degree of difficulty when people are trying to make those capital investments.

Okay.

And last quick question.

I noticed that the corporate expenses down sequentially and year-over-year.

Anything to read into efficiencies or cost controls?

We're always focused on efficiencies and cost controls.

I just don't know if it would've been material enough.

In the first quarter of '18, we actually had an environmental reserve adjustment that's one of the special items that's reflected in the press release.

And that concludes today's question-and-answer session.

I would like to turn the call back to Mr. Bhullar for closing remarks.

Thanks, Liz.

We appreciate everyone joining in and feel free to contact the IR team if you have any additional questions.

Thank you.

Ladies and gentlemen, thank you for your participation in today's conference.

This concludes the program, and you may now disconnect.

Everyone, have a great day.