瓦萊羅能源 (VLO) 2017 Q3 法說會逐字稿

Welcome to the Valero Energy Corporation reports 2017 Third Quarter Earnings Results Conference Call.

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

(Operator Instructions) Please note that this conference is being recorded.

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

Well, good morning, and welcome to Valero Energy Corporation's Third 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 me or our Investor Relations team after the call.

Now I'd like to direct your attention to the forward-looking statements 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.

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

What I'd like to do before we discuss our quarterly financial results is to talk about the hurricanes, and how proud I am of our Valero team and the energy industry as a whole for the way we responded to these natural disasters.

Hurricane Harvey's path touched almost all of Valero's Gulf Coast refineries.

It made landfall just northeast of Corpus Christi before proceeding inland to just east of Three Rivers near Victoria.

The storm then reversed course, short of reaching our headquarters in San Antonio and moved eastward along the Texas Gulf Coast to the Houston-Beaumont-Port Arthur region, where it stalled and dumped 50 inches of rain in the span of 4 days before continuing into Louisiana, and ultimately moving inland and dissipating.

We shut down our Corpus Christi and Three Rivers refineries prior to Harvey's arrival and reduced rate at our 3 plants in the Houston and Port Arthur area, eventually shutting down Port Arthur due to flooding.

Our team worked hard to get these plants safely back up and running, and we only experienced extended delays at Three Rivers and Port Arthur.

Hurricane Irma had a less direct impact on our refining operations, but our commercial team and our business partners worked tirelessly to prepare for and restore the supply chain as soon as possible.

While our operations have returned to normal, we recognize that people and communities affected by the storm are still recovering, particularly those along the southern Gulf Coast and in the Houston and Port Arthur areas.

In response, Valero provided financial assistance, meals, water, shelter, fuel and other support to employees and their affected communities during the storm and the recovery.

One of the things that I was most encouraged by was the display of the American spirit and our determination to help each other during these times of need.

From the efforts of the dedicated employees fighting back the onslaught of torrential rain and rising floodwaters, to all those Gulf Coast residents who banded together to rescue their neighbors and help with recovery and cleanup, it was a defining moment.

An event like this shows the efficiency of the supply chain in the refining and energy sector, which frankly is not fully appreciated on a day-to-day basis.

To think that the epicenter of the refining industry on the Gulf Coast could take a direct hit from a Category 4 hurricane, and keep supply disruptions as short-lived as they were, was impressive.

I applaud our employees, our local state and federal government officials, and all of our business partners, who worked closely with us on the front lines to return the supply of our fuels to affected communities.

Now despite the hurricane impact, we're pleased to report another good quarter of results for the company, which John will share with you shortly.

Last quarter, I mentioned that we were extending our participation in OSHA'S Voluntary Protection Program to more of our facilities.

I'm happy to report that our St.

Charles and Memphis refineries were awarded star status by OSHA, distinguishing Valero as a refining company with the most OSHA VPP Star sites.

These are noteworthy achievements for Valero that demonstrate our focus and commitment to safety and reliability.

Moving on to the market.

Overall, we're pleased to see margins improving compared to last year.

This improvement is primarily due to continued strong domestic and export product demand as well as ample supplies of crude, notwithstanding the impact of the OPEC cuts on the medium and heavy sour discounts.

Our system's flexibility allowed us to shift our feedstock diet to maximize domestic sweet crudes and capture wider discounts versus Brent.

We continue to adhere to our disciplined capital allocation strategy and also made progress on our growth investments.

We expect to complete the Diamond Pipeline and Wilmington Co-Gen projects within the next 2 months, and we're eager to see the incremental earnings contribution from these projects beginning in 2018.

Construction also continues on the Diamond Green Diesel expansion and the Houston alkylation unit, and we recently announced a Central Texas pipeline in Pasadena marine terminal projects.

Lastly, with regard to returns to stockholders, we returned $600 million through dividends and stock buybacks in the third quarter.

This results in a 58% payout of adjusted cash flow and operating activities year-to-date.

So we're well-positioned to exceed our target range of 40% to 50% for the year.

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

Thank you, Joe.

For the third quarter, net income attributable to Valero stockholders was $841 million or $1.91 per share compared to $613 million or $1.33 per share in the third quarter of 2016.

Third quarter 2016 adjusted net income attributable to Valero stockholders was $571 million or $1.24 per share.

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

Operating income for the refining segment in the third quarter of 2017 was $1.4 billion compared to $934 million for the third quarter of 2016, which has been revised retrospectively to reflect the VLP segment.

The increase from 2016 is attributed primarily to higher gasoline and distillate margins and wider discounts for domestic sweet crudes relative to Brent Crude, partly offset by higher premiums for residual feedstocks and narrower discounts for medium and heavy sour crudes versus Brent.

Refining throughput volumes averaged 2.9 million barrels per day, which was 33,000 barrels per day higher than the third quarter of 2016, despite Hurricane Harvey-related impacts.

Throughput capacity utilization was 92% for the third quarter of 2017.

Refining cash operating expenses of $3.71 per barrel were $0.17 per barrel higher than the third quarter of 2016, mostly due to higher energy cost in the third quarter of 2017.

The ethanol segment generated $82 million of operating income in the third quarter of 2017 compared to $106 million in the third quarter of 2016.

The decrease from 2016 was primarily due to lower margins resulting from higher corn and lower distillers grain prices.

Operating income for the VLP segment in the third quarter of 2017 was $69 million compared to $56 million in the third quarter of 2016.

The increase from 2016 was mainly due to contributions from the Meraux and Three Rivers terminals and the Red River pipeline, which we acquired in September 2016 and January 2017, respectively.

For the third quarter of 2017, general and administrative expenses, excluding corporate depreciation, were $229 million and net interest expense was $114 million.

Depreciation and amortization expense was $497 million and the effective tax rate was 30% in the third quarter of 2017.

With respect to our balance sheet at quarter end, total debt was $8.5 billion, and cash and temporary cash investments were $5.2 billion, of which $116 million was held by VLP.

Valero's debt to capitalization ratio, net of $2 billion in cash was 24%.

At the end of September, we have $5.1 billion of available liquidity excluding cash, of which $720 million was available for only VLP.

We generated $1 billion of net cash from operating activities in the third quarter.

Excluding the negative impact from a working capital increase of $315 million, cash generated was approximately $1.4 billion.

With regard to investing activities, we made $565 million of growth and sustaining capital investments, of which $73 million was for turnarounds and catalysts.

Moving to financing activities, we returned $600 million to our stockholders in the third quarter.

$309 million was paid as dividends and the balance was used to purchase 4.2 million shares of Valero common stock.

As of September 30, we had approximately $1.6 billion of share repurchase authorization remaining.

We continue to expect capital investments for 2017 to be $2.7 billion, with approximately $1.6 billion allocated for sustaining the business and $1.1 billion for growth.

Included in the total are turnarounds, catalysts and joint venture investments.

For modeling our fourth quarter operations, we expect throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.65 million to 1.7 million barrels per day; U.S. Mid-Continent at 410,000 to 430,000 barrels per day; U.S. West Coast at 265,000 to 285,000 barrels per day; and North Atlantic at 465,000 to 485,000 barrels per day.

We expect refining cash operating expenses in the fourth quarter to be approximately $3.90 per barrel.

Our ethanol segment is expected to produce a total of 4 million gallons per day in the fourth quarter.

Operating expenses should average $0.37 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 third quarter, to be around $215 million and net interest expense should be around $115 million.

Total depreciation and amortization expense should be approximately $495 million.

Lastly, we expect RIN's expense for the year to be between $800 million and $900 million.

And 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 two questions.

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

This helps us ensure other callers have time to ask their questions.

(Operator Instructions) And we have our first question from Roger Read with Wells Fargo.

Joe, I guess let's dive in on everybody's kind of favorite, refining, nonrefining topic of RINs here.

Obviously, some news has flowed through, both positive and negative the last time we talked.

And I'm just curious if we think about there's the RIN expense number and there's, obviously, some magnitude of recovery you're able to achieve.

Can you give us any guidance on kind of how that flows back through?

What you've been able to do to mitigate the expense?

And then maybe what you can do forward?

And let's assume there isn't going to be a meaningful policy change in the next 12 months.

All right, well fair enough.

The number that we would share on the actual RIN cost is the $800 million to $900 million.

So I won't speculate on how it affects the marketing volumes and so on.

But what I will tell you is, I think you can see it from the release, we're continuing to invest in assets that allow us to blend more and to export more.

So we've got a very strong focus on logistics and on the wholesale market expansion.

Now relative to this policy situation, Roger, this RFS fight is far from over.

As you would expect, those who are enjoying this windfall are aggressively defending their positions and we have a counter view.

Why don't I let Jason just give you some insights into our perspective on what's occurred and then maybe where we go.

Yes, this is Jason.

You all probably saw this letter that Administrator Pruitt sent to these Midwestern senators here in the last week about potential changes to RFS that the EPA was looking at.

In the letter, he said they decided they weren't going to move the point of obligation.

They weren't going to lower the biodiesel volumes under the notice they were looking at and they weren't going to grant export RINs, which is another idea they were looking at.

Of course, we're disappointed in how this went down since it looks like political pressure resulted in short-circuiting the policy review process.

You know that's just not good government.

It's one thing to have a full ballots' review of a proposal and decide it's not the right thing for the country, and it is another to be bullied and abandon your analysis midstream, which is what looks like -- looks to us what happened this time.

The White House, the EPA, and Congress have all acknowledged that high RIN prices are problem for the refiners.

This is not the way the program is supposed to work.

So they're going to continue to get pressure until we get the situation addressed.

We're going to continue to pursue our legal, regulatory and legislative options as are others, and we're going to keep up the fight.

Okay, thanks.

I guess maybe changing tack just a little bit.

Other big issue if you look out there is a pretty big difference in some of the light crude pricing, particularly thinking WTI, Midland or Cushing relative to Gulf Coast prices.

Can you give us an idea of how you're able to take advantage of that along the Gulf Coast?

Or maybe sort of a net crude pricing you're able to achieve through some of your marketing and pipeline access?

Roger, this is Gary.

I guess, we've raised our capacity to run light sweet crude.

So we're now about 1.6 million barrels a day of light sweet crude processing capability, with the addition of the toppers in Corpus and Houston.

In the Mid-Continent itself, we have 300,000 barrels of refining capacity between Ardmore and McKee.

And the Diamond Pipeline, which will start up in December, then puts Memphis with competitive access to that Midland Cushing market as well, which gives us about 500,000 barrels a day of equivalent Mid-Continent refining capacity.

In addition to that, we've worked very hard to secure logistics to give us competitive access to Midland at Corpus and also competitive access to Midland and Cushing in our Houston refineries.

And we've also added Line 9, which gives us exposure to that Brent TIR.

So a lot of this work that we've done on logistics over the past several years, we feel like puts us in great position to be able to take advantage of that light sweet, sweet difference.

Our next question comes from Spiro Dounis with UBS Securities.

Joe, just want to start off here.

Valero has been a strong steward of capital over the last few years and it just seems like the market is really starting to recognize the tight belt on spending and strong capital return.

But I can't help but notice the large cash balance, low debt levels, strong currency in share price now.

It just screams like maybe you should be investing here.

So just wondering, do you think you are reaching the point where a pivot to maybe more spending makes sense, whether it'd be refining midstream or expansion up or down the value chain?

I mean, Spiro, that's a good question.

I think you understand the way we look at the use of capital.

And we do have a strong cash position.

We do have a strong balance sheet.

Acquisitions are very opportunistic as you well know.

And we look at everything.

To have an effective acquisition for Valero, it's got to be one that there's synergy involved in, and so that's one of the primary considerations.

We have a great portfolio of assets today.

So we're not compelled to do something just because of where we find ourselves.

And then we always evaluate the returns that we could achieve with an acquisition or a growth project with that of buying back our shares.

And frankly, we still feel that we're undervalued at the price we're at today.

So that competition for the use of what we would deem to be the discretionary cash flow remains.

So I think you'll see us continue to look at opportunities as they present themselves.

I think that you can expect that capital projects will continue to percolate up, and if they return to their fellows' projects, we're going to do them.

But I mean nominally, our capital budget is going to be in this $2.7 billion to $3 billion range.

That's just what we feel that we can execute effectively.

And if for some reason we find some very interesting projects that would increase that number going forward, we've told you guys that we'll make our case with you on why it's a good idea.

So anyway, I think what you should expect is a bit more of the same going forward.

Fair enough.

And then maybe just general comments the market here.

I think, you got refined product supply lower than it's been in a while and as you head into wintertime here, I don't think you have seen distillate this low in years.

I guess historically that's kind of what's let's you a ramp-up in gasoline introduction too early in the spring.

So maybe just as you look into 2018, the setup right now for an inventory standpoint, has it surprised you?

Are we looking things being better than what you expected, maybe, earlier this year?

Well, I think even pre-hurricane, you saw typically during that time period, you saw some pretty good builds in distillate and distillate inventories were flat or even falling, even before you had the hurricane effect.

So then when you had the supply disruption, it has definitely put us in a very good position in terms of inventory heading into the winter, the heating oil season, with much cold weather at all, I think we're in for a very strong distillate season.

And then I think the point you made is accurate.

The last several years, distillates haven't been strong enough to really force refineries into a max distillate mode.

And it's kind of created a gasoline build heading into driving season.

But this year, it looks like with the strength in distillate, refineries will operate in a max diesel mode, which will help avoid the gasoline build and should be supported with the gasoline crack next year.

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

I've got my full quota of two, if I may.

Joe, the RIN question from earlier, I wonder if I could just add a bit of a follow-up to that.

What are your options to mitigate your RIN exposure?

I'm thinking exports, retail, other things you can do if this is going to drag on a bit more because it looks like the RIN guidance, the cost guidance has ticked up a little bit from what you had previously.

I wonder what your response will be now that, that line of potential resolution appears to have stalled for now?

Yes, Doug, that's a great question.

And I think if you look at the projects that we've announced, okay, you look at the pipeline that will take products into the market area, we're going to own a terminal.

It'll allow us to blend.

We're aggressively expanding our wholesale marketing business, and then the terminal at Houston that we've announced with Magellan is going to allow us to export more product.

We don't have our heads in the sand on this by any stretch of the imagination, and we will continue to develop projects which allow us to deal with this issue.

Again though, Doug, that being said, I think this fight is far from over.

There is a clear realization, as Jason stated, not only at the White House and in Congress, but also with the regulators that the RFS as it is structured today is broken.

And it's not achieving the objectives of the legislation when it was implemented.

And so there will be changes.

And we'll continue to deal with it strategically with the things we can control, and we'll continue to deal with it legislatively and from a regulatory front to try to come up with some type of reasonable solution to this.

But we are doing what we can, Doug, to try to mitigate this expense.

I will wait to hear what you got to say on that on a future date.

My follow-up is really, I guess, you kind of stump this one out at third-party conference, resetting the payout ratio to cash flow.

And I really got to commend you guys for doing that in terms of transparency, but my question is basically, to get the full benefit of that, one would imagine that it resets your dividend yield, and to some extent that has already happened, but now that you're -- where your share price is trading, you've obviously been very cognizant about when to do buybacks.

And what's really the bulk of my question is, assuming we get a corporate tax reduction, one would imagine that your corporate cash flow is going to take another step higher through this cycle.

What is your current thinking on the buyback versus dividend split as you go forward?

I mean, with this reset and the target is -- are we likely to see greater emphasis on dividend growth going forward?

And I'll leave it there.

On the reset of the target, I do not think that really affects our absolute dollar payout, but going forward, we're just going to provide it from -- with a different metric.

We'll provide the guidance versus the different metric.

In regards to the dividend, our current plan is to review the dividend for increases annually, and to pay a dividend at the high end of our peer group range.

Regarding share repurchases, they will be funded from our excess cash flow.

So as we generate excess cash flow, we'll compare the repurchase with our alternative uses of cash, and if the repurchases is the best use, then we'll repurchase some more shares.

I don't want to take up my quota, but maybe just an observation, your yield is now trading in line with ExxonMobil, just to put it in context.

One would suspect the dividend growth also gets rewarded in the relative yield of the share price, I guess, is what I'm saying, just an observation.

But I appreciate your answer and I like the moves.

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

Joe, you've obviously announced this New Mexico terminal sort of partnership.

Can you talk through sort of what having that terminal gives you that you didn't have before as it relates to selling into Mexico?

Brad, this is Gary.

We have secured a long-term deal.

It gives us access to deepwater marine terminal in Veracruz, Mexico.

From there, we can supply inland terminals and Pueblo in Mexico City.

We expect that to be in operation sometime in the first quarter of '19.

In addition to that, we continue to ramp up our cross-border volume to supply the market.

And we're also exploring other opportunities to supply some of the other major population centers.

At this time, we're not ready to communicate any of those opportunities.

In addition to all the work going on in logistics, we are also engaged with a number of retailers and distributors regarding wholesale volumes to supply both branded and unbranded volumes there.

So Brad, I mean there's really two benefits, right?

Number one, we sell barrels into Mexico today.

This provides us with the footprint and the opportunity to capture additional margin on those barrels, and then it provides the opportunity to grow.

It's a market where consumption is growing.

Same is true with other parts of Latin America, and that's why we continue to look at those also.

And then of course, you get the other benefit.

You have a RIN-related benefit associated with securing those markets and exporting more into them.

Okay, that's great color guys.

And I guess maybe sticking with Gary, just on the Venezuela front, obviously, you guys are big buyers of Venezuelan crude.

Heard a lot of anecdotes recently about quality declines there and difficulty in regards to payments.

Any color you can give there about how you guys are thinking about Venezuela as a source going forward would be great?

Sure.

Our volumes in Venezuela have been fairly consistent.

We certainly see the struggles that they have.

Some of that shows up in the load windows.

It's difficult to get the load windows, but we've been getting the volume and we have seen some degradation in quality, but the commercial terms that we have on our contract with Venezuela have price deducts that go along with those qualities.

So we really haven't seen any problems as of yet.

Our next question comes from Paul Sankey with Wolfe Research.

Hey, Paul, are you there?

It seems he has dropped.

I will move on to the next question.

Our next question comes from Paul Cheng with Barclays.

Joe, two questions.

Maybe the first one would be for Gary, actually.

For the Diamond Pipeline, when is that going to start up?

And what is the life is going to be?

What are we talking about on there?

Yes, so Diamond Pipeline will be doing line fill in November and we expect the pipeline to be in operation in December.

To kind of get an idea of the economics today, we supply Memphis from the Gulf and it's really an LLS plus pipeline tariff.

When Diamond is in service, it will be Cushing or Midland TI plus the Diamond tariff.

So it really is that WTI to LLS spread that you would look at.

Today that spread is around $6.30.

So Gary, should I interpret what you say is that the tariff will be about the same as that from the gulf up to Memphis today?

No, there's a little difference in the tariffs, but it's not too significant.

And when you're getting the oil from Cushing on the WTI and the Gulf Coast, are we going to see any yield difference or anything that we need to take into consideration in addition to the LLS, WTI spread?

Yeah, we will have a number of grades that.

One of the reasons we like Diamond is that it gives us access to a number of different crude grades, and certainly depending on what crude grades are economic at the time, there can be a yield shift associated with the crudes.

Okay.

But that's not in your base economic?

No, it's not.

Okay.

And second one, Joe, on the IMO 2020.

Does Valero have any plan or expected launch refining CapEx projects associated with that to shift your yield?

Why don't I let Lane and Gary weigh in on this.

Paul, this is Lane.

So we, obviously, are looking at that, and we have a view.

Our existing assets will clearly benefit from that regulatory change, and we have several big projects that are in our gating process.

We're not in a position to talk about them publicly, but we definitely understand that will change the market, not only for fuel oil, but we believe that the replacement fuel will be diesel.

So you'll see a fairly positive economics from that sort of resid to diesel spread.

So yes, we are looking at projects to take advantage of that.

Is there any timeline linked that you guys may come to a FID decision or any kind of time line you can share?

Yes, we'll get to some FID decisions in the first half of next year, maybe even as early as the first quarter of next year.

We have to go through our gating process and get the engineering done.

And so it will be sometime next year when we would be provide a little more clarity to everyone as to what we're deciding on and what we'll invest in.

And will those be in the, say, billion, billion and a half kind of project or will that be much smaller?

All very excellent questions.

But I think I probably said about that as much as I can.

Paul, that was number three.

We love talking to you.

We'll get out there with it soon enough, though.

But -- and Lane answered it properly.

Our next question comes from Phil Gresh with JPMorgan.

I suppose I'll ask one more question in a slightly different way there on the back of Paul's question, which is this range of CapEx that you've generally talked about, this kind of 2.5, I guess it's 2.5 to 2.7 type of range.

Would any of these projects be big enough that it would influence that?

Or do you still think that you're generally going to operate within that range over the next few years?

No, I don't think we're ready at this point in time to tell you that we're going to jump above that range.

And the projects are material, but it goes into the discipline around selecting the ones with the best rates of return that position us best to grow in the future.

And so that's our focus.

You know projects take several years to construct.

And so even if there's a $1.5 billion project, you're talking $500 million, $600 million a year.

So I don't think you should expect that you're going to find us jumping to $3.5 billion to $4 billion of CapEx.

Right.

Okay.

That's helpful.

And then certainly, I can appreciate all of your comments about the efforts on the Gulf Coast.

But I'd just ask about where Valero is at in terms of as we enter the fourth quarter, were there any residual effects anywhere in your system?

I guess, I'm thinking maybe Port Arthur or would you say you're fully back up and running by the start of the quarter?

Yes, Phil, this is Lane.

So Port Arthur would have been the refinery that has the most -- the biggest lingering effect going into the fourth quarter, but our operations are back to normal as of now.

So...

Okay.

And then the last question for Joe.

Joe, you've talked about this $1.2 billion to $1.4 billion of project EBITDA that's going to be coming over the next few years, $300 million to $400 million of that in execution phase.

So, you talk about Diamond's coming, Wilmington's coming, Diamond Green Diesel, how much should we expect in 2018 uplift to the run rate basis?

Yes, I'll let -- why don't John give you some insight there.

Yes, Phil, so we've got Diamond Pipeline and Wilmington Co-Gen that's coming up.

We have given that Slide 13 in our deck, so you can have a longer-term view of expected EBITDA.

We really don't break it down by year.

So we don't have specific guidance on those two that you can expect next year.

But you can kind of triangulate on the IRR thresholds that we've given in the slide deck and use the base costs for those two projects to get a ballpark, depending on your price assumption.

But what we have done in the past, and you can see in the slides on the toppers, was do a make good after there's some time where they operate, and we can kind of see what they are contributing.

And I would think for larger projects, we would continue to do that.

So with the run rate of the $1.2 billion to $1.4 billion, generally be fairly linear over this next 5 years, more broadly?

Well, we don't have guidance on if it's lumpy or smooth.

But as the projects come online, we'll look at it and talk about them a little bit.

That's really all we can say.

Our next question comes from Blake Fernandez with Scotia Howard Weil.

A question for you.

I was hoping to clarify on this VLP drop of $508 million.

Can you clarify how much of that is going to be financed in the form of units versus cash?

Because I'm trying to figure out how much cash is going to actually land on the balance sheet in 4Q?

Blake, this is Joe.

Donna is going to give an answer to this.

Yes.

So the net cash inflow to VLO for that should be a little north of $400 million.

There will be some unit take backs, but it'll be relatively small and less than $50 million.

Okay, great.

And then Gary, back on the previous question on shifting toward maximum distillate yield.

I don't believe you stated this, but I was looking at your 3Q levels and it looks like you're running about 38% distillate yield.

I'm just curious, is that kind of the upper end of what you think the system can do?

Or I guess, how much flex do you have there?

We generally say we have about -- ability to swing about 5% of our yield slate.

I would say for the third quarter, we were in a max distillate mode for a good portion of the quarter.

So I think that's kind of the amount of flexibility you'll see in the yields.

And you think that's indicative of kind of industry so in other words, maybe another 2% or 3% or so ability to kind of flex more toward distillate going forward?

Yes, I would assume most people are similar to us.

Our next question comes from Neil Mehta with Goldman Sachs.

First question was around the product export market.

Just one, your guys' perspective in terms of where ultimately the barrels are going and the outlook for product exports as we roll into 2018 here?

This is Gary.

The third quarter, we did 88,000 barrels a day of gasoline exports, and we did 251,000 barrels a day of diesel exports.

I think especially on the diesel, you definitely saw some hurricane impacts.

You know prior to the hurricane, we were over 300,000 barrels a day of diesel exports.

And then certainly, you know with the hurricane, we -- those volumes dropped.

November, with November trade, we saw wide open arbs to go both to South America and to Europe.

December trade, it looks like certainly a big pull again to Latin America.

For the first few days of December trade, the arb to Europe has been closed, but our traders expect it to open up.

So we don't really see that there will be much of a material difference in export demand.

In fact, we expect it to grow as we see growth in South America.

I appreciate it.

And then as a follow-up, Gary, just on Brent TI.

So you talked about how the system is switching to maximize lights . But do you have any views on -- in terms of what's driving it this wide?

It seems like LLS is firm here, Houston pricing is actually relatively firm.

It's really -- it seems like there's a congestion or bottleneck around Cushing.

But any color, as folks who are in the market, in terms of what's driving the differentials wide as it is?

And then just kind of how you're thinking about that spread going into 2018 as well?

Yes so I think what you're seeing in Brent TI is really a combination of factors.

It's strength in Brent and weakness in TI.

So the strength in Brent, you're seeing a pull from Asia of North Sea barrels and you're seeing good refining margins in Europe.

And so it's pushed the Brent contract into backwardation.

And then on TI, it had weakness and some of that was driven from the hurricanes.

You decrease demand for TI with refining capacity down, and then the hurricanes also hindered our ability to export the crude.

Following that period, now you have a period where you have some Mid-Continent refineries and turnarounds that look like, at the peak, 400,000 to 500,000 barrels of refining capacity that's down.

And so that's put -- it's begun to stress the logistics a little bit.

So the market link line and the seaway line are both under proration, and so it's really that then caused this weakness in TI.

So certainly, it improves some as Mid-Continent refining capacity comes back online.

But as we continue to see production growth, I think you know you'll see that pipeline tariffs are meaningful again.

And we would expect to see a little bit wider Brent TI through next year.

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

Got a interesting development on Capline last week.

Can you talk about the company's interest in possibly locking up line space on a potential reversal of that line at the same change in Meraux?

And how are you thinking in general about the long term mix of Canadian heavies into your Gulf Coast system?

Yes, Chi, this is Gary.

It's really difficult for us to be able to comment because at the stage we're not sure what's going to feed the Capline reversal.

You know they said 300,000 barrels a day.

We're not sure what feeds it.

In general though, we have connectivity into Memphis through Capline.

So a reversal gives us more optionality at Memphis.

And then I think, if it is Canadian heavy, it gives us some more access to Canadian heavy at our St.

Charles refinery, which is a positive as well.

But at this stage, it's just too early for us to really comment on anything we would do with that.

Well does the Capline reversal change here support at all for Keystone XL moving in?

I mean, you can't get barrels into Patoka of Keystone, and how do you think about that?

Well we're still supportive of Keystone XL.

It's a -- to us, it's the most efficient way to bring the barrels in.

But we'll see what happens with that and then what happens with Capline.

Okay.

And on Latin American heavies, you talked about Venezuela, but certainly there's declining production throughout that region.

How do you think that plays out longer-term on availability of Latin American heavy into your region?

And how does that influence Maya differential longer term?

Yes, so I think you see some decline in South America, but we see Canadian heavies continuing to ramp up.

And so I think some of the lost barrels that you have form South America will be replaced by additional Canadian heavies.

We certainly see that while the OPEC cuts are in place that the quality differentials can be narrower, but when you get the OPEC barrels, you'll see wider differentials.

And then as you move closer to this IMO 2020 date, we think that the quality differentials will be very wide at that -- during that period of time.

And then maybe just one general question here.

Joe, you talked about the hurricane impacts and supply chain efficiencies in your remarks.

But is there anyway you guys can get more fuel into Puerto Rico to help those people out?

By all accounts, there's still a shortage of everything, and it just seems like we need a private sector to step in and take the lead here to help out the situation there.

You know, Chi, that's a really nice thought.

I mean, we have provided financial support into Puerto Rico as well as Mexico after the earthquakes and then, of course, as a result of the hurricanes here.

And from a fuel supply source, Gary?

Yes, we certainly can look at it.

I don't -- I can't say that we've had any calls for fuel.

But I'll look into it, Chi.

Well, we sure wouldn't hold it back.

No.

Our next question comes from Justin Jenkins with Raymond James.

I guess maybe a couple on midstream from me.

So last quarter we talked about M&A versus organic growth.

And Joe, I appreciate your response to an earlier question, and you mentioned how much you prefer maybe the organic side, given control of development, and certainly seen that with the investment or the announcements you've made in September.

But I guess, I'm curious with the difficulties playing out in midstream stocks lately and maybe the relative strength of VLP, if maybe you see things looking better for M&A?

Well, I mean -- look, what we've seen, what we've participated in the M&A market around, let's just say gathering systems, it seems like there's still a pretty lofty multiples, okay.

So then you get into is it better to try to buy something like that or is it better to go ahead and do the development yourself.

So obviously, we've seen plenty of opportunity to strengthen our system, both for Valero and for VLP, by doing the organic projects.

But Rich, is there anything you want to add to this?

It's basically what you said, the assets, the transactions that we see are trading in north of 20x multiples.

And we've got a good inventory of organic projects and the EBITDA upstairs, the drop-down.

So acquisitions are part of the growth strategy.

But right now, we've got a lot of good stuff at much more attractive multiples.

But we do look at all this stuff.

Okay.

And then maybe kind of thinking on the financing plan for the two midstream JVs announced in September.

Do you think we could view it more like Diamond, where we build it at VLO and dropped then to VLP?

Or is there a thought to take it VLP involved sooner.

And I'll leave it there.

Well, and Donna may want to speak to this.

But I would say that generally our ultimate goal here, as VLP grows, is to be able to -- allow it to be able to do its projects and its acquisitions on its own.

Today, Valero still has absolutely no problem providing, what I will call it, financial support, but being on point for taking the asset and adding it to the drop inventory.

Anything you'd add?

No, I mean, it's right.

So as soon as VLP can get to that size and scale to take this on -- to take that negative cash impact on itself, we're certainly looking forward to that to doing it that way.

And our next question comes from Ryan Todd with Deutsche Bank.

Maybe just a couple of quick ones.

On run rates, your run rate guidance in terms of volume throughput into 4Q is relatively in line with our expectations, but I think there's been some talk of deferrals of turnaround activity and maintenance activity into earlier next year to take advantage of the opportunity.

I mean, are you seeing any of that across your portfolio?

Or as you look broadly across the industry, do you have expectations for activity -- turnaround activity, I guess, deferrals now or what it means for next year's maintenance period in February and March?

Well, Ryan, I'll start with the last question.

We don't really have forward views on where we're going to be in the first half or even next year on our turnaround, and not really on the industry.

But I will say is that we deferred our McKee turnaround in the Mid-Continent for about 2 weeks to help get into better contractor situation and supply situation.

And so that was really just a 2-week delay.

We did move out a catalyst change in one of our -- in our LTO hydrocracker in Houston into next year.

And that's pretty much the extent of our deferrals.

We didn't have a lot of turnaround activity in the Gulf Coast going on or the Mid-Continent, for that matter, going on in the fourth quarter of this year.

Great.

And then maybe just one more quick one.

In third quarter, I believe, your feedstock was, I think, you ran about 52% sweet, you're 48% sweet last quarter.

Prior to the startup of Diamond, is there any additional flex in the mix to run additional sweet and get closer to the 1.6 million barrels of capacity?

Or is that about max?

Well, if you look at the way we ran in the third quarter out of that 1.6 million barrels a day of capacity, we utilized about 85% of that.

In the fourth quarter, certainly some of that under -- unutilized capacity that we had was a result of the hurricanes, so that capacity is back online.

But with the heavy Canadian discounted to Houston TI barrel by 15%, economics are really pushing us towards the heavy at some of our plants, and then light sweet after that.

Our next question comes from Faisel Khan with Citigroup.

Two questions.

First, the decision to take back a small number of units in the VLP transaction, was that a function of sort of the current market conditions for MLPs?

Or was it just a function of -- you guys have a $5 billion of cash in the balance sheet and you don't need to take back the cash?

The decision to take back some of those shares was largely to mitigate some of our tax exposure on the deal.

Okay, okay, got you.

And then just, I guess, following up on that, the current cash balance of over $5 billion, no matter how much stock you buy back and no matter how much you increase the dividend, the balance still remains.

So I just want to understand your philosophy around that.

That's a good thing.

You know, Faisel, I mean that's a good question.

I take it.

Your question is, what are we going to do with all the cash?

We're going to continue on the path we're on.

And as I said earlier, we think our shares are undervalued.

So the capital allocation framework that we put in place has worked very well for us.

We do -- Mike mentioned, we look at the dividend.

I don't think we're at the top on where we're going to have dividend payouts going forward.

And then, we -- again, a significant transaction would chip some of the cash.

So again, we've told you in the past, our objective is not to hoard cash and just sit here with a ton of cash on the balance sheet.

We're going to put it to work, and we'll do it through the context of the capital allocation framework.

Okay.

And when you say that an acquisition could chip some of the cash away, are you -- is that you tried -- you look for stuff and you just can't make it work?

Or is it just the timing is not right?

Well even with a lot of cash, it doesn't make sense to overpay for something.

And we have a very disciplined approach to looking at acquisitions.

And as Rich stated on the logistics side, 20x multiples seem to be a little bit rich, when we can do organic growth projects around logistics at much more attractive economics.

Granted, the run rate is longer, the lead time is longer, but the result is much, much better for our owners than it would be if we overpay for something.

So patience isn't something that maybe that we're all blessed with, but we're trying to do so and to continue to drive growth, but do it in a reasonable way.

Our next question comes from Craig Shere with Tuohy Brothers.

The latest drop looks to be a bit of a lower multiple than historical.

Is that driven more by perhaps higher maintenance CapEx on the assets or the higher cash component?

Is that an issue?

And do you see multiples starting to stairstep down for ensuing drops relative to what you've done in the prior years?

So the combined multiple for the most recent drop is not out of line from our prior drops in that 8.5x to 9.5x multiple.

And so I wouldn't contribute any higher maintenance or any capital associated with these assets here.

They are high-quality assets.

They're -- again remember, we solve for a IRR pretax for these drop downs and the multiple just kind of rolls out.

So we're in that 12% to 13% pretax IRR on these drop downs.

But there's nothing funny going on with maintenance or CapEx associated.

I'm sorry.

I may have just misunderstood the press release.

So is the combined EBITDA $84 million?

No.

It's $60 million.

Okay.

I apologize.

I see no questions in queue at this time.

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

Okay, well, thank you, everybody.

We appreciate you joining us 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.

We thank you for participating, and you may now disconnect.