瓦萊羅能源 (VLO) 2018 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Third Quarter 2018 Valero Earnings Conference Call.

(Operator Instructions) And I would now like to introduce your host for today's call, Mr. John Locke.

Sir, you may begin.

Good morning, and welcome to Valero Energy Corporation's Third Quarter 2018 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; 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.

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 the actual results to differ from our expectations, including those we've described in our filings with the SEC.

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

Thanks, John, and good morning, everyone.

We had solid safety and operational performance in the third quarter.

Refinery utilization exceeded 99%, and we set a new record for light sweet crude processing as discounts relative to Brent remained very attractive.

We also delivered strong financial results outperforming the third quarter of last year despite a margin environment that was generally less favorable.

Our use of the Diamond Pipeline and Enbridge Line 9B again contributed meaningfully to the performance of our Memphis and Québec city refineries as these pipelines provided access to discounted Cushing and Canadian sweet crudes, respectively.

We look forward to the start-up of the Sunrise Pipeline expansion, which is scheduled for November 1. This pipeline will add another 100,000 barrels per day of Permian pricing exposure to our Mid-Continent refineries and displays an equal volume of less competitively priced crude.

We continue to deliver on our commitment to grow Valero's earnings capability through growth, investments and acquisitions, while delivering returns to stockholders.

The Diamond Green Diesel expansion was completed in August, bringing the current renewable diesel production capacity to 16,500 barrels per day.

Development continues on a project to add a parallel facility and further expand the production capacity to a total of 44,000 barrels per day.

A final investment decision is expected before year-end.

In September, our Board of Directors approved a project to construct a 55,000 barrel per day coker and a sulfur recovery unit at the Port Arthur refinery for a total cost of $975 million.

Upon completion in 2022, the refinery will have 2 parallel crude vacuum coker trains.

The additional coker capacity is expected to improved turnaround efficiency and provide margin benefits from increased heavy sour crude processing capability and reduced intermittent feedstock purchases.

Earlier this month, we agreed to acquire 3 ethanol plants from Green Plains with a total nameplate capacity of 280 million gallons per year at a cost of $300 million plus working capital estimated at $28 million.

These plans utilize ICM and Delta-T technologies that are located in the corn belt, enabling us to transfer best practices from our existing portfolio and capture commercial and operational synergies.

We expect to fund this acquisition with cash and anticipate closing the transaction in the fourth quarter of 2018, subject to customary closing conditions and possible FTC review.

Construction of the Central Texas pipelines and terminals and the Pasadena products terminal remains on track, and work continues to progress on the Houston and St.

Charles alkylation units and the Pembroke cogeneration plant.

These projects are scheduled for completion in 2019 and 2020.

Moving to Valero Energy Partners, we announced last week the execution of a definitive agreement and plan of merger to acquire all of the outstanding publicly held common units of VLP at a price of $42.25 per unit.

The transaction is expected to close as soon as possible after meeting customary closing conditions.

Given the paradigm shift underway in MLP markets, Valero evaluated a range of options before the partnership and Valero concluded that a merger would provide the best outcome for Valero shareholders and VLP unit holders.

This transaction offers compelling benefits for Valero shareholders in terms of cash flow synergies in a simplified structure.

At the same time, the merger addresses MLP investor sentiment that has shifted away from favoring the high distribution growth and equity fund to drop-down model to a model that favors slower distribution growth and self-funded organic growth.

The merger also offers a premium to VLP's average trading prices and immediate conversion of VLP's equity to cash.

Now turning to cash returns to stockholders.

We paid out 55% of our year-to-date adjusted net cash provided by operating activities, and we continue to target an annual payout ratio of between 40% to 50% of adjusted net cash provided by operating activities.

As we look forward to the fourth quarter and into 2019, we remain optimistic.

Global economic activity continues to grow at a reasonable pace.

In the U.S., unemployment rates are at record lows.

Domestic and international product demand is strong.

Gasoline export volumes are expected to increase seasonally, while distillate exports should moderate as winter demand picks up in the northern hemisphere.

Despite margins incentivizing maximum distillate production and relatively high industry utilization, days of supply for distillate remained near 5-year lows.

And 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 $856 million or $2.01 per share compared to $841 million or $1.91 per share in the third quarter of 2017.

Operating income for the refining segment in the third quarter of 2018 was $1.3 billion compared to $1.4 billion for the third quarter of 2017.

The $90 million decrease is mainly attributed to lower gasoline and secondary products margins, partially offset by wider discounts for sour and sweet crude oils versus Brent.

Refining throughput volumes in the third quarter of 2018 averaged 3.1 million barrels per day and throughput capacity utilization was 99%.

Throughput volumes were 207,000 barrels per day higher than the third quarter of 2017, when the operations of 5 of our U.S. Gulf Coast refineries were impacted by Hurricane Harvey.

Refining cash operating expenses of $3.67 per barrel were $0.08 per barrel lower than third quarter of 2017, primarily due to higher throughput in the third quarter of 2018.

The ethanol segment generated $21 million of operating income in the third quarter of 2018, compared to $82 million in the third quarter of 2017.

The decrease of $61 million was mainly due to lower ethanol prices in the third quarter of 2018.

Operating income for the VLP segment in the third quarter of 2018 was $90 million compared to $69 million in the third quarter of 2017.

The increase of $21 million was mostly attributed to contributions from the Port Arthur terminal assets and Parkway Pipeline, which were acquired by VLP in November of 2017.

For the third quarter of 2018, general and administrative expenses were $209 million and net interest expense was $111 million.

Depreciation and amortization expense was $517 million and the effective tax rate was 24%.

With respect to our balance sheet at quarter-end, total debt was $9.1 billion and cash and cash equivalents were $3.6 billion, of which $128 million was held by VLP.

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

At the end of September, we had $5.3 billion of available liquidity, excluding cash, of which $750 million was available for only VLP.

We generated $496 million of cash from operating activities in the third quarter.

Included in this amount is $729 million use of cash to fund working capital.

Excluding working capital, net cash provided by operating activities was approximately $1.2 billion.

Moving to capital investments, which excludes acquisitions, we made $604 million of growth and sustaining investments in the third quarter.

Sustaining investments of $435 million include $171 million of turnaround and catalyst costs.

The balance of capital invested in the quarter was for growth.

With regard to financing activities, we returned $775 million to our stockholders in the third quarter.

$341 million was paid as dividends with the balance used to purchase 3.8 million shares of Valero common stock.

As of September 30, we had approximately $2.8 billion of share repurchase authorization remaining.

We continue to expect 2018 capital investments to total $2.7 billion, with about $1.7 billion allocated to sustaining the business and $1 billion to growth.

Included in this total, our 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 1.76 million to 1.81 million barrels per day; U.S. Mid-Continent at 440,000 to 460,000 barrels per day; U.S. West Coast at 265,000 to 285,000 barrels per day; and North Atlantic at 480,000 to 500,000 barrels per day.

We expect refining cash operating expenses in the fourth quarter to be approximately $3.80 per barrel.

Excluding the acquisition of the 3 ethanol plants in Green Plains, which is expected to close in the fourth quarter, our ethanol segment is expected to produce a total of 4.1 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.

For 2018, we expect the annual effective tax rate to be about 23%.

For the fourth quarter, we expect G&A expenses, excluding corporate depreciation, to be approximately $220 million; net interest expense is estimated at $110 million; and total depreciation and amortization expense should be approximately $525 million.

Lastly, given the recent declines in ethanol and biodiesel RIN costs, we are reducing expected RINs expense for the year to between $450 million to $550 million.

That concludes our opening remarks.

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

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

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

(Operator Instructions) And our first question comes from the line of Roger Read with Wells Fargo.

Joe, if we could, one thing you didn't talk about in the overview, but is certainly very topical here, the IMO 2020 thought process.

So story comes out, administration doesn't like it, no surprise there, but the IMO's meeting this week, can you talk about maybe how -- what we're seeing and what your expectations are?

How that fits together?

And if there's any change?

And how you're looking at the potential impact about this time next year into early 2020?

Yes, Roger, good question.

We'll let Jason speak a little bit about that.

Okay.

Hey, Roger, this is Jason.

I'm sure many of you all have been following that meeting, you just referenced the Marine Environmental Protection Committee's meeting that's going on all week in London.

And should you all have experienced the same as we have.

It's a closed meeting, so information trickles out and dribs and drabs at different times, but this is what we've gleaned from it from what we've been able to ascertain.

Looks like there's been 2 very positive developments come out of the committee so far.

Looks like the carriage ban will go into effect on its original proposed date of March 1, 2020.

There was a proposal, I believe, by Bangladesh to delay it, that was defeated.

And this -- it'll be officially voted on either today or tomorrow, to lock it in.

So we think that's a very big deal since it gives the port states a powerful tool to help them force the specs.

You don't have to prove the ship burned noncompliant fuel, they just have to look and see, just having it in the fuel tank onboard is a breach of the regulation, more so, let's say, ship has a scrubber -- that's going to be a -- help a lot with maintaining compliance.

The second bit of good news relates to this experience building phase proposal that's caused quite a bit of commotion and that's what was referred to in that Wall Street Journal article.

Now exactly how this proposal was worked -- would work was never really clear to us.

The proponents themselves actually took the step of issuing a clarifying statement saying it wouldn't delay or phase in the spec change.

Nevertheless, there was a lot of worry that this might pass at least a potential delay or watering down of the standards.

So there was a lot of debate on it at the meeting, and the report we got yesterday was that the committee reached an agreement at the end of the day that the proposal will be limited to data collection and analysis and cover nothing else.

So there'd be nothing about a phase in or initially relaxed enforcement.

So our main takeaway so far is that the committee seems to remain firm in its commitment to fully implement the spec change on January 1, 2020, and to make sure the right enforcement tools are available.

Great.

Second unrelated question, you've got 2 acquisitions come in actually this quarter, the ethanol and the VLP deal.

How should we think about the 40% to 50% payout of cash flow in terms of dividends and share repos relative to the commitments in this particular period with the acquisitions?

We think about the acquisition as a balance sheet event and the CFFO as the normal process.

Yes.

Roger, that's another good question.

And we've been very consistent in our messaging, in our execution around our capital allocation framework.

And really what we're talking about here is the discretionary uses.

There is no consideration of affecting our maintenance CapEx or turnarounds or the dividend so -- in a negative way.

So this really is focused on the discretionary uses.

And if you look at what we've done, we've got really good growth projects.

The Diamond Pipeline is performing very well.

We've got the coker project, which has significant returns, that's under development.

We've got the ALKis, the Central Texas pipeline and many more really good growth projects that are underway.

If you look at it from an acquisition perspective, which is another component of the discretionary piece, we've got the ethanol plants, which Martin can talk about here in a bit, but we were able to buy ethanol plants in a down market.

And when we're looking at acquisition, that's always what we're trying to do.

And then on the repurchases, we've got the payout ratio, which is overriding, but we've been very ratable in our acquisition of our shares and we're focused on buying dips.

So what I would say here is that you should expect that our behavior to remain consistent going forward is what we've done in the past.

And our next question comes from the line of Paul Cheng with Barclays.

I have to apologize that the first question is somewhat similar to what Roger just asked on the IMO, but I want to focus that, Jason, you guys have a lot of contact in D.C. and in the White House and all.

Oh, and I know Joe that met with President Trump for a number of times.

Can you give us some insight that what exactly the White House is trying to do?

Or what is the proposal they have in mind in terms of slowdown the rollout?

I mean, what kind of mechanism or what kind of program that they have in place or that they are thinking?

Okay.

Sure.

And I don't think they've come to a conclusion yet.

And one thing we shouldn't do is read too much into this one story with an anonymous source from the administration as being a statement of their policy.

From our discussions, we don't think the administration has reached the any firm conclusions yet.

They're all understanding the economic impact of the potential changes, but there's nothing yet.

Now the word was they were supporting the experience building phase, and in the context, there seemed to be that it would lead to some type of the layer lax enforcement upfront, but looks like that was very clearly shut down within the committee.

And we -- importantly, we were told the U.S. delegation actually supported this conclusion of basically morphing that, that proposal into something that only dealt with data gathering.

So I think it's an ongoing discussion.

They don't have a firm commitment yet or firm position yet and they're just trying to understand the situation.

Jason, just (inaudible) in the conversations you have with the White House staff, have -- does any occasion come out as a new K option saying that U.S. could even drop out from the ECA definition.

Can the President have the authority to just use executive order that you get out if he want to?

It is pretty complicated.

I don't think they're having discussions a lot about that yet, anything that extreme.

And we've tried to understand this is very complicated, this international kind of treaty law.

And I can tell you what we've been able to do glean, although we're definitely not experts on it, it sounds like you could pull out or the U.S. could pull out of the entire treaty, the MARPOL treaty or the entire Annex.

He doesn't have the option to just pull out of this IMO 2020 sulfur regulation and that would take 12 months notice, and we're not -- there is not certainty around whether the Senate would have be approve that or go along with it.

But the point is if you pull out of the entirety of Annex VI (inaudible) which is the narrowest thing you could deal with, that covers all of the International Marine air pollution requirements.

So the ramifications will go way beyond the IMO's sulfur, the 2020 regulations.

So there's -- it wouldn't be taken lightly by the administration, and it would have ramifications way beyond that spec.

So I think they -- it would take a lot of thinking and see if they want to do that.

And even if you did pull out of the treaty, the other complication is a lot of the requirements and regulations or provisions of the treaty have been incorporated in the separate federal statutes.

So even if the President withdrew from the treaty, the statutes can't be changed except by an Act of Congress.

So they would still be in place.

So it's a very long and messy process to go down that road.

My second question maybe is for either Gary or Lane.

Maya seems like is being mispriced very expensive.

Do you flaunt that it's attractive for you to run it now or that you can have other alternative you would able to fund is far more attractive?

Are you running it at all?

And then maybe as a sidenote, after the roll in of the VLP, will the reporting format of the company be changed that you just roll everything into refining and no longer report the VLP or logistic result on a separate item?

Great, Paul.

Yes, Paul, thank you for Maya question.

Certainly, the volatility between Brent and WTI and the Midland Cushing spread along with fuel getting strengthened as (inaudible) on the Maya formula.

And so we would certainly say that Maya is not priced competitively in the market today.

We've had several conversations with PMI.

I think they're well aware that their barrels are not being priced competitively into the U.S. Gulf Coast, and they will make adjustments as we move forward.

I also think that Maya is not really as relevant of a marker for heavy sour crude as it used to be.

Certainly, in our system, the only heavy barrel -- heavy sour barrels that we buy that are priced off the Maya formula are the barrels that we get from Mexico.

The remainder of the barrels are not priced off with Maya.

And today, Canadian heavy barrel and the U.S. Gulf Coast has a $8 to $10 advantage over Maya.

So we still see a good incentive to push heavy sour crudes into our refining system, but I would agree Maya is not priced competitively today.

And then I guess, the next question was, Paul, your fourth, was relative to...

The segment reporting question.

Yes, so we are still in the process of evaluating the segment reporting going forward once VLP is no longer publicly listed.

We don't have anything to share with you at this moment, but that is something that we're looking at.

And our next question comes from the line of Doug Terreson with Evercore ISI.

I wanted to get your views on market fundamentals, and specifically, while distillate demand and inventories appear pretty positive, the converse seems to be true for gasoline, although net exports for both seem to be pointed in the right direction.

So my question regards really demand trends in the domestic and the regional market that you guys are involved in for these 2 products.

And also whether you sense that price has allocated demand somewhat in North America and Latin America in recent months, meaning, whether we've seen some demand destruction of any sort.

So just kind of an overview on gasoline and distillate, please?

Sure.

This is Gary.

I think, basically, demand is kind of where we'd expect it is to be going into this year.

You've had a little bit of demand growth compared to last year, about 1%.

The real surprise especially on the gasoline side is, yes, very high refinery utilization so -- and year-to-date, we've averaged 93% refinery utilization, 2.6% higher than where we were last year.

With that increase in refinery utilization, gasoline production is up about 2% of where it was last year.

And even though you've had an increase in demand, you've had about a 2:1 increase in production over demand.

It's caused a surplus in the inventory build.

As we moved into the fourth quarter, I think you've seen gasoline cracks get very weak.

Some of that is, typically, as you move out of driving season, you see weaker demand for gasoline.

And then you also have the potential to even swirl the gasoline production further as you move out into RVP transition and get butane into the pool.

I think there are a few bullish signs in the gasoline market, inventory has actually drawn in the last couple of weeks and a lot of that is due to what you alluded to, we've seen very good gasoline exports.

In the last 3 weeks in a row, we've averaged about 1 million barrels a day of gasoline being exported.

In our system, we're seeing very strong South American demand.

Of course, in South America, they're moving into their summer driving season, which has been supportive of the gasoline crack.

And when you look at gasoline inventory on a days-of-supply basis and you take those exports into account, we are at about the 5-year average range on apparent days of supply.

On the supply side, it looks like we could be getting some help as well.

The last set of higher data I looked at, it looks like Northwest Europe hydroskimming margins have turned negative.

Conversion -- even conversion refinery economics are about breakeven.

In the U.S., we're seeing very tight margins on reformers and cat crackers.

And even in the U.S., a hydroskimming refinery, if you don't have advantaged crude supply, those economics are getting challenged as well.

So I think you'll see some gasoline come off the market.

In fact, in the last week of DOE stats, you did see gasoline drop fairly significantly.

Gasoline yield dropped fairly significantly.

And then I think you're starting to see some indications of some run cuts in the industry as well.

The Brent curve moved from backwardation to contango, which may be an indication that you're getting some run cuts that are starting to pressure down the front part of that Brent curve.

Okay.

Can you spend just a second on distillate as well?

Yes.

So distillate, I think, if you look at where distillate inventories that look, both on an absolute basis, and certainly, on a days-of-supply business, we're very low.

We really just haven't been able to replenish distillate inventory since the hurricane last year.

We continue to see very good export demand for distillate as well as domestic demand.

And certainly, in the Atlantic Basin, as you're moving into heating oil season, we would expect demand to be very strong for distillate.

Then again, on the distillate side, I think if you do get some hydroskimming refineries and some refinery run cuts, that will even be more supportive to the distillate market as well because you'll take some of the distillate production offline as well.

And our next question comes from the line of Doug Leggate with Bank of America Merrill Lynch.

Joe, I'm sorry, my first one is an IMO question as well.

So I wonder if I could take advantage of Jason being on the line.

Jason, the situation as it relates to, I think Paul's questionnaire about the White House and so on, our understanding is that -- is really -- the enforcement is really done to member states.

Do you have any thoughts on what the signaling from the U.S., whether they pulled out or not?

Does it really come down to the penalties or the enforcement mechanism, which could ultimately be eased if -- as one method of kind of work around.

I was just trying to think about how the rule making evolves over the next 12 months?

Any thoughts you may have on that would be appreciated.

No, you're right.

That's a key component, and historically, the U.S. has been one of the most zealous enforcers of MARPOL through the Coast Guard and the EPA.

And you could think about how shipping works, and like you said, all shipping within the U.S. is already covered by this tighter sulfur spec, which we seem to be fine with the 0.1% in the ECA.

The only other shipping that'll be involved in going to and from the U.S., and if the U.S. didn't want to enforce it, especially now that we have the carriage rule in place, the flag state would have authority to enforce it, and wherever that ships the other end of the voyage the driver is coming to and from, that port state would also be able to enforce it and have the carriage rule to help it.

So you'd say, even if the U.S. chose not to enforce, which will be very uncharacteristic of us, there should still be a lot of mechanisms in place to do it.

Okay, a lot of moving parts.

We'll see how it plays out.

But I guess, my second question is also kind of related, if I may, and it really gets to Doug Terreson's question about the gasoline market.

It's maybe one for Gary, but everyone should chime in, our understanding is that there was like broad consensus European -- (inaudible) this is the best thing to happen with European refineries in 20 years.

There is an expectation utilization is going to go up at the same time as a lot of U.S. light sweet crude's going to make its way to European markets at the end of next year.

How do you see that impacting the Atlantic Basin gasoline market, and related to IMO, if I may, is that kind of an offset, which is to swing the cat feed into the bunker fuel market that is a viable solution to perhaps resolving some of the potential tightness in that distillate side?

And I'll leave it there.

Thanks, Doug.

Yes.

I think the way you characterized it is very similar to the way we see it.

I think it looks like for the next several months, certainly, first -- fourth quarter to first quarter, gasoline market is going to remain weak.

And certainly, as European refiners run more of the U.S. light sweet crude, you have the potential to put more gasoline on the market.

And it's really when you start getting into the fourth quarter and people start reacting to change for IMO and you pull some of the VGOs out of the cat to get them into the bunker market that gasoline balances start to tighten back up along with some demand growth.

So does that cap the upside risk on potential diesel margin spike as it relates to IMO demand?

I don't really know that it spikes.

I don't really know that I understand what you're asking.

So the perception is that diesel margins spike on the back of a swing from -- away from high sulfur fuel oil and from marine diesel.

But if we're cutting back cat feed on weak gasoline markets, doesn't that solve part of the problem?

Yes.

I think most of the forecast that we've seen says that, that will happen, but it will help make up for the shortfall in the marine bunker and the high sulfur fuel being pulled out of the market, combination of that with ULSD going to the marine market as well.

And our next question comes from the line of Benny Wong with Morgan Stanley.

I was wondering if you could share some thoughts around your CapEx plans next year, now with the logistics business rolled out and the coker spend, particularly on the growth side and how that looks between your business segments?

And if you may, longer term, just any thoughts around allocation split, how that will evolve with the new business structure?

John?

Hey, Benny, this is John.

We really don't have our capital guidance out there yet for 2019.

If you look at what we've done here in the last couple of years, it's been sort of in this 50-50 allocation logistics and refining.

I mean, we've got a project set out there, obviously, that's part of the bigger strategic plan, but we only have guidance on this year.

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

Sorry, I don't have an IMO question.

My question is more on the very strong performance on the North Atlantic side.

I just wanted to understand was it both the assets equally contributing?

Or was it you capturing the European cracks really well?

Or was it also the Québec city benefiting from the light-like spread?

Any color you can provide on the very strong results on the North Atlantic region?

Hey, Manav, this is Lane.

So really what you saw in our North Atlantic strong crack attainment was our exposure to this wide Brent TI arb and really it's our Line 9 reversal that we invested in, the only access to the Puebla, the Canadian -- the distressed Canadian crudes coming out of that region of the world.

So that was really what drove us not only to have exposure on the price of those crudes, but also to run a little bit more rate as a result of that.

And one follow-up, sir.

E15 was recently announced by President Trump, and there were some concerns that it might eat up into a small portion of the gasoline demand, but I know you guys have very strong views that it's not going to be as material as people think.

There are lot of challenges to E15, so if you could give some color on that also, please?

Sure.

We'll let Jason talk to you a minute about that.

Yes.

You're right.

Back on October 11, the White House announced that we're going to direct the EPA to start a rule making to get the E15 RVP waiver in place for next summer.

And this is something the ethanol guys have been fighting for a long time.

It's been at the top of their list.

We don't think it's going to be a sudden big increase in ethanol penetration.

But first of all, there are lots of reasons E15 hadn't taken off already.

Not just -- it's not just related to this RVP waiver.

Retailers have concerns about equipment compatibility.

There is risk to engines that aren't warranted for the fuel.

It is liable for if you have an issue, questions about consumer demand.

But -- and there's only about 1% of the stations in the U.S. have E15 now, about 1,400 stations.

And when you figure out what will it take to offer E15, there is a varying questions.

Basically, you have to spend some money, and you have to spend a lot of money or little money kind of depending on the configuration of your station.

But there's going to have to be some capital spend.

And that brings us to the legality of this rule.

Now there's a big debate about whether the EPA has the authority to grant this RVP waiver for E15, like some people think they do and then a lot of people also think that it's going to have to be done by Congress because the RVP waiver for E10 is actually included in the RFS statute itself.

So one thing that's certain is whenever the EPA rule goes final, there's going to be a bunch of people issue lawsuits challenging EPA's authority to do this.

And this is going to take a couple of years for that to work its way through the courts before you get a final answer.

So now put yourself into shoes of one of these retailers who's got to spend money to be able to offer E15.

Now you're going to spend money with the risk of having stranded capital because in a couple of years the court may void it.

So I think that's going to be -- have some type of a chilling effect on the capital rollout, which will keep things -- keep the rollout from being very aggressive along with just the general problems with E15 we talk about a lot.

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

Just wanted to circle back on the PADD 1 in the Atlantic Basin.

Part of that, I appreciate the color on what the strength there was.

I just wanted to just sort of drill down on the product side.

You just alluded yields of gasoline volumes are down, obviously optimizing to the dynamics there, but just wanted to get your understanding of if there is anything on the product pricing side or moves you've been doing in that market that they're also helping to realize margin there?

And then how to think about that on a go-forward basis versus broader regional dynamics?

This is Lane, again.

I think the only other comment I would make is that our Québec refinery, the way we have that refinery configured, it makes us to have a very high distillate yield for the kind of crudes that it runs.

So anytime you get into a market where the gasoline crack is depressed in relation to the heat crack, that refinery will perform very, very well.

And as we all know, I mean, the heat crack could have been outperforming the gas crack here of late.

So when you think about that, that's the base going forward.

That's really one of the drivers for that performance in that areas with Québec's distillate yields.

Okay.

And I guess, my follow-up also not on IMO question, but wanted to ask (inaudible) Western Canadian heavy and short -- near term and then maybe look into 2019 plans to getting more WCS down into the Gulf Coast (inaudible).

I was -- we've been hearing a lot about railways and an incremental transport volumes.

So just wanted to see if you have any color there and update on what we can expect?

I'm thinking about this also longer term with respect to the Port Arthur coker decision?

Yes.

This is Gary.

I think in the short term really, you're going to depend on rail to clear the production in Western Canada.

And I think you'll continue to say that market constraint.

We're certainly ramping up our rail volume some.

We did about 30,000 barrels a day in the third quarter.

We expect to get that up to 40,000 barrels a day in the fourth quarter.

And then it looks like there is some additional rail being dedicated to that market early next year.

But I think before you see a meaningful shift in the Western Canadian differentials, you're going to have to have one of the pipeline projects done and it looks like the first opportunity for that would be the Line 3 replacement Enbridge project, which looks like the earliest and that would happen would be late next year.

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

Joe, I was wondering if you could just spend a minute walking through the rationale for buying in VLP versus potentially doing something with the IDRs or other options that were available to you?

And then additionally, you mentioned in your prepared comments that there will be some cash flow synergies, so I was wondering if you could give some sort of quantification of that?

Yes.

You bet, I'll take the first part, and I'll let Donna take the second part.

But if you go back to the original plan with VLP, it was to use the MLP structure and its lower cost of capital to develop projects that supported Valero's core business.

And whatever we did a project at VLP or Valero for subsequent drop to VLP, it was always with a, does it benefit Valero and help integration into the supply chain going forward?

So that was where we started, okay.

We got it out there.

We had this great base of logistics assets that we could drop down and opportunities enabled us to provide the MLP investor with a clear line of sight to ratable growth.

We had a sub-3% yield on VLP's equity and we were executing as promised.

Then the MLP market's appetite changed significantly from a drop-down driven high-growth sponsored MLP equity to a self-funded low-growth model with corporate and governance rights.

And the cost of capital was also higher than that at VLO.

So we looked at this for a year or more.

We're very patient.

We watched carefully for any catalyst change that would support a shift back to our original design and we saw none.

So we looked at every available option.

We agreed that the best outcome for both Valero Energy and the VLP owners was the buy end.

VLP unitholders get a premium to the average trading in the market and all the stockholders get an accretive transaction.

So it was a win-win, which are very hard to find and it dealt with a problem you've got or that we've had, which was we had an entity out there that we needed to retain control over and we weren't able to grow it.

So Donna, you want to take the second piece?

Yes.

In regards to the other options that we've looked at, so a lot of talks in the market had been about eliminating the IDRs.

Unfortunately, that doesn't solve the underlying issue of being able to fund growth because still it wouldn't have access to the equity market.

Some other options that we've seen MLPs choose are converting to C-Corps.

As Joe mentioned, these assets are key to us and maintaining control over them is absolutely key.

They support a lot of our primary refineries, and we didn't want to put the MLP into a structure that jeopardized Valero maintaining control over those assets.

So we looked at a lot of different options, as Joe indicated.

We took our time doing so.

We spent the last year or so looking at all of this -- all of the options at whether or not we really thought the MLP equity market would recover at any time soon, and we kept coming back to buying it in was the best solution for both the unitholders and the shareholders of Valero.

You know, Brad, it's interesting and that every solution that one might consider is unique to their individual circumstances and somebody else might choose to do it differently.

VLP was small enough and it afforded us this opportunity.

If it was huge, we probably wouldn't have had the opportunity to do something like this or we'd have had to do it differently.

So anyway, we think we've made the right decision, and the timing was such that we were able to execute it now.

So we decided to go ahead and do it.

Okay.

And then any quantification of the synergy benefit?

It -- they're coming from a lot of different places.

Obviously, the leakage from the unitholder -- public unitholder distribution is the large piece of that.

The public company cost is another piece of that.

And just a simplified structure cuts a lot of administrative cost out of the equation.

And our next question comes from the line of Peter Low with Redburn.

The first one is on the ethanol acquisition.

Can you give us more color on the strategic rationale behind that?

And perhaps whether you'd like to do more deals in the biofuel space in the future?

And the second was just a quick one.

In the release, you talked about a $700 million working capital build.

Is that simply the impact of rising oil prices?

So should we expect it to unwind in the future quarters?

Sure.

On the ethanol -- this is Martin.

If we take a long-term view at this and if you step back and look at ethanol, it's going to be in the gasoline pool for a long time, right, and it's a core part of our strategy.

So the opportunity came up to buy 3 quality plants, so we took it.

We see corn ethanol as the most competitive octane source in the world.

We expect ethanol demand to grow globally.

If we look at exports, they were about 30% year-on-year for the last 3 years.

Exports will be 10% of production this year.

And you'll also see domestic production has been growing at about 3.6% a year.

This year, that growth is going to slow to something like 1% and 1.5%.

So that big increase in production is slowing down.

So we think things are going to start improving on the supply demand balance and with that obviously larger improvement.

So it was just -- we're always looking at acquisitions.

Our last one was in '14 for ethanol, and it just became an opportunity that looked bigger than we took it.

In the future, we'll continue to look in the space, and then the other thing we're obviously looking at in the biofuels is what Joe mentioned a decision on the Diamond Green Diesel two and that will be coming up before the end of the year.

And that's it.

And then Peter, you were asking about working capital?

That's right.

What was your question, again, sorry, just repeat it?

I mean, it's a quite big build in the quarter, about $700 million.

I was just wondering was that simply an effect of rising oil prices?

Or should we expect that kind of unwinds over the next few quarters?

It's all the combination of some volume and some price impact, and there should be a fair portion of that, that will reverse itself.

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

First question I had was around Port Arthur and the decision around sanctioning the coker project.

Can you talk a little bit about the economics of that?

How should we think about it either on an IRR basis or incremental EBITDA for the capital that you're spending there?

Hi, Neil, this is Lane.

So really the benefits are twofold.

One is the feedstock flexibility and an earlier caller had asked a question around how -- our view of Canadian heavy sour in the Gulf Coast.

And we currently have a longer-term view there is going to be considerable amount of heavy sour in the Gulf coast, and in addition to that, just our overall sort of how that fits into our optimization of our Gulf Coast.

We'd like to benefit from the feedstock flexibility.

And secondly, its turnaround efficiencies.

This is a 2 -- today, this is almost a 2-train refinery with the exception of a big coker.

So anytime we are taking certain units offline to do turnarounds, there is a lot of synergies and having this additional to essentially finally separate this refinery into 2 separate trains and build to execute turnarounds in a more efficient manner.

With respect to EBITDA, uncharacterized, but we think the EBITDA of around $325 million used in mid-cycle prices, and I'm going to preface that by saying that mid-cycle does not include IMO.

So we've always been -- we've been pretty vocal saying this is not really an IMO project, this is very much about optimizing our system.

Obviously, if our outlook is to make $325 million in our mid-cycle case, then it's got a lot of upside in an IMO 2020 universe.

I appreciate that, Lane.

And the follow-up is just on the Brent, WTI differential.

So there's 2 parts to this question.

One is, how you see that evolving over the next 6 months to 1 year with the spread obviously at a very wide level, and arguably, beyond transportation economics, but then, again, with the potential for Cushing to build in the intermediate term?

And then the second is that you guys have done a good job of whether it's through the Sunrise Pipeline or through the Diamond Pipeline actually getting access to those light barrels, so can you just talk about how you're evolving the system to capture those inland discounts?

Yes, this is Gary.

I think we see with the start-up of the Sunrise Pipeline and then production increasing around Cushing, you will have more barrels beginning to make their way to the Cushing hub.

Certainly, as PADD 2 turnarounds wind down.

You'll get some demand back, but most forecasts I see shows that Cushing continues to build through next year, and I think you really have to get to the point of late next year when some of the large Midland Permian to the Gulf Coast projects come on that allow Permian production to clear to the Gulf and some of the barrels that are currently going to Cushing get pulled away before you see Cushing start to draw again.

Yes, we -- in fact, our system, Sunrise and Diamond and then Line 9 have all increased our access to certainly the Midland and Cushing barrels, which has been a significant uplift for us.

And our next question comes from the line of Paul Sankey with Mizuho.

For the IMO -- to make it simple for the IMO question, what's your current assumption for the number of barrels a day that are going to be affected here when we get to 2020?

Just wanted to sort of simplify the whole question?

Well, I don't know that we have an absolute number that we give.

There is roughly 3.5 million barrels a day of marine bunker being consumed, and our view is the majority of that has to switch to the 0.5 spec.

Yes.

And essentially, although you said the coker project is not IMO related, I guess, you're expecting essentially the IMO change to go through at considerable scale basically?

Hey, Paul, this is Lane.

We really -- we do believe IMO will go ahead.

I think that's what is our view.

But we didn't fund or we didn't do this project because of IMO 2020.

We just...

Right.

So is it then based on have a heavy-light spread assumption.

Can you talk a little bit about the mid-cycle that you referenced as being the rationale for the investment?

And I have one follow-up, which is just, given the VLP takeback, could you keep going and actually buy MLPs now?

Is that a thought?

Okay.

Mid-cycle, just a way we define a mid-cycle is, it's sort of the average -- the last average of the last 10 years sort of pricing scenarios where we're trying to capture a full-blown refining cycle absent sort of what we consider to be major dislocations, primarily, I would say in the domestic crude market, for example, when we had the Brent TI blow out a few years ago (inaudible) what we considered to be a mid-cycle.

So that's how the prices are.

All right, so Paul, you've got a follow-up for Lane or...

No.

I was going to ask about this idea that maybe you keep going and buying some MLPs?

Well, I mean, we've always had that opportunity quite honestly, right.

I mean, we could have done it in VLO, and then subsequently, drop the assets to VLP.

We'll continue to look at them.

But here, again, I think what our general view of the space is that we need logistics assets that provide better access for crude and feedstock into the refinery and more access to markets with products moving out.

And to the extent that if there is an opportunity out there that scratches those 1 of those 2 itches or both, I think we will really look hard at it.

Otherwise, I don't think that -- it's certainly not, what I would say, a specific point of focus where we're looking (inaudible) we need to go now and rollout MLPs.

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

Could you all walk through the time lines for the build-out of contracted and acquired assets in Mexico and Peru?

Maybe elaborate on the potential export implications both on volume and margin?

And Joe, relating to your last comment, could you opine on the opportunity for additional Latin American infrastructure opportunities post the Peru investment?

All right, we'll -- as far as time line.

Yes.

As far as time line, we acquired the terminal, it's operational.

There is a second terminal -- that's Peru, I'm sorry.

And there's a second terminal in the northern part of Peru that we're in the process of reactivating and that should be first quarter of next year.

So we'll have over 1 million barrels of receipt facility in Peru.

And in Mexico, the Veracruz terminal, which is about 2.1 million barrels of storage should be in service the end of this year, early first quarter of 2020.

And then the inland terminals, which combine between Puebla and Mexico city should be the end of 2019, first quarter of 2020.

Okay, so that's it.

And then, Craig, we do continue to look for opportunities to put a stake in the ground internationally.

Gary, do you or Rich have any other comments on that?

No.

Okay.

So we'll continue to look -- I think really part of my focus right now and the team's focus is, okay, we've got the terminal approved, let's -- and we've borrowed the entire business.

So Gary is running -- not only we got the terminal operation, but we've got a marketing business that was associated with that.

And it takes a lot to get your arms around things and to be sure that we're maximizing the value of it.

So we're looking at that as a potential stake in the ground to allow us to be more on the western coastline of South America.

And then I think we'll look for opportunities to continue to try to move to the eastern coastline down the road, but no specific plans right now.

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

Just a couple of clarifying questions or follow-ups.

First one would be, obviously between the ethanol plants and the growth opportunities in VLP, you've had a string of announcements recently.

I think one of the questions that's been out there is just can you -- with the organic pieces of this, can you fund this all within the construct of your existing capital budget framework?

And I know you don't want to give specific 2019 guidance, I guess, you had, but just trying to clarify that key point?

And then, Joe, just generally, I mean, do you feel like there are other opportunities out there that you're looking at?

Or you just have to grab those string of things that just kind of came up recently?

Well, so we're not deviating from the capital allocation framework.

And yes, to answer your question, even though we haven't provided guidance for '19, I think we've generally provided ranges that we thought worked with our capital ranges, and we're not deviating from that.

So Phil, that's not going to change.

I would say that the timing of these opportunities, acquisitions are always opportunistic, and so Martin and his team did a good thorough evaluation with Rich's team on the ethanol plants, and we had a willing seller.

And so we had an opportunity to buy it at numbers that were very attractive relative to deals we've looked at over the last couple of years.

The VLP buy-in, it was just timely for us to do that.

Again, we were patient.

I mean, it could have happened in June, right, but we wanted to wait and see if the market changed.

Then when we finally concluded that we had basically a broken equity out there and this VLP wasn't going to do for VLO what we expected it to do, it's time to move on and get out of it, and that's exactly what we did.

So it is more coincidental that these things happened at the same time than certainly a sign of things to come.

Okay, fair enough.

Just a second question is just on the throughput guidance for the fourth quarter.

Yes, I think you're assuming kind of at the midpoint maybe 96%, 97% type utilizations.

I guess, I'm just a little surprised by that because of the commentary around some parts of the world needing to do run cuts.

So I guess, obviously, Valero is a low cost refiner.

So perhaps it's less impactful for you guys.

So just wondering how you think about your throughput guidance in the context of the pretty weak gasoline cracks that are out there right now?

So Phil, this is Lane.

I think when you think about throughput, it's primarily feedstocks and crude, right.

So at this time, we think our assets are pretty competitive and our outlook is not that unchanged minus whatever turnaround activity we have in a particular region.

Gary commented earlier around where margins are or predominantly, we see a weak Northwestern Europe hydroskimming margins and Mediterranean hydroskimming margins.

And then we are starting to see sort of breakeven economics on conversion units in the entire Atlantic Basin.

So we'll just see how that affects our -- in reality what our throughput is.

But the time we gave this guidance, that was kind of how we felt the universe for the next 3 months.

And our next question comes from the line of Chris Sighinolfi with Jefferies.

2 quick follow-ups, if I could.

Obviously, there's been some questions on capital allocation.

I realize you're not deviating from your historical approach and also we're not in a position to provide 2019 CapEx guidance.

But just curious how views around leverage are influenced by the recent developments.

Seems like obviously the organic investments, acquisitions provided some opportunity for capital deployment.

The share prices obviously pulled back, and you've talked about opportunistic buys historically.

So can you just remind us or revisit views around sort of consolidated leverage?

Yes.

So our target for leverage is between 20% to 30%, and we're at the lower -- at 24% to a lower half of that.

We have a large cash balance today to fund a lot of those things that we're talking about as well as some borrowing capability.

Okay, so no change in that.

You feel comfortable with it, okay.

No.

Also following up on the E15 question, appreciate the market views, they're very helpful.

But I'm just curious how a potential approval of the President's proposal might impact your own ethanol operations if at all.

And then also any views around additional ethanol acquisitions.

I think, Joe, in your prepared remarks, you had noted a federal review of the Green Plains plant acquisitions as a condition.

So I'm just wondering if there is any amount of concentration issues that at any point that you'd -- you think you might run into?

Okay.

And this is Martin.

I would say on the E15, it really doesn't impact our ethanol production thought process any, go along with what Jason said on that, it's going to be a slow and very measured penetration into the market here in the United States.

So it really doesn't impact how we're looking at things.

As far as future acquisitions, we keep looking at them.

We're still -- I mean, the largest producers are still only 11%, 12% of the market space in the United States.

So it's probably not an issue.

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

If I could ask 2 quick ones.

Firstly, just on cash from ops.

It looks like in addition to the working capital drag, there was an additional $200 million of a cash drag that wasn't explained in the press release.

I was wondering if you could provide any commentary around that?

And then secondly, just on gasoline demand growth, I know you referenced 1% growth kind of year-to-date, but it seems like that growth has been moderating a bit over the past couple of months.

Are you seeing a similar trend?

You want to take that one first.

Hey, Jason.

Oh, yes, let's take the second one first.

Gasoline?

Okay, yes, so on gasoline demand, I will tell you that the only real visibility we have to that is through our wholesale channel.

Quarter-over-quarter, our volumes were up 5%.

So our wholesale volumes were -- grew at better than the demand growth.

We did see slight reduction in volume from the second quarter to third quarter, only about 1%, but we really attributed to that.

It looked like most of where we lost demand was in the Southeast and was storm related.

And on the question about the remaining cash usage, we made a contribution to our pension plans in September about $100 million and the rest of this is just a lot of miscellaneous items.

And our final question comes from the line of Matthew Blair with Tudor, Pickering, Holt.

Coming back to Prashant's question on WCS, you mentioned that we should expect a small near-term increase in rail volumes.

I was wondering have you made any pipeline commitments on the future pipes like L3R, KXL or the Trans Mountain expansion?

Yes.

This is Gary.

We don't have any pipeline commitments, though we do have some arrangements with producers where we would buy barrels in the Gulf when those pipelines are done.

Okay.

And then on the West Coast, we saw a pretty expensive ANS barrels in Q3.

And then I think, today, we're back to a premium versus Brent.

Any color on what's going on with ANS?

Yes.

I think that the West Coast market was actually the most impacted by some of the volume slowdown from the Middle East.

Some of the Saudi barrels and Kuwaiti barrels that went out to the West Coast kind of took pressure off the ANS.

So as we see the Saudi volume ramped back up and more of those barrels making their way to the West Coast, I think it takes some of the pressure off of the ANS.

Thank you, and that does conclude today's Q&A session, and I'd like to return the call to Mr. John Locke for any closing remarks.

Thanks, Sandra, and thanks everybody for calling in this morning.

If you have an additional questions, please contact the IR team.

Thank you.

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

This does conclude the program, and you may all disconnect.

Everyone, have a great day.