Good day, ladies and gentlemen, and welcome to the Third Quarter 2018 Valero Earnings Conference Call. At this time, all participants are in a listen only mode. Later, we will conduct a question and answer session and instructions will follow at that time. 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 Valera Energy Corporation's Q3 2018 earnings conference call. With me today are Joe Gorder, our Chairman, President and Chief Executive Officer Donna Tietzman, 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 1 on our website atvalero.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 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 3rd 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 Q3 of last year despite a margin environment that was generally less favorable. Our use of the Diamond Pipeline in Enbridge Line 9B again contributed meaningfully to the performance of our Memphis and Quebec 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 displace 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 $975,000,000 Upon completion in 2022, the refinery will have 2 parallel crude vacuum coker trains. The additional coker capacity is expected to improve turnaround efficiency and provide margin benefits from increased heavy sour crude processing capability and reduced intermediate feedstock purchases. Earlier this month, we agreed to acquire 3 ethanol plants from Green Plains with a total nameplate capacity of 280,000,000 gallons per year at a cost of $300,000,000 plus working capital estimated at $28,000,000 These plants utilize ICM and Delta T Technologies and 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 Q4 of 2018 subject to customary closing conditions and possible FTC review.
Construction of the Central Texas pipelines and terminals in 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 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 unitholders. This transaction offers compelling benefits for Valero shareholders in terms of cash flow synergies and 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 funded dropdown 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 Q4 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 remain near 5 year lows. And with that, John, I'll hand the call back to you.
Thank you, Joe. For the Q3, net income attributable to Valero stockholders was $856,000,000 or $2.01 per share compared to $841,000,000 or $1.91 per share in the Q3 of 2017. Operating income for the refining segment in the Q3 of 2018 was $1,300,000,000 compared to $1,400,000,000 for the Q3 of 2017. The $90,000,000 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 Q3 of 2018 averaged 3,100,000 barrels per day and throughput capacity utilization was 99%.
Throughput volumes were 207,000 barrels per day higher than the Q3 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 Q3 of 2017, primarily due to higher throughput in the Q3 of 2018. The ethanol segment generated $21,000,000 of operating income in the Q3 of 2018 compared to $82,000,000 in the Q3 of 2017.
The decrease of $61,000,000 was mainly due to lower ethanol prices in the Q3 of 2018. Operating income for the VLP segment in the Q3 of 2018 was $90,000,000 compared to $69,000,000 in the Q3 of 2017. The increase of $21,000,000 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 Q3 of 2018, general and administrative expenses were 209,000,000 dollars and net interest expense was $111,000,000 Depreciation and amortization expense was $517,000,000 and the effective tax rate was 24%. With respect to our balance sheet at quarter end, total debt was $9,100,000,000 and cash and cash equivalents were $3,600,000,000 of which $128,000,000 was held by VLP.
Valero's debt capitalization ratio net of $2,000,000,000 of cash was 24%. At the end of September, we had $5,300,000,000 of available liquidity excluding cash, of which $750,000,000 was available for only VLP. We generated $496,000,000 of cash from operating activities in the Q3. Included in this amount is a $729,000,000 use of cash to fund working capital. Excluding working capital, net cash provided by operating activities was approximately 1,200,000,000 dollars Moving to capital investments, which excludes acquisitions, we made $604,000,000 of growth and sustaining investments in the 3rd quarter.
Sustaining investments of $435,000,000 include $171,000,000 of turnaround and catalyst costs. The balance of capital invested in the quarter was for growth. With regard to financing activities, we returned $775,000,000 to our stockholders in the Q3. Dollars 341,000,000 was paid as dividends with the balance used to purchase 3,800,000 shares of Valero common stock. As of September 30, we had approximately $2,800,000,000 of share repurchase authorization remaining.
We continue to expect 2018 capital investments to total $2,700,000,000 with about $1,700,000,000 allocated to sustaining the business and $1,000,000,000 to growth. Included in this total are turnarounds, catalysts and joint venture investments. For modeling our 4th quarter operations, we expect throughput volumes to fall within the following ranges: US Gulf Coast at 1,760,000 to 1,810,000 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 per day. We expect refining cash operating expenses in the 4th quarter to be approximately $3.80 per barrel. Excluding the acquisition of the 3 ethanol plants from Green Plains, which is expected to close in the Q4, our ethanol segment is expected to produce a total of 4,100,000 gallons per day in the 4th quarter. Operating expenses should average 0 point $3 the annual effective tax rate to be about 23%.
For the
Q4, we expect G and A expenses, excluding corporate depreciation to be approximately $220,000,000 Net interest expense is estimated at $110,000,000 and total depreciation and amortization expense should be approximately $525,000,000 Lastly, given recent declines in ethanol and biodiesel RIN cost, we are reducing expected RINs expense for the year to between $450,000,000 $550,000,000 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 and 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.
You. And our first question comes from the line of Roger Read with Wells Fargo. Your line is now open.
Yes. Thanks. Good morning and nice quarter as usual.
Thanks, Roger.
Joe, if we could, one thing you didn't talk about in the overview, but it's certainly very topical here, the IMO 2020 thought process. So story comes out, administration doesn't like it, no surprise there, but the IMO is 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 in how you're looking at the potential impact about this time next year into early 2020?
No, 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 is going on all week in London. And I'm sure you all have experienced the same as we have. It's a closed meeting, so information trickles out in 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 will 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 enforce the new specs. You don't have to prove the ship burned non compliant fuel.
They just have to look and see just having it in the fuel tank on board is a breach of the regulation, of
course, unless the ship has a scrubber.
That's going to be help a lot with maintaining compliance. The second bit of good news relates to this experience building phase proposal that has caused quite a bit of commotion and that's what was referred to in that last return article. Now exactly how this proposal was worked with woodwork 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 get passed at least a potential delay or watering down 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 will be nothing about a phase in or initially relaxed enforcement. So our main takeaway so far is that the committee seems to remain firm and it's a commitment to fully implement the spec change on January 1, 2020 and to make sure the right enforcement tools are available.
Great. Thanks. 2nd unrelated question, you've got 2 acquisitions coming at you 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 this particular period with the acquisitions or we think about the acquisitions as a balance sheet event and the CFFO is the normal process?
Yes, Roger. No, it's another good question. And we've been very consistent in
our messaging and 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, it's under development. We got the Alky's, 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 acquisitions, 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 with what we've done in the past.
Awesome. Thanks.
Okay, buddy.
Thank you. And our next question comes from the line of Paul Cheng with Barclays. Your line is now open.
Hey, guys. Good morning.
Hi, Paul.
I have to apologize that 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 DC and in the White House and all. I know Joe met with President Trump for a number of times. Can you give us some insight that what exactly the Whitehall is trying to do or that 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 pace or that they are thinking?
Okay. Sure. And I don't think they've come to a conclusion yet. And one thing we should 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 any firm conclusions yet.
They are won't understand the economic impact of the potential changes, but there's nothing yet. Now the word was they were supporting that experience building phase. And in the context or seem to be that it would lead to some type of delay or lacks enforcement upfront, but looks like that was very clearly shut down within the committee. And importantly, we were told the U. S.
Delegation actually supported this conclusion of basically morphing 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 curious that in the conversation you have with the White House staff, does any occasion come out as a new care option saying that U. S. Could even drop out from the ECA destination. Can the President have the authority that just use executive order that you get out if he want to?
It is pretty complicated. I don't think they're having discussions 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 glean, although we're definitely not experts on it. It sounds like he 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 the IMO 2020 sulfur regulation. And that would take 12 months notice. And we're not there's not certainty around whether the Senate would have to approve that or go along with it.
But the point is, if you pull out of the entirety of Annex VI, which is the narrowest thing you could deal with, that covers all of the international marine air pollution requirements. So the ramifications would go way beyond the IMO sulfur, the 2020 regulations. So 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 into 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.
Thank you. My second question that maybe is for either Gary or Lynn. Meyer, seems like it's being mispriced very expensive. Do you find that it's attractive for you to run it now or that you can have other alternative you would be able to find this far more attractive. Are you running it at all?
And then maybe as a sign off, 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 real P or logistic result on a separate item? Thank you.
Thanks, Paul. Yes, Paul,
I'll take Maya question. Certainly, the volatility between Brent and WTI and the Midland Cushing spread along with fuel getting strengthened has wreaked havoc on the Maya formula. And so we would certainly say that Maya is not priced competitively in the market today. We 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 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 of Maya.
And today, Canadian heavy barrel in the U. S. Gulf Coast has an $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 4 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.
Thank you.
Okay, buddy.
Thank you. And our next question comes from the line of Doug Terreson with Evercore ISI. Your line is now open.
Good morning, everybody.
Hi, Doug.
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 two 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 expected it 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 just very high refinery utilization.
So year to date, we've averaged 93% refiner utilization, 2.6% higher than where we were last year. With that increase in refinery utilization, gasoline production is up about 2% over where it was last year. And even though you've had an increase in demand, you've had about a 2 to 1 increase in production over demand is caused the surplus in inventory build. As we move into the Q4, 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 swell 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 1,000,000 barrels a day of gasoline being exported. In our system, we're seeing very strong South American demand. 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 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 hydro data I looked at, it looks like Northwest Europe hydro skimming margins have turned negative. 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, the hydro skimming refinery, if you don't have an 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 drop 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 indication that you're getting some run cuts that are starting to pressure down the front part of that Brent curve.
Can you spend just a second on distillate as well?
Yes. So distillate, I think, if you look at where distillate inventories look both on an absolute basis and certainly on a days of supply basis, we're very low. We really just haven't been able to replenish distillate inventories 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 more 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 skimming refiners and some refinery run cuts, that will even be more supportive to distillate market as well because you'll take some of the distillate production offline as well.
Sure. Thanks a lot guys.
Thanks Doug.
Thank you. And our next question comes from the line of Doug Leggate with Bank of America Merrill Lynch. Your line is now open.
Thanks. Good morning, everybody. 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 question earlier about the White House and so on, our understanding is that it's really the enforcement is really down 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 a kind of workaround? I'm just trying to think about how the rule making evolves over the next 12 months. Any thoughts you might have on that would be appreciated.
Yes. 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 would be involved is stuff 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, right, where it's coming to or 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 would 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, Our understanding Our understanding is that there's a broad consensus, European let's face it, this is the best thing to happen to European refineries in 20 years. There's an expectation utilization is going to go up at the same time as a lot of U.
S. Light sweet crudes 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 it a 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 on the distillate side? And I'll leave it there.
Thanks.
Thanks, Doug. Yes, I think the way you characterize it is very similar to the way we see it. I think it looks like for the next several months, certainly Q1 Q4 through Q1, gasoline market is going to remain weak. And certainly as European refiners run more of the U. S.
Light sweet crude, you had the potential to put more gasoline on the market. And then it's really when you start getting into the Q4 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, the 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. No, 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 into marine diesel. But if we are 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.
All right. A lot of moving parts. Thanks, fellows. Appreciate the answers.
Thank you. And our next question comes from the line of Benny Wong with Morgan Stanley. Your line is now open.
Hi, good morning. Thanks guys.
I was
wondering if you could share some thoughts around your CapEx plans next year now with the logistics business rolled up 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 the allocation split, how that will evolve with the new business structure?
Yes. 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 the last couple of years, it's been sort of in this fifty-fifty 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.
Okay, thanks.
Thank you. And our next question comes from the line of Manav Gupta with Credit Suisse. Your line is now open.
Hey guys, 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 Cubic City benefiting from the light, light 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 TIR and really it's our Line 9 reversal that we invested in and all the access to the sort of 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 to the price of those crews, 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 a 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 in October 11, the White House announced they were going to direct the EPA to start a rulemaking to get the E15 RVP waiver in place for next summer. And this something 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's risk to engines that aren't warranted for the fuel, who's liable for it 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 1400 stations. And when you figure out what will it take to offer E15, there's 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. There's going to have to be some capital spend.
And that brings us to the legality of this rule. 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 E-ten 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 suing lots of 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 in the shoes of one of these retailers who's got to spend money to be able to offer E15.
Now are you 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 chilling effect on the capital rollout, which will keep things keep the rollout from being very aggressive along with just the general problems with E-fifteen we talk about a lot.
Thank you, guys. This was very insightful. Thank you.
Thank you.
Thank you. And our next question comes from the line of Prashant Rao with Citigroup. Your line is now open.
Good morning. Thanks for taking the question.
You bet.
Just wanted to circle back on the pad one, the Atlantic Basin. As part of that, I appreciate the color on what the strength there was. I wanted to just sort of drill down on the product side, you've been able to get your distillate yields up, gasoline volumes down, obviously optimizing to the dynamics there. But just wanted to get an understanding of if there's anything on the product pricing side or moves you've been able to do in that market that they're also helping the realized 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 Quebec refinery, the way we have that refinery configured, it makes have a very high distillate yield for the kind of crews 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 has sort of been outperforming the gas crack here of late. So when you think about that asset base going forward, that's really one of the big drivers for that performance in that area is Quebec's distill yields.
Okay. Thanks. And I guess my follow-up, also not an IMO question, but wanted to ask about Western Canadian heavy and near term and then maybe looking to 2019 plans to getting more WCS down into the Gulf Coast, particularly with Lake Charles. I was we've been hearing a lot about rail ramp and incremental transport volumes. I just wanted to see if
you had any color there
or an 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 see that market constrain. We're certainly ramping up our rail volume some. We did about 30,000 barrels a day in the Q3.
We expect to get that up to 40,000 barrels a day in the Q4. And then it looks like there's 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 that would happen would be
Thank you.
Thank you. And our next question comes from the line of Brad Heffern with RBC Capital Markets. Your line is now
open. Hey, good morning, everyone.
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 are available to you. And then additionally, you mentioned in your prepared comments that there would 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 then we'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 whenever we did a project at VLP or at 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 enable us to provide the MLP investor with a clear line of sight to ratable growth. We had a sub-three percent yield on VLP's equity and we were executing Then the MLP market's appetite changed significantly from a dropdown 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 are 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 in. VLP unitholders get a premium to the average trading in the market and VL O stockholders get an accretive transaction.
So it was a win win, which are very hard to find and it dealt with a problem we've got or that we 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 looked at. So a lot of talk in the market had been about eliminating the IDRs. Unfortunately, that doesn't solve the underlying issue with being able to fund to the 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 with the best solution for both the junior holders and the shareholders of Valero.
Brad, it's interesting in 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've had to do it differently. So anyway, we think we made the right decision and the timing was such that we were able to execute it now and we decided to go ahead and do it.
Okay.
And then any quantification of the synergy benefit?
They're coming from a lot of different places. Obviously, the leakage from the unitholder public unitholder distribution is a large piece of that. The public company cost is another piece of that. And just a simplified structure cuts a lot of the administrative costs out of the equation.
Okay. Appreciate the thorough answer.
Thank you. And our next question comes from the line of Peter Lowe with Redburn. Your line is now open.
Hi, thanks for taking my questions. The first one is just on the hi. The first one is just on the ethanol acquisition. Can you give us some more color on the strategic rationale behind that and perhaps whether you look to do more deals in the biofuel space in the future? And the second was just a quick one.
In the release, you talk about a $700,000,000 working capital build. Is that simply the impact of rising oil prices? So should we expect it to unwind in future quarters? Thanks.
Sure. On the ethanol, this is Martin. 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.
We took it. We see corn ethanol as the most competitive octane source in the world. We expect ethanol demand to grow globally. If you look at exports, they have about 30% year on year for the last 3 years. Exports will be 10% of production this year.
And you also see domestic production, it's been growing at about 3.6 percent a year. This year, that growth is going to slow to something 1%, 1.5%. So that big increase in production slowing down. So we think things are going to start improving on the supply demand balance and what that will get some margin 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 good and we took it. Now in the future, we'll continue to look in this space. And then the other thing we're obviously looking at in the biofuels is what Joe mentioned, the decision on the Diamond Green Diesel 2 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. It was quite a big build in the quarter, about $700,000,000 I was just wondering, was that simply an effect of rising oil prices? So should we expect that kind of unwinds over the next few quarters?
So that was a combination of some volume and some price impact and there should be a fair portion of that, that will reverse itself.
That's great. Thanks.
Thank you. And our next question comes from the line of Neil Mehta with Goldman Sachs. Your line is now open.
Good morning, team. 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 it? How should we think about it either on a IRR basis or incremental EBITDA for the capital that you're spending there?
Hi, Dylan. It's Blayne. So really the benefits are twofold. One is the feedstock flexibility. There was an earlier caller that asked a question around how do our view of Canadian heavy sour in the Gulf Coast.
And we certainly have a longer term view that there's 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 like to benefit from the feedstock flexibility. And secondly, is 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's a lot of synergies in having this additional to essentially finally separate this refinery into 2 separate trains and be able to execute turnarounds in a more efficient manner.
With respect to EBITDA, I'd characterize that we think the EBITDA is around $325,000,000 using mid cycle prices and I'm going to preface that by saying that mid cycle doesn't 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 $325,000,000 in a mid cycle case, then it's got a lot of upside in an IMO 2020 universe.
I appreciate that, Elaine. 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 a 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?
Daniel, this is Gary. I think we see with the startup 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 pad 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 and back to 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. Thanks, team.
Thank you. And our next question comes from the line of Paul Sankey with Mizuho. Your line is now open.
Hi, good morning, everyone. 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's roughly 3,500,000 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. So you and essentially, although you said that the Coker project is not IMO related, I guess you're expecting essentially the IMO change to go through at considerable scale basically?
Paul, this is Lainelle. We do believe IMO will go ahead. I think that's our view, but we didn't fund or we didn't do this project because of IMO 2020. We see a lot of upside. Yes.
So is it then based on 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 was just given the VLP take back, could you keep going and actually buy MLPs now? Is that a thought? Thanks.
Okay. So mid cycle is just the way we define a mid cycle. It's sort of the average the last average of the last 10 years sort of pricing scenario. So 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 Brent TI blow out a few years ago out to 30, we throw that out for any what we consider to be a mid cycle. So that's how we price that.
Paul, you got a follow-up for later?
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 dropped the assets to VLT. 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 feedstocks into the refinery and more access to markets with products moving out. And to the extent that there's an opportunity out there that scratches those one of those 2 inches 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 at saying, gee whiz, we need to go now roll up MLPs.
Understood. Thank you, Jeff.
Take care, Paul.
Thank you. And our next question comes from the line of Craig Shere with Tuohy Brothers. Your line is now open.
Good morning.
Hi, Craig.
Could you all walk through timelines 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. Well, as far as timeline
Yes. As far
as timeline, we acquired the terminal, it's operational. There's a second terminal. Peru. That's Peru, I'm sorry. And there's a second terminal in the northern part Peru that we are in the process of reactivating and that should be Q1 of next year.
So we'll have over a 1000000 barrels of receipt facilities in Peru. In Mexico, the Veracruz terminal, which is about 2,100,000 barrels of storage, should be in service. The end of this year, early Q1 of 2020. And then the inland terminals, which combined between Puebla and Mexico City should be the end of 2020, Q1 of 20 21.
Okay. So that's that. 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. 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 Tourmal Crew, let's and we bought an entire business.
So Gary is running not only we got the Tourmaline operation, but we've got a marketing business that was associated with that. And it takes a while 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 do 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.
Great. Thank you.
You bet.
Thank you. And our next question comes from the line of Phil Gresh with JPMorgan. Your line is now open.
Yes. Hi, good morning. Just a couple of clarifying questions or follow ups. First one would be, obviously, between the ethanol plants and the growth opportunities and 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, yet, 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 happen to have a 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 'nineteen, I think we've generally provided ranges that we thought were 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 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 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. And when we finally concluded that we had basically a broken equity out there and that BLP wasn't going to do for BLO 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.
Yes. Okay. Fair enough. Just the second question is just on the throughput guidance for the 4th quarter. 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. But 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 Laine. 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's comments earlier around where margins are, are predominantly we see a weak Northwestern Europe hydro skimming margins and Mediterranean hydro skimming 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 where how that affects our I know how to in reality what our throughput is, but at the time we gave this guidance, that was kind of how we saw the universe for the next 3 months.
Okay, thanks.
Thank you. And our next question comes from the line of Chris Sighinolfi with Jefferies. Your line is now open.
Hey, good morning. Thanks for all the added color guys. Two quick follow ups, if I could. Obviously, there's been some questions on capital allocation. Realize you're not deviating from your historic 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? It seems like obviously organic investments, acquisitions provide some opportunity for capital deployment. The share price has 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%, so the lower half of that. We have a large cash balance today to fund a lot of the things that we're talking about as well as some borrowing capability.
Okay. So no change in that, I feel comfortable with it. Okay. Also following up on the E15 question, appreciate the market views. They're very helpful.
But I'm just curious how the 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 federal review of the Green Plains plant acquisitions as a condition. So I'm just wondering if there's any market concentration issues at any point that 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 that we keep looking at them, It's 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.
Okay, great.
Thanks a
lot for the eye color guys.
Thanks, Chris.
Thank you. And our next question comes from the line of Jason Gabelman with Cowen. Your line is now open.
Yes. Hey, guys. How's it going? 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 $200,000,000 of 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?
Thanks.
Hey, Jason. Oh, yes. Let's take the second one first.
Gasoline.
Okay. Yes. So on gasoline demand, I would 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 you know, our wholesale volumes were grew at better than the demand growth.
We did see slight reduction in volume from the Q2 to Q3, 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.
Got it.
And on the question about the remaining cash usage, we made a contribution to our pension plans in September about $100,000,000 and the rest of it is just a lot of miscellaneous items.
All right, great. Thanks a lot.
Thank you.
Thank you. And our final question comes from the line of Blair with Tudor, Pickering, Holt. Your line is now open.
Hey, good morning, everyone. Coming back to Prashant's question on WCS, you mentioned that we should expect a small near term increase in rail volumes. But 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, but we do have some arrangements with producers to where we would buy barrels in
the Gulf when those pipelines are done. Okay.
Okay. And then on the West Coast, we saw pretty expensive A and S barrels in Q3. And then I think today we're back to a premium versus Brent. Any color on what's going on with A and S? 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 A and S. So as we see the Saudi volume ramp back up and more of those barrels making their way to the West Coast, I think it takes some of the pressure off of A and S.
Great. Thank you.
Thank you. And that does conclude today's Q and 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 any 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.