Good day, ladies and gentlemen, 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. If anyone should require assistance during the call, you may press star then zero on your touchtone telephone to speak with an operator. I would now like to introduce your host for today's call, Mr. John Locke. Sir, you may begin.
Good morning, 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 actual results to differ from our expectations, including those we've described in our filings with the SEC. 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 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 1st. 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 million. Upon completion in 2022, the refinery will have two 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 three 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 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 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 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 drop-down model to a model that favors slower distribution growth and self-funded organic growth.
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%-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 remain near five-year lows.
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 five 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 the 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 a $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 are turnarounds, catalysts, and joint venture investments.
For modeling our fourth quarter operations, we expect throughput volumes to fall within the following ranges: U.S. Gulf Coast at 1.76 million-1.81 million barrels per day, U.S. Midcontinent at 440,000-460,000 barrels per day, U.S. West Coast at 265,000-285,000 barrels per day, and North Atlantic at 480,000-500,000 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 three ethanol plants from 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 non-cash 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 recent declines in ethanol and biodiesel RIN costs, we are reducing expected RINs expense for the year to between $450 million and $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 two questions. If you have more than two questions, please rejoin the queue as time permits. This helps us ensure other callers have time to ask their questions.
Thank you. Ladies and gentlemen, if you have a question at this time, please press star and then one on your touchtone telephone. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. To prevent any background noise, we do ask that you please place your line on mute once your question has been stated. Our first question comes from the line of Roger Read with Wells Fargo. Your line is now open.
Yeah, thanks. Good morning. Nice quarter as usual.
Thanks, Roger.
Joe, if we could, one thing you didn't talk about in the overview is certainly very topical here, the IMO 2020 thought process. Story comes out, Administration doesn't like it, no surprise there. The IMO's meeting this week. Can you talk about maybe 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 y'all have been following that meeting you just referenced. The Marine Environment Protection Committee's meeting is going on all week in London. I'm sure y'all have experienced the same as we have. It's a closed meeting, so information trickles out in dribs and drabs at different times. This is what we've gleaned from it, from what we've been able to ascertain. Looks like there's been two 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 1st, 2020. There was a proposal, I believe, by Bangladesh to delay it that was defeated, and it'll be officially voted on either today or tomorrow to lock it in.
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 noncompliant 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 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 The Wall Street Journal article. Exactly how this proposal 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 be a path that leads to a potential delay or watering down of the standards. 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. There would be nothing about a phase in or initially relaxed enforcement. Our main takeaway so far is that the committee seems to remain firm in its commitment to fully implement the spec change on January 1st of 2020 and to make sure the right enforcement tools are available.
Great, thanks. Second unrelated question. You've got two acquisitions coming at you this quarter, the ethanol and the VLP deal. How should we think about the 40%-50% payout of cash flow in terms of dividends and share repos relative to the commitments this particular period with the acquisitions? We think about the acquisitions as a balance sheet event and the CFFO as the normal process.
Yeah, Roger. That's another good question. We've been very consistent in our messaging and our execution around our capital allocation framework. Really what we're talking about here is the discretionary uses. There's no consideration of affecting our maintenance CapEx or turnarounds or the dividend in a negative way. This really is focused on the discretionary uses. 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 got the Alky units, 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, then we've got the ethanol plants, which Martin can talk about here in a bit. We were able to buy ethanol plants in a down market. When we're looking at acquisitions, that's always what we're trying to do. Then on the repurchases, we've got the payout ratio, which is overriding. We've been very ratable in our acquisition of our shares, and we're focused on buying dips. 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.
Thank you. 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 the first question is somewhat similar to what Roger just asked on the IMO. I want to focus that, Jason, you guys have a lot of contact in D.C. 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 White House trying to do, what is the proposal they have in mind in terms of slow down the rollout? What kind of mechanism or what kind of program that they have in place or that they are thinking?
Okay. Sure. I don't think they've come to a conclusion yet. 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's reached any firm conclusions yet. They are wanting to understand the economic impact of the potential changes, there's nothing yet. The word was they were supporting that experience building phase, in a context or it seemed to be that it would lead to some type of delay or lax enforcement up front. Looks like that was very clearly shut down within the committee. 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. I think it's an ongoing discussion.
They don't have a firm commitment yet or a firm position yet, they're just trying to understand the situation.
Jason, just curious that in the conversation you have with the White House staff, has any occasion come out as a new care option, saying that U.S. could even drop out from the ECA designation? Can the President have the authority that just use executive order that to get out if he want to?
It is pretty complicated. I don't think they're having discussions about that yet, anything that extreme. We've tried to understand this. It's very complicated, this international kind of treaty law, 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 this IMO 2020 sulfur regulation, that would take 12 months notice and there's not certainty around whether the Senate would have to approve that or go along with it. 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.
The ramifications would go way beyond the IMO sulfur, the 2020 regulations. It wouldn't be taken lightly by the administration, it would have ramifications way beyond that spec. I think it would take a lot of thinking and see if they want to do that. 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. Even if the President withdrew from the treaty, the statutes can't be changed except by an act of Congress. They would still be in place. 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 Lane. Maya seems like it's being priced 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 is far more attractive? Are you running it at all? Then maybe as a sign though, 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? Thank you.
Thank you, Paul.
Yeah, Paul, I'll take your Maya question. Certainly the volatility between Brent and WTI and the Midland Cushing spread, along with fuel oil getting strengthened has wreaked havoc on the Maya formula. So we would certainly say that Maya is not priced competitively in the market today. We had several conversations with PMI. I think they are well aware that their barrels are not being priced competitively into the U.S. Gulf Coast, 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.
Today, Canadian heavy barrel in the U.S. Gulf Coast has an $8-$10 advantage over Maya. We still see a good incentive to push heavy sour crudes into our refining system. I would agree, Maya is not priced competitively today.
I guess the next question was, Paul, your fourth-
Yeah
was relative to-
The segment reporting question.
Yeah.
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. 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. Net exports for both seem to be pointed in the right direction. My question regards really demand trends in the domestic and the regional markets that you guys are involved in for these two products. 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. Just kind of an overview on gasoline and distillate, please.
Sure. This is Gary. I think basically demand is 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.
Yeah
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% over where it was last year. Even though you've had an increase in demand, you've had about a 2 to 1 increase in production over demand. It's caused a surplus in the inventory build. As we move 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. 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.
Yeah.
I think there are a few bullish signs in the gasoline market. Inventory has actually drawn 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 three 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. When you look at gasoline inventory on a days of supply basis, and you take those exports into account, we are about the five-year average range on a current days of supply. On the supply side, it looks like we could be getting some help as well.
The last set of Haver data I looked at, it looks like Northwest Europe hydrodesulfurization margins have turned negative.
Yeah.
Even conversion refinery economics are about break even. In the U.S., we're seeing very tight margins on reformers and cat crackers. Even in the U.S., a hydrodesulfurization refinery, if you don't have an advantage crude supply, those economics are getting challenged as well. 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. I think you're starting to see some indications of some run cuts in the industry as well.
Yeah.
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.
Okay. Can you spend just a second on distillate as well?
Yeah. Distillate, I think, if you look at where distillate inventories look both on an absolute basis and certainly on a days of supply basis-
Yeah
we're very low.
Yeah.
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. Again, on the distillate side, I think if you do get some hydrodesulfurization refineries and some refinery run cuts, that'll even be more supportive to the 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. 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.
Morning, Doug.
Joe, I'm sorry, my first one's an IMO question as well. 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 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 as one method of a kind of workaround? I'm just trying to think about how the rulemaking evolves over the next 12 months. Any thoughts you might have on that would be appreciated.
Yeah. No, you're right. That's a key component. Historically, the U.S. has been one of the most zealous enforcers of MARPOL through the Coast Guard and the EPA. You 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. 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. Wherever that ship's the other end of the voyage, 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.
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. 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 whoever wants to chime in. Our understanding is that there's a broad consensus. 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 crude is 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?
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? I'll leave it there. Thanks.
Thanks, Doug.
Yeah. 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 fourth quarter through first quarter, gasoline market's going to remain weak. Certainly as European refiners run more of the U.S. light sweet crude, you have the potential to put more gasoline on the market. 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.
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.
The perception is that diesel margins spike on the back of a swing away from high sulfur fuel oil into marine diesel. If we're cutting back cat feed on weak gasoline markets, doesn't that solve part of the problem?
Yeah, I think, most of the forecasts 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, fellas. Appreciate the answers.
You're welcome.
Thank you. 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 load up and the Coker spend, particularly on the growth side and how that looks between your business segments. If you may, longer term, just any thoughts around the allocation split, how that will evolve with the new business structure?
Yeah. 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 50/50 allocation logistics and refining. We 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. 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 Quebec City benefiting from the light spread? Any color you can provide on the very strong results on the North Atlantic region.
Hey, Manav, this is Lane. Really what you saw in our North Atlantic strong crack attainment was our exposure to this wide Brent/WTI, and really it's our Line 9B reversal that we invested in. Getting all the access to the distressed Canadian crudes coming out of that region of the world. That was really what drove us, not only to have exposure to the price of those crudes, but also to run a little bit more rate as a result of that.
One follow-up, sir. E15 was recently announced by Donald Trump. There were some concerns that it might eat up into a small portion of the gasoline demand. 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. If you could give some color on that also, please.
Sure. We'll let Jason talk to you a minute about that.
Yeah. No, you're right. Back on October 11th, 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. This is 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. First of all, there are lots of reasons E15 hadn't taken off already. 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. There's only about 1% of the stations in the U.S. have E15 now, about 1,400 stations.
When you figure out what will it take to offer E15, there's varying questions. Basically, you have to spend some money. You have to spend a lot of money or a little money, kind of depending on the configuration of your station. There's going to have to be some capital spend. 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. Some people think they do. 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. One thing that's certain is whenever the EPA rule goes final, there's going to be a bunch of people sue them.
Lots of lawsuits challenging the EPA's authority to do this. It's going to take a couple of years for that to work its way through the courts before you get a final answer. 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, a court may void it?
I think that's going to have some type of a chilling effect on the capital rollout, which will keep the rollout from being very aggressive, along with just the general problems with E15 we talk about a lot.
Thank you, guys. This was very insightful. Thank you.
Thank you.
Thank you. 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 PADD 1, 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 and you've been able to get your distillate yields up, gasoline volumes down, obviously optimizing to the dynamics there. 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 are 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 has a very high distillate yield for the kind of crude that it runs. Anytime you get into a market where the gasoline crack is depressed in relation to the heat crack, that refinery will perform very well. As we all know, the heat crack has sort of been outperforming the gas crack here of late. 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 distillate yields.
Okay, thanks. I guess my follow-up, also not an IMO question, but wanted to ask about Western Canadian heavy and short near term, then maybe looking to 2019 plans to getting more WCS down into the Gulf Coast, specifically at Lake Charles. We've been hearing a lot about rail ramps 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 coke decision.
This is Gary. I think, in the short term, really you're going to depend on rail to clear the production in Western Canada, I think you'll continue to see that market constrained. 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. Then it looks like there's some additional rail being dedicated to that market early next year. 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. 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 late next year.
Okay. Thanks very much, gentlemen.
Thank you.
Thank you. 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 were available to you. 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.
Yeah, you bet. I'll take the first part, and then we'll let Donna take the second part. 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. 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? 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 3% yield on VLP's equity, and we were executing as promised.
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. The cost of capital was also higher than that at VLO. We looked at this for a year or more. We were very patient. We watched carefully for any catalyst change that would support a shift back to our original design, and we saw none. 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 unit holders get a premium to the average trading in the market, and VLO stockholders get an accretive transaction.
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. Donna, you want to take the second piece?
Yeah, in regards to the other options that we looked at.
Yep.
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 growth because you still wouldn't have access to the equity market. Some other options that we've seen MLPs choose are converting to C corp. 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. 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.
We kept coming back to buying it in was the best solution for both the unitholders and the shareholders of Valero.
Brad, it's interesting in that every solution that one might consider is unique to their individual circumstances. 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 would've had to do it differently. Anyway, we think we made the right decision, and the timing was such that we were able to execute it now. We decided to go ahead and do it.
Okay. Then any quantification of the synergy benefit?
They're coming from a lot of different places. Obviously, the leakage from the public unitholder distribution is a large piece of that. The public company cost is another piece of that. Just the simplified structure cuts a lot of the administrative costs out of the equation.
Okay. Appreciate the thorough answer.
Thank you. Our next question comes from the line of Peter Low with Redburn. Your line is now open.
Hi. Thanks for taking my questions.
Oh.
Hi. The first one's 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? The second was just a quick one. In the release, you talk about a $700 million working capital build. Is that simply the impact of rising oil prices? 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? It's a core part of our strategy. The opportunity came up to buy three 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 you look at exports, they're up about 30% year-on-year for the last 3 years. Exports will be 10% of production this year. You also see domestic production that's been growing at about 3.6% a year. This year, that growth is going to slow to something 1%, 1.5%. That big increase in production is slowing down.
We think things are going to start improving on the supply-demand balance, and with that, we'll get some margin improvements. We're always looking at acquisitions. Our last one was in 2014 for ethanol, and it just became an opportunity that looked good and we took it. In the future, we'll continue to look in this space, the other thing we're obviously looking at in the biofuels is what Joe Gorder mentioned, the decision on the Diamond Green Diesel 2. That'll be coming up before the end of the year. That's it.
Peter Low, you were asking about working capital?
That's right.
What was your question again? Sorry, just repeat it.
It's quite a big build in the quarter, about $700 million. I was just wondering, was that simply an effect of rising oil prices? Should we expect that kind of unwinds over the next few quarters?
That was a combination of some volume and some price impact, there should be a fair portion of that that will reverse itself.
That's great. Thanks.
Thank you. 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, Neil. This is Lane. Really, the benefits are twofold. One is a feedstock flexibility. There was an earlier caller that asked a question around our view of Canadian heavy sour in the Gulf Coast, and we certainly have a longer-term view. There's going to be a considerable amount of heavy sour in the Gulf Coast, in addition to that, just our overall sort of how that fits into our optimization of our Gulf Coast. We like the benefits from the feedstock flexibility. Secondly is turnaround efficiency. Today, this is almost a two-train refinery with the exception of a big coker. 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 two 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 was around $325 million using mid-cycle prices, I'm going to preface that by saying that mid-cycle doesn't include IMO. 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 going to make $325 million in a mid-cycle case, it's got a lot of upside in an IMO 2020 universe.
I appreciate that, Lane. The follow-up is just on the Brent-WTI differential. There's two parts to this question. One is how you see that evolving over the next six 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. 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. Can you just talk about how you're evolving the system to capture those inland discounts?
Neil, this is Gary. 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 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. 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.
Back to our system, Sunrise and Diamond and 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. Our next question comes from the line of Paul Sankey with Mizuho. Your line is now open.
Hi, good morning, everyone. 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 3.5 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.
Yeah. 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.
I'd say, Paul, this is Lane. We do believe IMO will go ahead. I think that's our view. We didn't fund or we didn't do this project because of IMO 2020. We just see.
Yeah.
See a lot of other guys.
Right. 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? 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.
I'd say, mid-cycle is just the way we define a mid-cycle. It's sort of the average of the last 10 years sort of pricing scenario. 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-W TI blow out a few years ago out to 30. We'd throw that out for what we consider to be a mid-cycle. That's how we price that.
Sure.
All right. Well, Paul, you got a follow-up for Lane, or?
No, I was going to ask about this idea that maybe you keep going and buy some MLPs.
Well, we've always had that opportunity, quite honestly, right? We could have done it in VLO and then subsequently dropped the assets to VLP. We'll continue to look at them. Here again, I think 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. To the extent that there's an opportunity out there that scratches one of those two itches or both, I think we will really look hard at it. Otherwise, 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, Joe.
You bet. Take care, Paul.
Thank you. 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 the 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. Joe, relating to your last comment, could you opine on the opportunity for additional Latin American infrastructure opportunities post the Peru investment?
All right. As far as timeline.
As far as timeline, we acquired the terminal. It's operational. There's a second terminal.
That's Peru.
That's Peru. I'm sorry. There's a second terminal in the northern part of Peru that we're in the process of reactivating. That should be first quarter of next year. We'll have over 1 million barrels of receipt facility in Peru. 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. The inland terminals, which combine between Puebla and Mexico City, should be the end of 2020, first quarter of 2021.
Okay. That's that. 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?
No.
Okay. 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. We bought an entire business. Gary's running, not only, we got the terminal operation, but we've got a marketing business that was associated with that. It takes a while to get your arms around things and to be sure that we're maximizing the value of it. 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. I think we'll look for opportunities to continue to try to move to the eastern coastline down the road. No specific plans right now.
Great. Thank you.
All right.
Thank you. Our next question comes from the line of Phil Gresh with JP Morgan. Your line is now open.
Yes. Hi, good morning. Just a couple 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, 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. Then, Joe, just generally, 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, we're not deviating from the capital allocation framework. Yes, to answer your question, even though we haven't provided guidance for 2019, I think we've generally provided ranges that we thought were our capital ranges, and we're not deviating from that. Phil, that's not going to change. I would say that the timing of these opportunities. Acquisitions are always opportunistic, so Martin and team did a good thorough evaluation with Rich's team on the ethanol plants, and we had a willing seller. 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. It could have happened in June, right? We wanted to wait and see if the market changed.
When we finally concluded that we had basically a broken equity out there and that 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. That's exactly what we did. It is more coincidental that these things happened at the same time than certainly a sign of things to come.
Yeah. Okay. Fair enough. Just the second question is just on the throughput guidance for the fourth 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 maybe some parts of the world needing to do run cuts. I guess, obviously Valero is a low-cost refiner, so perhaps it's less impactful for you guys. Just wondering how you think about your throughput guidance in the context of the pretty weak gasoline cracks that are out there right now.
Phil, this is Lane Riggs. I think when you think about throughput, it's primarily feedstock and crude, right? At this time, we think our assets are pretty competitive our outlook's not that unchanged minus whatever turnaround activity we have in a particular region. Gary's comments earlier around where margins are predominantly we see a weak Northwestern Europe hydro skimming margins and Mediterranean hydro skimming margins. We are starting to see sort of breakeven economics on conversion units in the entire Atlantic basin. We'll just see how that affects in reality, what our throughput is. At the time we gave this guidance, that was kind of how we saw the universe for the next three months.
Okay, thanks.
Thank you. 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. Just curious how views around leverage are influenced by the recent developments. 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. Can you just remind us or revisit views around sort of consolidated leverage?
Our target for leverage is between 20%-30%, and we're at the lower, at 24%, 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. No change in that. I feel comfortable with it. Okay.
Cool.
Also following up on the E15 question. Appreciate the market views. They're very helpful. I'm just curious how the potential approval of the President's proposal might impact your own ethanol operations, if at all. 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. I'm just wondering if there's any market concentration issues at any point that you think you might run into.
Okay.
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. It really doesn't impact how we're looking at things. As far as future acquisitions, we keep looking at them. The largest producers are still only 11%-12% of the market space in the United States, it's probably not an issue.
Okay, great. Thanks a lot for the IR call, guys.
Thanks, Chris.
Thank you. Our next question comes from the line of Jason Gabelman with Cowen. Your line is now open.
Yeah. Hey, guys. How's it going? If I could ask two 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 cash drag that wasn't explained in the press release. I was wondering if you could provide any commentary around that. Secondly, just on gasoline demand growth. I know you referenced 1% growth 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.
You want to do the second one first?
Oh, yeah. Let's take the second one first.
Gasoline.
Okay. Yeah. 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%. Our wholesale volumes grew at better than the demand growth. We did see slight reduction in volume from the second quarter to the 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.
Got it.
On the question about the remaining cash usage, we made a contribution to our pension plans in September, about $100 million. The rest of it's just a lot of miscellaneous items.
All right, great. Thanks a lot.
Thank you.
Thank you. Our final question comes from the line of Matthew 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. I was wondering, have you made any pipeline commitments on the future pipes like L3R, KXL, or the Trans Mountain expansion?
Yeah, this is Gary. We don't have any pipeline commitments, we do have some arrangements with producers to where we would buy barrels in the Gulf when those pipelines are done.
Okay. On the West Coast, we saw pretty expensive ANS barrels in Q3, I think today we're back to a premium versus Brent. Any color on what's going on with ANS?
Yeah, 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 took pressure off the ANS. As we see the Saudi volumes 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 ANS.
Great. Thank you.
Thank you. 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. 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.