Welcome to the Valero Energy Corporation Reports 2017 Third Quarter Earnings Results Conference Call. My name is Vanessa, and I will be the operator for today's call. Please note that this conference is being recorded. And I will now turn the call over to Mr. John Locke, Vice President, Investor Relations.
Well, good morning, and welcome to Valera Energy Corporation's Q3 2017 earnings conference call. With me today are Joe Gorder, our Chairman, President and Chief Executive Mike Cyszkowski, our Executive Vice President and CFO Lane Riggs, our Executive Vice President of Refining Operations and Engineering Jay Browning, our Executive Vice President and General Counsel and several other members of Valero's senior management team. If you have not received the earnings release and would like a copy, you can find 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 me or our Investor Relations team after the call.
Now I'd like to direct your attention to the forward looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our filings with the SEC. Now, I'll turn the call over to Joe for opening remarks.
Well, thanks, John, and good morning, everyone. What I'd like to do before we discuss our quarterly financial results is to talk about the hurricanes and how proud I am of our Valero team and the energy industry as a whole for the way we responded to these natural disasters. Hurricane Harvey's path touched almost all of Valero's Gulf Coast refineries. It made landfall just northeast of Corpus Christi before proceeding inland to just east of Three Rivers near Victoria. The storm then reversed course short of reaching our headquarters in San Antonio and moved eastward along the Texas Gulf Coast to the Houston, Beaumont, Port Arthur region where it stalled and dumped 50 inches of rain in the span of 4 days before continuing into Louisiana and ultimately moving inland and dissipating.
We shut down our Corpus Christi and Three Rivers refineries prior to Harvey's arrival and reduced rate at our 3 plants in the Houston and Port Arthur area, eventually shutting down Port Arthur due to flooding. Our team worked hard to get these plants safely back up and running, and we only experienced extended delays at Three Rivers and Port Arthur. Hurricane Irma had a less direct impact on our refining operations, but our commercial team and our business partners worked tirelessly to prepare for and restore the supply chain as soon as possible. While our operations have returned to normal, we recognize that people and communities affected by the storm are still recovering, particularly those along the Southern Gulf Coast and in the Houston and Port Arthur areas. In response, Valero provided financial assistance, meals, water, shelter, fuel and other support to employees and their affected communities during the storm and the recovery.
One of the things that I was most encouraged by was the display of the American spirit and our determination to help each other during these times of need. From the efforts of the dedicated employees fighting back the onslaught of torrential rain and rising floodwaters to all those Gulf Coast residents who banded together to rescue their neighbors and help with recovery and cleanup, it was a defining moment. An event like this shows the efficiency of the supply chain in the refining and energy sector, which frankly is not fully appreciated on a day to day basis. To think that the epicenter of the refining industry on the Gulf Coast could take a direct hit from a Category 4 hurricane and keep supply disruptions as short lived as they were was impressive. I applaud our employees, our local, state and federal government officials and all of our business partners who work closely with us on the front lines to return the supply of our fuels to affected communities.
Now despite the hurricane impacts, we're pleased to report another good quarter of results for the company, which John will share with you shortly. Last quarter, I mentioned that we were extending our participation in OSHA's voluntary protection program to more of our facilities. I'm happy to report that our St. Charles and Memphis refineries were awarded star status by OSHA, distinguishing Valero as a refining company with the most OSHA VPP star sites. These are noteworthy achievements for Valero that demonstrate our focus and commitment to safety and reliability.
Moving on to the markets, overall, we're pleased to see margins improving compared to last year. This improvement is primarily due to continued strong domestic and export product demand as well as ample supplies of crude notwithstanding the impact of the OPEC cuts on the medium and heavy sour discounts. Our systems flexibility allowed us to shift our feedstock diet to maximize domestic sweet crudes and capture wider discounts versus bread. We continue to adhere to our disciplined capital allocation strategy and also made progress on our growth investments. We expect to complete the Diamond Pipeline and Wilmington cogen projects within the next 2 months and we're eager to see the incremental earnings contribution from these projects beginning in 2018.
Construction also continues on the Diamond Green Diesel expansion and the Houston Alkylation Unit, and we recently announced the Central Texas Pipeline and Pasadena Marine Terminal Projects. Lastly, with regard to returns to stockholders, we returned $600,000,000 through dividends and stock buybacks in the 3rd quarter. This results in a 58% payout of adjusted cash flow and operating activities year to date. So we're well positioned to exceed our target range of 40% to 50% for the year. So with that, John, I'll hand the call back to you.
Thank you, Joe. For the Q3, net income attributable to Valero stockholders was $841,000,000 or $1.91 per share compared to $613,000,000 or $1.33 per share in the Q3 of 2016. Q3 2016 adjusted net income attributable to Valero stockholders was 571,000,000 dollars or $1.24 per share. For reconciliations of actual to adjusted amounts, please refer to the financial tables that accompany our release. Operating income for the refining segment in the Q3 of 2017 was $1,400,000,000 compared to $934,000,000 for the Q3 of 2016, which has been revised retrospectively to reflect the VLP segment.
The increase from 2016 is attributed primarily to higher gasoline and distillate margins and wider discounts for domestic sweet crudes relative to Brent crude, partly offset by higher premiums for residual feedstocks and narrower discounts for medium and heavy sour crudes versus Brent. Refining throughput volumes averaged 2,900,000 barrels per day, which was 33,000 barrels per day higher than the Q3 of 2016, despite Hurricane Harvey related impacts. Throughput capacity utilization was 92% for the Q3 of 2017. Refining cash and operating expenses of $3.71 per barrel were $0.17 per barrel higher than the Q3 of 2016, mostly due to higher energy costs in the Q3 of 2017. The ethanol segment generated 82,000,000 of operating income in the Q3 of 2017 compared to 106,000,000 in the Q3 of 2016.
The decrease from 2016 was primarily due to lower margins resulting from higher corn and lower distillers grain prices. Operating income for the VLP segment in the Q3 of 2017 was $69,000,000 compared to $56,000,000 in the Q3 of 20 16. The increase from 2016 was mainly due to contributions from the Monroe and Three Rivers terminals and the Red River pipeline, which were acquired in September 2016 and January 2017, respectively. For the Q3 of 2017, general and administrative expenses, excluding corporate depreciation, were $229,000,000 and net interest expense was $114,000,000 Depreciation and amortization expense was $497,000,000 and the effective tax rate was 30% in the Q3 of 2017. With respect to our balance sheet at quarter end, total debt was $8,500,000,000 and cash and temporary cash investments were $5,200,000,000 of which $116,000,000 was held by VLP.
Valero's debt to capitalization ratio net of $2,000,000,000 in cash was 24%. At the end of September, we had $5,100,000,000 of available liquidity excluding cash, of which $720,000,000 was available for only VLP. We generated $1,000,000,000 of net cash from operating activities in the Q3. Excluding the negative impact from a working capital increase of $315,000,000 cash generated was approximately 1.4 $565,000,000 of growth and sustaining capital investments, of which $73,000,000 was for turnarounds and catalysts. Moving to financing activities, we returned $600,000,000 to our stockholders in the Q3, dollars 309,000,000 was paid as dividends and the balance was used to purchase 4,200,000 shares of Valero common stock.
As of September 30, we had approximately $1,600,000,000 of share repurchase authorization remaining. We continue to expect capital investments for 2017 to be $2,700,000,000 with approximately $1,600,000,000 allocated for sustaining the business and $1,100,000,000 for growth. Included in the total are turnarounds, catalysts and joint venture investments. For modeling our Q4 operations, we expect throughput volumes to fall within the following ranges: U. S.
Gulf Coast at 1,650,000 to 1,700,000 barrels per day U. S. Mid Continent at 410,000 to 430,000 barrels per day U. S. West Coast at 265,000 to 285,000 barrels per day and North Atlantic at 465,000 to 485000 barrels per day.
We expect refining cash operating expenses in the 4th quarter to be approximately $3.90 per barrel. Our ethanol segment is expected to produce a total of 4,000,000 gallons per day in the Q4. Operating expenses should average $0.37 per gallon, which includes 0 point per gallon for non cash costs such as depreciation and amortization. We expect G and A expenses, excluding corporate depreciation for Q3 to be around $215,000,000 and net interest expense should be around $115,000,000 Total depreciation and amortization expense should be approximately $495,000,000 Lastly, we expect RINs expense for the year to be between $800,000,000 $900,000,000 And that concludes our opening remarks. Before we open the call to questions, we again respectfully request that callers adhere to our protocol of limiting each turn in the Q and A to 2 questions.
And we have our first question from Roger Read with Wells Fargo.
Hi, thanks. Good morning.
Good morning, Roger.
Joe, I guess, let's dive in on everybody's kind of favorite refining, non refining topic of RINs here. Obviously, some news has flowed through both positive and negative in the last time we talked. And I'm just curious, if we think about there's the rent expense number and then there's obviously some for it for it? And let's assume there isn't going to be a meaningful policy change in the next 12 months.
All right. Well, fair enough. The number that we would share on the actual RIN cost is the $800,000,000 to $900,000,000 So I won't speculate on how it affects the marketing volumes and so on. But what I will tell you is, I think you can see it from the release, we're continuing to invest in assets that allow us to blend more and to export more. So we've got a very strong focus on logistics and on the wholesale market expansion.
Now relative to this policy situation, Roger, this RFS fight is far from over. As you'd expect, those are enjoying this windfall or aggressively defending their positions and we have a counter view. Why don't I let Jason just give you some insights into our perspective on what's occurred and then maybe where we go?
Okay. Yes, this is Jason. You all probably saw this letter Administrator Pruitt sent to these Midwestern senators during the last week about potential changes to RFS that the EPA was looking at. In the letter, he said he decided they weren't going to move the point of obligation, they weren't going to lower the biodiesel volumes under the notice they were looking at and they were going to grant export rents, which is another idea they were looking at. Of course, we're disappointed in how this went down since it looks like political pressure resulted in short circuiting the policy review process.
That's just not good government. It's one thing to have a full balance review of a proposal and decide it's not the right thing for the country. It's another to be bullied into abandoning the analysis midstream, which is what looks like looks to us what happened this time. Jill, the White House, the EPA and Congress have all acknowledged that high rent prices are a problem for the refiners. This is not the way the program is supposed to work.
So they're going to continue to get pressure until we get the situation addressed. We're going to continue to pursue our legal, regulatory and legislative options as are others and we're going
to keep up the fight.
Okay. Thanks. I guess maybe changing tack just a little bit. Other big issue if you look out there is a pretty big difference in some of the light, light crude pricing, particularly thinking WTI Midland are pushing relative to Gulf Coast prices. Can you give us an idea of how you're able to take advantage of that along the Gulf Coast or maybe sort of a net crude pricing you're able to achieve through some of your marketing and pipeline access?
Yes, Ryder, this is Gary. I guess we've raised our capacity to run light sweet crude. So we're now about 1,600,000 barrels a day of light sweet crude processing capability with the addition of the toppers at Corpus and Houston. In the Mid Continent itself, we have 300,000 barrels of refining capacity between Ardmore and McKee and the Diamond Pipeline, which will start up in December, then puts Memphis with competitive access to that Midland Cushing market as well, which gives us about 500,000 barrels a day of equivalent midcontinent refining capacity. In addition to that, we've worked very hard to secure logistics to give us competitive access to Midland at Corpus and also competitive access to Midland and Cushing and our Houston refineries.
And we've also added Line 9, which gives us exposure to that Brent TIR. So a lot of this work that we've done on logistics over the past several years, we feel like puts us in great position to be able to take advantage of that wide sweet sweet differential.
Okay, great. Thank you.
Thank you. Our next question comes from Ciro Dounis with UBS Securities.
Hey, good morning, everyone. Thanks for taking the question. Joe, just want to start off here. Valera has been strong steward of capital over the last few years and it just strong currency and share price now. It just screams strong currency and share price now.
It just screams like maybe you should be investing here. So just wondering, do you think like you're reaching the point where pivots maybe more spending makes sense, whether it be refining midstream or expansion up or down the value chain?
Yes, I mean Spiro, that's a good question. I think you understand the way we look at the use of capital. And we do have a strong cash position. We do have a strong balance sheet. Acquisitions are very opportunistic, as you well know, and we look at everything.
To have an effective acquisition for Bolero, it's got to be one that there's synergy involved in. And so that's one of the primary considerations. We have a great portfolio of assets today. So we're not compelled to do something just because of where we find ourselves. And then we always evaluate the returns that we could achieve with an acquisition or a growth project with that of buying back our shares.
And frankly, we still feel that we're undervalued at the price we're at today. So that competition for the use of what we would deem to be the discretionary cash flow remains. So I think you'll see us continue to look at opportunities as they present themselves. I think that you can expect that capital projects will continue to percolate up and if the returns are there for those projects, we're going to do them. But I mean nominally, our capital budget is going to be in this $2,700,000,000 to $3,000,000,000 range.
That's just what we feel that we can execute effectively. And if for some reason we find some very interesting projects that would increase that number going forward, we've told you guys that we'll make our case with you on why it's a good idea. So anyway, I think what you should expect is a bit more of the same going forward.
Fair enough. And then just maybe just general comments around the market here. I think you've got refined product supply lower than it's been in a while. And as you head into wintertime here, I don't think we've seen this low in years. And I guess historically, that's kind of what's led to a ramp up in gasoline production too early in the spring.
So maybe just as you look into 2018, the setup right now from an inventory standpoint, is it surprised you? Are we looking at things being better than what you expected maybe earlier this year?
Well, I think even pre hurricane, you saw typically during that time period, you see some pretty good builds in distillate and distillate inventories were flat or even falling even before you had the hurricane effect. So then when you have the supply disruption, it's definitely put us in a very good position in terms of inventory heading into the winter, the heating oil season With much cold weather at all, I think we're in for a very strong distillate season. And then I think the point you made is accurate. The last several years, distillate hasn't been strong enough to really force refineries into a max distillate mode and it's kind of created a gasoline build heading into driving season. But this year, it looks like with the strength in distillate, refineries will operate in a max diesel mode, which will help avoid the gasoline build and should be supportive of the gasoline crack next year.
Great. Appreciate the color. Thanks, guys.
Thank you. Our next question comes from Doug Leggate with Bank of America.
Thanks guys. Good morning everybody. I've got I'll take my full quarter of 2 if I may. Joe, the RIN question from earlier, I wonder if I could just put a follow-up to that. What are your options to mitigate your RIN exposure?
I'm thinking exports, retail, other things you can do if this is going to drag on a bit more because it looks like the RIN guidance, the cost guidance has ticked up a little bit from what you had previously. So I'm just wondering what your response will be now that, that line of potential resolution appears to have stalled for now?
Yes. No, Doug, that's a great question. And I think if you look at the projects that we've announced, okay, you look at the pipeline that will take products into the market area, we're going to own a terminal. It will allow us to blend. We're aggressively expanding our wholesale marketing business.
And then the terminal at Houston that we've announced with Magellan is going to allow us to export more product. We don't have our heads in the sand on this by any stretch of the imagination. And we will There is There is a clear realization, as Jason stated, not only at the White House and in Congress, but also with the regulators that the RFS as it is structured today is broken. And it's not achieving the objectives of the legislation when it was implemented. And so there will be changes and we'll continue to deal with it strategically with the things we can control, and we'll continue to deal with it legislatively and from a regulatory front to try to come up with some type of reasonable solution to this.
But we are doing what we can, Doug, to try to mitigate this expense.
Okay. I will wait to hear what you got to say on a future date. My follow-up is really, I guess you kind of snuck this one out to a 3rd party conference, resetting the payout ratio to cash flow. And I really got to commend you guys for doing that in terms of the transparency. But my question is basically to get the full benefit of that one with the margin that it resets your dividend yield to some extent that's already happened.
But now that you're where your share price is trading, you've obviously been very cognizant about when to do buybacks. And what's really at the back of my question is, assuming we get a corporate tax reduction, one would imagine that your corporate cash flow is going to take another step higher through the cycle. What is your current thinking on the buyback versus dividend split as you go forward? And with this reset in the target, is are we likely to see greater emphasis on dividend growth going forward? And I'll leave it there.
Thanks.
Thanks, Doug.
Okay. On the reset of the target, I do not think that really affects our absolute dollar payout. But going forward, we're just going to provide it from with a different metric. We'll provide the guidance versus a different metric. In regard to the dividend, our current plan is to review the dividend for increases annually and to pay a dividend at the high end of our peer group range.
Regarding share repurchases, they will be funded from our excess cash flow. So as we generate excess cash flow, we'll compare the repurchase with our alternative uses of cash. And if the repurchases is the best use, then we'll repurchase some more shares.
I don't want to take up my quota here, Mike. Just an observation, your yield is now trading in line with ExxonMobil, just to put it in context, which one would suspect that dividend growth gets rewarded in the relative yield of the share price, I guess, is what I'm saying, just an observation. But I appreciate your answer and, yes, I like the move. Thanks a lot.
Thanks, Doug.
Thank you. Our next question comes from Brad Heffern with RBC Capital Markets.
Good morning, everyone. Good morning. Joe, good morning. You've obviously announced this new Mexico terminal sort of partnership. Can you talk through sort of what having that terminal gives you that you didn't have before as it relates to selling into Mexico?
Hey, Brad, this is Gary. We have secured a long term deal. It gives us access to Deepwater Marine Terminal in Veracruz, Mexico. From there, we can supply inland terminals in Puebla in Mexico City. We expect that to be in operation sometime in the Q1 of 2019.
In addition to that, we continue to ramp up our cross border volume to supply the market. And we're also exploring other opportunities to supply some of the other major population centers. But this time, we're not ready to communicate any of those opportunities. In addition to all the work going on logistics, we are also engaged with a number of retailers and distributors regarding wholesale volume to supply both branded and unbranded volumes to them.
So Brad, I mean there's really 2 benefits, right? Number 1, we sell barrels into Mexico today. This provides us with a footprint and the opportunity to capture additional margin on those barrels. And then it provides the opportunity to grow. It's a market where consumption is growing.
Same is true with other parts of Latin America, and that's why we continue to look to those also. And then of course, you get the other benefit, you have a RIN related benefit associated with securing those markets and exporting more into them.
Okay. That's great color, guys. Thanks. And I guess maybe sticking with Gary, just on the Venezuela front, obviously, you guys are big buyers of Venezuelan crude. Heard a lot of anecdotes recently about quality declines there and just general difficulty as it comes to payments.
Any color you can give there about how you guys are thinking about Venezuela as
a source going forward would be great? Sure. Our volumes from Venezuela have been fairly consistent. We certainly see that the struggles that they have, some of that shows up in the load windows. It's difficult to get the load windows.
But we've been getting the volume and we have seen some degradation in quality. But the commercial terms that we have on our contracts with Venezuela have price deducts that go along with those qualities. So we really haven't seen any problems as of yet.
Our
next question comes from Paul Sankey with Wolfe Research.
Hey, Paul, are you there?
He dropped.
It seems that he has dropped. I will move on to the next question. Our next question comes from Paul Cheng with Barclays.
Hey guys, good morning.
Good morning, Paul.
Joe, two questions. Maybe that the first one will be for Gary, actually. For the Diamond Titan 9, when is that going to start up and when the light field going to be? Yes.
So we'll What kind
of pellet that we're talking about on there?
Yes. So Diamond Pipeline will be doing line fill in November and we expect the pipeline to be in operation in December. To kind of get an idea of the economics today, we supply Memphis from the Gulf, and it's really an LLS plus pipeline tariff. When Diamond is in service, it will be Cushing or Midland TI plus the Diamond tariff. So it really is that WTI to LLS spread that you would look at.
Today, that spread is around $6.30
So Gary, should I interpret what you say is that the tariff will be about the same as that from the Gulf Coast up to Memphis today?
No. There's a little difference in the tariffs, but it's not too significant.
And that when you're getting the oil from Kuxing on the WTI and South from the Gokko, are we going to see any yield difference or any things that we need to take into consideration in addition to the LOS WTI spread?
Yes. We'll have a number of grades that one of the reasons we like Diamond is it gives us access to a number of different crude grades and certainly depending on what crude grades are economic at the time, there can be a yield shift associated with the crudes.
Okay. But that's not in your base economic?
No, it's not.
Okay. A second one, Joe, on the IMO 2020, does Valerio have any plan or expected large refining CapEx projects associated with that to shift your yield?
Why don't I let Lane and Gary weigh in on this?
Paul, this is Lane. So we obviously are looking at that and we have a view of our existing assets will clearly benefit from that regulatory change and we have a couple of several big projects that are in our gating process. We're not in a position to talk about them publicly, but we definitely understand that will change the market not only for fuel oil, but we believe that the replacement fuel will be diesel. So you'll see a fairly positive economics from that sort of resid to diesel spread. So yes, we are looking at projects to take advantage of that.
Is there any timeline, I think, that you guys may come to a FID decision or any kind of timeline you can share?
Yes. We'll get to some FID decisions in the first half of next year, maybe in as early as the Q1 of next year. We just got to we got to go through our gating process and get the engineering done. And so it will be sometime next year when we would be provide a little more clarity to everyone as to what we're deciding on and what we're going to invest in.
And will those be in the say $1,000,000,000, $1,500,000,000 kind of project or it will be much smaller?
All very excellent questions, but I think I would probably fit about as much as I can.
Okay. Thank you.
Paul, that was number 3.
Thank you.
We love talking to you. Yes, we'll get out there with it soon enough though. But yes, I mean, Lane answered it properly.
Thank you.
Thanks, Paul.
And thank you. Our next question comes from Phil Gresh with JPMorgan.
I suppose I'll ask one more question in a slightly different way there on the back of Paul's question, which is this range of CapEx that you've generally talked about, this kind of 2.5%, I guess it's 2.5% to 2.7% type of range. Would any of these projects be big enough that it would influence that or do you still think that you're generally going to operate within that range over the next few years?
No, I don't think we're ready at this point. And Todd, to tell you that we're going to jump above that range. And the projects are material, but it goes into the discipline around selecting the ones with the best rates of return that position us best to grow in the future. And so that's our focus. Projects take several years to construct.
And so even if it's $1,500,000,000 project, you're talking $500,000,000 $600,000,000 a year. So I don't think you should expect that you're going to find us jumping to $3,500,000,000 to $4,000,000,000 of CapEx.
Right. Okay. That's helpful. And then certainly can appreciate all of your comments about the efforts on the Gulf Coast. Thought I'd just ask about where Valero is at in terms of as we entered the Q4, were there any residual effects anywhere in your system?
I guess I'm thinking maybe Port Arthur, or would you say you're fully back up and running by the start of the quarter?
Yes. So, Phil, this is Lane. So, we yes, Port Arthur would have been the refinery that had the biggest lingering effect going into the Q4, but our operations are back to normal as of now.
Okay. And then last question for Joe. Joe, you've talked about this $1,200,000,000 to 1 point $4,000,000,000 of project EBITDA that's going to be coming over the next few years, dollars 300,000,000 to $400,000,000 that's in execution phase. So you talked diamonds coming, Wilmington's coming, Diamond Green Diesel, how much should we expect in 2018 uplift on a run rate basis?
Yes. Why don't John give you some insight there?
Yes, Phil. So we've got Diamond Pipeline and Wilmington cogen that's coming up. We have given that Slide 13 in our deck, so you can have a longer term view of expected EBITDA. We really don't break it down by year. So we don't have specific guidance on those 2 that you can expect next year, but you can kind of triangulate on the IRR thresholds that we've given in the slide deck and use the base cost for those two projects to get a ballpark depending on your price assumption.
But what we have done in the past and you can see in the slides on the toppers was do a make good after there's some time where they operate and we can kind of see what they are contributing. And I would think for larger projects, we would continue to do that.
So would the run rate of the $1,200,000 to $1,400,000 generally be fairly linear over this next 5 years more broadly?
Well, we don't have guidance on if it's lumpy or smooth. But as the projects come online, we'll look at it and talk about them a little bit.
But that's really all I can say on it. Okay. Thanks.
Thank you. Our next question comes from Blake Fernandez with Scotia Howard Weil.
Hey guys, good morning. Question for you, I was hoping to clarify on this VLP drop of $508,000,000 Can you clarify how much of that is going to be financed in the form of units versus cash? I'm basically trying to figure out how much cash is going to actually land on the balance sheet in 4Q.
Yes. Hey, Blake, this is Joe. Donna is going to give an answer to this.
Yes. So the net cash inflow to VLO for that should be a little north of $400,000,000 There will be some unit take backs, but it will be relatively small and less than $50,000,000
Okay, great. Thank you. And then, Gary, back on the previous question on shifting toward maximum distillate yield. I don't believe you stated this, but I was looking at your 3Q levels and it looks like you were running about 38% distillate yield. I'm just curious, is that kind of the upper end of what you think the system can do?
Or, I guess, how much flex do you have there?
We generally say we have about an ability to swing about 5% of our yield slate. I would say for the Q3, we weren't in a MAX distillate load for a good portion of the quarter. So I think that's kind of the amount of flexibility you'll see in the yields.
And you think that's indicative of kind of industry, so in other words, maybe another 2% or 3% or so ability to kind of flex more toward distillate going forward? Yes.
I would assume most people are similar to
us. Our next question comes from Neil Mehta with Goldman Sachs.
Good morning team.
Good morning Neil.
First question was around the product export market. Just wanted your guys' perspective in terms of where ultimately the barrels are going and the outlook for product exports as we roll into 2018 here?
This is Gary. In the Q3, we did 88,000 barrels a day of gasoline exports and we did 251,000 barrels a day of diesel exports. I think especially on the diesel, you definitely saw some hurricane impacts. Prior to the hurricane, we were over 300,000 barrels a day of diesel exports. And then certainly, with the hurricane, we those volumes dropped.
November, with November trade, we saw wide open arms to go both to South America and to Europe. December trade, it looks like certainly a big pull again to Latin America. For the 1st few days of December trade, the RV Europe has been closed, but our traders expect it to open up. We don't really see that there'll be much of a material difference in export demand. In fact, we expect it to grow as we see growth in South America.
I appreciate it. And then the follow-up, Gary, just on Brent TI. So you talked about how the system is switching to maximize lights, but do you have any views in terms of what's driving it this wide? It seems like LLS is very firm here. Houston pricing is actually relatively firm.
It's really it seems like there's a congestion or bottleneck around Cushing, but any color as folks who are in the market in terms of what's driving the differential as wide as it is? And then just kind of how you're thinking about that spread going into 2018 as well?
Yes. So I think what you're seeing in Brent TI is really a combination of factors. It's strength in Brent and weakness in TI. So the strength in Brent, you've seen a pull from Asia of North Sea barrels and you've seen good refining margins in Europe. And so it's pushed the Brent contract into backwardation.
And then on TI, you've had weakness, and some of that was driven from the hurricanes. You decreased demand for TI with refining capacity down. And then the hurricanes also hindered our ability to export the crude. Following that period, now you've had a period where you have some mid continent refineries and turnarounds. So it looked like at the peak, 4000 to 500000 barrels of refining capacity that's down.
And so that's put it's begun to stress the logistics a little bit. So the market linked line and the Seaway line are both under proration and so it's really that then caused this weakness in TI. So certainly it will improve some But as we continue to see production growth, I think you'll see that But as we continue to see production growth, I think you'll see that pipeline tariffs are meaningful again and we would expect to see a little bit wider Brent TI through next year.
Time. Our next question comes from Chi Chiao with Tudor, Pickering, Holt.
Thanks. Good morning. Interesting development on Capline last week. Can you talk about the company's interest in possibly locking up line space on a potential reversal of that line at the St. James and Monroe?
And how are you thinking in general about the long term mix of Canadian heavies into your Gulf Coast system?
Yes, Cheetah, this is Gary. It's really difficult for us to be able to comment because at this stage, we're not sure what's going to feed a Capline reversal. They said 300,000 barrels a day. We're not sure what feeds it. In general, though, we have connectivity into Memphis through Capline.
So a reversal gives us more optionality in Memphis. And then I think if it is Canadian heavy, it gives us more access to Canadian heavy at our St. Charles which is a positive as well. But at this stage, it's just too early for us to really comment on anything we would do with that.
Well, does the cap line reversal change your support at all for Keystone XL moving in? I mean, you can get barrels into Patoka of Keystone. And how are you thinking about that?
Well, we're still supportive of Keystone XL. To us, it's the most efficient way to bring the barrels in. But we'll see what happens with that and then what happens with Capline.
Okay. And on Latin American heavies, you talked about Venezuela, but certainly there's a declining production throughout that region. How do you think that plays out longer term on availability of Latin American heavy into your region? And how does that influence Maya differential longer term?
Yes. So I think you see some decline in South America, but we see Canadian heavies continuing to ramp up. And so I think some of the lost barrels that you have from South America were replaced by additional Canadian heavies. We certainly see that while the OPEC cuts are in place that the quality differentials can be narrower, but when you get the OPEC barrels, you'll see wider differentials. And then as you move closer to this IMO 2020 date, we think that the quality differentials will be very wide during that period of time.
Okay. Thanks. And maybe just one general question here. Joe, you talked about the hurricane impacts and supply chain efficiencies in your remarks. But is there any way you guys can get more feel into Puerto Rico to help those people out?
By all accounts, there's still shortage of everything and it just seems like we need the private sector to step in and take a lead here to help out the situation there? Thanks.
Chi, that's a really nice thought. I mean, we have provided financial support in the Puerto Rico, as well as Mexico after the earthquakes and then of course, as a result of the hurricanes here and from a fuel supply source. Gary?
Yes, we certainly can look at it. I don't I can't say that we've had any calls for fuel, but I'll look into it, Gene.
Well, we sure wouldn't hold it back. No.
No. Yes. Thanks for those thoughts. Appreciate it.
Thank you.
And thank you. Our next question comes from Justin Jenkins with Raymond James.
Great. Thanks. Good morning, everybody. I guess maybe a couple on midstream for me. So last quarter, we talked about M and A versus organic growth.
And Joe, I appreciate your response to an earlier question. And you mentioned how much you prefer maybe the organic side given control of development. And certainly seen that with the investment or the announcements you've made in September. But I'm curious with the difficulty playing out in midstream stocks lately and maybe the relative strength of VLP, if maybe you see things looking better for M and A?
Well, I mean, look, what we've seen, what we've participated in the M and A market around, let's just say gathering systems, seems like they're still at pretty lofty multiples, okay? So then you get into, is it better to try to buy something like that or is it better to go ahead and do the development yourself. So obviously, we've seen plenty of opportunity to strengthen our system both for Valero and for BLP by doing the organic projects. But Rich, is there anything you want to add to this? It's
basically what you said. The assets, the transactions that we see are trading at north of 20x multiples. And we've got a good inventory of organic projects and we've got the EBITDA upstairs to drop down. So acquisitions are part of the growth strategy. But right now, we've got a lot of good stuff at much more attractive multiples.
But we do look at all this stuff.
Okay. Appreciate that guys. And then maybe thinking on the financing plan for the 2 midstream JVs announced in September, do think we could view it more like Diamond where we build it at VLO and drop into VLP? Or is there a thought to get VLP involved sooner? And I'll leave it there.
Thanks, guys.
Well, and Don, I may want to speak to this, but I mean, I would say that generally our ultimate goal here as VLP grows is to be able to allow us to be able to do its projects and its acquisitions on its own. Today, Valero still has absolutely no problem providing what I won't call it financial support, but being on point for taking the asset and adding it to the drop inventory. Anything you'd add?
No, I mean, right. So as soon as VLP can get to that size and scale to take the font, to take that negative cash impact on itself, I'm certainly looking forward to doing it that way.
Understood. Thanks, everyone.
Thank you, Joe.
And our next question comes from Ryan Todd with Deutsche Bank.
Okay, thanks. Maybe just a couple of quick ones. On run rates, your run rate guidance in terms of volume throughput into 4Q is relatively in line with our expectations. But I think there's been some talk of deferrals of turnaround activity and maintenance activity into earlier next year to take advantage of opportunity. I mean, are you seeing any of that across your portfolio?
Or as you look broadly across the industry, do you have expectations for activity, turnaround activity, I guess deferrals now or what it means for next year's maintenance period in February March?
Well, Ryan, I'll start with the last question. We don't really give forward views on where we're going to be in the first half or even next year on our turnaround and not really on the industry. What I will say is that we deferred our McKee turnaround in the Mid Continent for about 2 weeks to help get in a better contractor situation and supply situation. And so that was really just a 2 week delay. We did move out a catalyst change in 1 of in our LTO hydrocracker at Houston into next year.
And that's pretty much the extent of our deferrals. We didn't have a lot of turnaround activity in the Gulf Coast going on or the Mid Continent for that matter going on in the Q4 of this year.
Great. Thank you. And then maybe just one more quick one. In Q3, I believe your feedstock was I think you ran about 52% sweet. You were 48% sweet last quarter.
Prior to the start up of Diamond, is there any additional flex in the mix to run additional sweet and get closer to the 1,600,000 barrels of capacity or is that about max?
Well, if you look at the way we ran in the 3rd quarter out of that one point 6,000,000 barrels a day of capacity, we utilized about 85% of that. In the 4th quarter, certainly some of the underutilized capacity that we had was a result of the hurricane, so that capacity is back online. But with the heavy Canadian discounted to Houston TI barrel by 15%, economics are really pushing us towards the heavy at some of our plants and then light sweet after that.
Great. Thank you.
Thanks, Ryan.
Thank you. Our next question comes from Faisal Khan with Citigroup.
Good morning, guys.
Hi, Faisal.
Hi. Two questions. First, the decision to take back a small number of units in the VLP transaction, was that a function of sort of the current market conditions for MLPs or was it just a function of you guys have a $5,000,000,000 of cash in the balance sheet and you don't need to take back the cash?
I mean, the decision to take back some of those shares was largely to mitigate some of our tax exposure on the deal.
Okay, okay. Got you. And then just I guess following up on that, the current cash balance of over $5,000,000,000 no matter how much stock you buy back and how much you increase the dividend, the balance still remains. So I just want to understand your philosophy around
That's a good thing. Yes. Fazil, I mean, that's a good question. I take it your question is what are we going to do with all the cash. We're going to continue on the path we're on.
And as I said earlier, we think our shares are undervalued. So the capital allocation framework that we put in place has worked very well for us. We do, Mike mentioned, we look at the dividend. I don't think we're at the top on where we're going to have dividend payouts going forward. And then we again, a significant transaction would chew up some of the cash.
So again, we've told you in the past, our objective is not to hoard cash and just sit here with a ton of cash on the balance sheet. We're going to put it to work and we'll do it through the context of the capital allocation framework.
Okay. And when you say that an acquisition could chip some of the cash away, are you is it you've tried, you've looked for stuff and you just you can't make it work or is it just the timing is not
right? Well, even with a lot of cash, it doesn't make sense to overpay for something. And when we have a very disciplined approach to looking at acquisitions, and as Rich stated on the logistics side, 20 times multiple seem to be a little bit rich when we can do organic growth projects around logistics at much more attractive economics. Granted, the run rate is longer, the lead times longer, but the result is much, much better for our owners than it would be if we overpaid for something. So patience isn't something maybe that we're all blessed with, but we're trying to do so and to continue to drive growth, but do it in a reasonable way.
Great. Thanks, Joe. Appreciate the comments.
Thank you. Our next question comes from Craig Shere with Tuohy Brothers.
Good Morning. The latest drop looks to be a
bit of
a lower multiple than historical. Is that driven more by perhaps higher maintenance CapEx on the assets or the higher cash component? Is that an issue? And do you see multiples starting to stair step down for ensuing drops relative to what you've done in the prior years?
So the combined multiple for the most recent drop is not out of line from our prior drops. It's in that 8.5 to 9.5 time multiple. And so I wouldn't attribute any higher maintenance or any capital IRR pretax for the for IRR pretax for these dropdowns and the multiple just kind of rolls out. So we're in that 12% to 13% pretax IRR on these dropdowns. But there's nothing funny going on with maintenance or CapEx associated.
I'm sorry, I may have just misunderstood the press release. Is the combined EBITDA 84,000,000
dollars No, it's 60.
Okay. I apologize.
Okay.
No problem, Craig.
Thanks, Craig.
And thank you. I see no further questions in queue at this time. I will now turn the call back over to Mr. Locke for closing remarks.
Okay. Well, thank you everybody. We appreciate you joining us today. Please contact me or the IR team if you have any additional questions. Thank you.
And thank you, ladies and gentlemen. This concludes today's