瓦萊羅能源 (VLO) 2016 Q3 法說會逐字稿

Welcome to the Valero Energy Corporation reports 2016 third-quarter earnings conference call. My name is Vanessa and I will be your operator for today's call.

(Operator Instructions)

Please note that this conference is being recorded. I will now turn the call over to Mr. John Locke, Vice President, Investor Relations. Sir, you may begin.

Thanks, Vanessa. Good morning and welcome to Valero Energy Corporation's third-quarter 2016 earnings conference call. With me today are Joe Gorder, our Chairman, President and Chief Executive Officer; Mike Ciskowski, our Executive Vice President and CFO; Lane Riggs, our Executive Vice President of Refining Operations & Engineering; Jay Browning, our Executive Vice President and General Counsel, and several other members of Valero's Senior Management team.

If you have not received the earnings release and would like a copy, you can find one on our website at valero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments. If you have any questions after reviewing these tables, please feel free to contact 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. These 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 a few opening remarks.

Thanks, John, and good morning, everyone. During the quarter, our team again operated safely and reliably, and did a good job of capturing margin in a low, but improving margin environment. We also executed our projects well, completing major turnarounds and progressing on growth investments, while optimizing our portfolio. These actions enabled us to produce positive cash flow and to return a healthy amount of cash to stockholders.

In the market, we continue to see solid product demand domestically and internationally. The sustained low price of crude oil and petroleum products, along with strong export demand, helped create a pull on domestic product inventories. We're also encouraged by the modest return of domestic shale crude production, which is good for diesel demand and crude differentials.

On the downside, we continue to see negative impacts on Valero's earnings from exorbitant RINs prices. For the year, we expect to incur costs in the range of $750 million to $850 million to purchase RINs. At these levels, the expense is significant to our company and has our full attention.

You've likely seen that we filed a petition with the EPA to address this issue. Our efforts are focused on moving the point of obligation, which we believe will not only level the playing field among refiners and retailers, but it'll also improve the penetration of renewable fuels, reduce RIN fraud, lower RIN speculation, and reduce costs for the consumer. We have had many constructive conversations with regulators and these conversations continue today.

As you'd expect, we continue to work this issue aggressively. As I mentioned a moment ago, our refining operations were very good. We ran reliably during the quarter and experienced very little unplanned downtime. We completed major turnarounds at our Port Arthur and Ardmore refineries, which our teams planned very well and executed safely and successfully, and we will be wrapping up the restart process over the next few days.

Our ethanol business performed very well, recording its highest operating income contribution since the fourth quarter of 2014. Our plants are the most competitive in the industry and are run by dedicated people. So it's great to see them again contributing to Valero's earnings in a meaningful way.

Regarding strategic investments, we're pleased to have both our new crude units up and running. The Corpus Christi crude unit, which was completed late last year, and the Houston crude unit, which was completed in June, both ran well during the quarter.

Turning to the development of our Houston alkylation unit, the project is in the engineering and procurement phase and on track for completion in the first half of 2019. The economics of this project look good, given the tight outlook for octane and it also positions us well for Tier 3 gasoline compliance. Looking ahead to 2017, we expect spending on capital investments to be similar to the budget for 2016, which was $2.6 billion.

I also want to share an update on our portfolio. Effective October 1, we disposed of our Aruba business. We've been on the island and in the community for a long time and worked hard to produce a win-win for Valero and the Government of Aruba.

In addition, the Government of Aruba secured a new operator who plans to invest capital in the site and operate it as a bitumen upgrader, which should have a positive economic impact on the community. We're happy for the people of Aruba and for the assets to have a renewed purpose on the island.

With respect to Valero Energy Partners, the dropdown of the Meraux and Three Rivers Terminal in September helped us achieve our dropdown target for the year. Yesterday, we announced the distribution increase of 5.5% for the third quarter, which puts us on track to deliver 25% distribution growth through 2017.

Although we don't plan to provide dropdown guidance for 2017 at this time, we are comfortable setting the target for annual distribution growth for 2018 of at least 20%. You'll hear more from VLP on their call later this week, but VLP has excellent operations, is in great shape. And finally, despite significant turnarounds during the quarter and the low-margin environment, we generated solid cash flow from operations.

So far this year, we returned 148% of net income to stockholders and we're well ahead of our 75% payout ratio target for the year. We're also extending our payout ratio target of at least 75% of net income to 2017. So with that, John, I'll hand the call back over to you.

Thank you, Joe. For the quarter, net income attributable to Valero stockholders was $613 million or $1.33 per share, which compares to $1.4 billion or $2.79 per share in the third quarter of 2015. Excluding an income tax benefit of $42 million, or $0.09 per share related to the Aruba disposition, third quarter 2016 adjusted net income was $571 million, or $1.24 per share.

Please refer to the reconciliations of actual to adjusted amounts that begin on page 3 of the earnings release tables. Operating income for the refining segment in the third quarter of 2016 was $990 million, which was $1.3 billion lower than the third quarter of 2015. Primary drivers of the decline were weaker gasoline and distillate margins due to elevated product inventories, lower discounts for most sweet and sour crude oils relative to Brent crude oil, and higher RIN prices.

Refining throughput volumes averaged 2.9 million barrels per day in the third quarter of 2016, which was in line with the third quarter of 2015. Our refineries operated at 95% throughput capacity utilization, with major turnarounds that occurred at the Port Arthur and Ardmore refineries. Both refineries are currently in the process of restarting operations.

Refining cash operating expenses of $3.63 per barrel in the third quarter of 2016 were $0.17 per barrel lower compared to the third quarter of 2015, primarily due to lower employee-related expenses and adjustments related to the Aruba disposition. The ethanol segment generated $106 million of operating income in the third quarter of 2016, which was $71 million higher than in the third quarter of 2015, largely due to higher gross margin per gallon resulting from lower corn prices.

For the third quarter of 2016, general and administrative expenses, excluding corporate depreciation, were $192 million and net interest expense was $115 million. Depreciation and amortization expense was $470 million and the effective tax rate was 18% in the third quarter of 2016. The effective tax rate was lower-than-expected and lower than the third quarter of 2015, primarily due to income tax benefit on the Aruba disposition and the favorable settlement of an income tax audit.

With respect to our balance sheet, at quarter end, total debt was $9 billion and cash and temporary cash investments were $5.9 billion. Valero's debt-to-capitalization ratio, net of $2 billion in cash, was 25%. We had approximately $5 billion of available liquidity, excluding cash.

We generated $863 million of cash from operating activities in the third quarter, which was after the impact of [$176] million of unfavorable working capital changes, primarily a decrease in accounts payable. With regards to investing activities, we made $453 million of capital investments.

Moving to financing activities, we returned $778 million in cash to stockholders in the third quarter, which included $276 million in dividend payments and $502 million for the purchase of 9.2 million shares of Valero common stock. We completed a $1.25 billion public debt offering in September, and in October we repaid $950 million of senior notes due in 2017. On a pro forma basis, after the repayment, our debt-to-capital ratio was 22%.

Our Board of Directors approved an incremental $2.5 billion share repurchase authorization in September. And at quarter end, we had approximately $2.7 billion of repurchase authorization remaining. For 2016, we expect capital investments to total about $2.4 billion, which is slightly below our previous guidance due to lower turnaround costs and the timing of some growth CapEx spend.

For modeling our fourth quarter operations, we expect throughput volumes to fall within the following ranges. US Gulf Coast at 1.58 million to 1.63 million barrels per day; US Mid-Continent at 420,000 to 440,000 barrels per day; US West Coast at 270,000 to 290,000 barrels per day; in the North Atlantic, at 450,000 to 470,000 barrels per day.

Refining cash operating expenses are estimated at approximately $3.75 per barrel in the fourth quarter. We continue to expect cost attributed to meeting our biofuel blending obligations, primarily related to RINs in the United States, to be between $750 million and $850 million for 2016. Our ethanol segment is expected to produce a total of 3.9 million gallons per day.

Operating expenses should average $0.38 per gallon, which includes $0.05 per gallon for non-cash costs, such as depreciation and amortization. G&A expenses for the fourth quarter, excluding corporate depreciation, are expected to be about $200 million and net interest expense should be about $150 million. Total depreciation and amortization expense should be approximately $465 million and our effective tax rate should be around 31%.

That concludes our opening remarks. And before we open the call to questions, we ask that callers adhere to our protocol of limiting each turn in the Q&A to two questions. This will help us ensure that other callers have time to ask their questions. If you have more than two questions, please rejoin the queue as time permits.

Thank you.

(Operator Instructions)

And we have our first question from Ryan Todd of Deutsche Bank.

Great. Thanks. Maybe if I could just ask -- start out asking on payout and cash return to shareholders. Again -- and this has been the case, I guess, over the course of the year, where you significantly exceeded your official payout target again, despite a fairly challenging year. I mean, how do you think about managing this going forward?

I know you reset the bar at 75% for 2017. How do you view the balance between returning that cash to shareholders and preserving optionality for growth projects that are -- and M&A, if necessary?

Well, all of those options are part of our capital allocation. So we did set the target at at least 75% for 2017. So going forward we feel like that's an appropriate way to go into the -- appropriate rate to start the year with, and then we'll analyze that as we move through the year and adjust it as accordingly.

Okay. Thanks. Then maybe one question on the product environment as we head into the winter. Last year the industry massively overproduced gasoline through the winter, setting up a challenging position into 2016.

Can you share your thoughts, as we head into this winter, on managing inventories of gasoline versus distillate balance as you shift to winter-grade gasoline and what role -- I know on the last quarter we talked some about potential for economic run cuts into the latter part of the year. Do you still see that as necessary in managing inventories, or have we done enough work at this point where you think you're okay?

Ryan, this is Gary. I think that we will need to see some economic run cuts in the industry. If you look at what's happened in the market, Chicago has been selling off fairly sharply over the last week and we're starting to see inventories build in the Mid-Continent.

So, typically, especially in that land-locked region, the market is short product in the summer and becomes long product in the winter. And I think refineries in that region will need to cut to balance the market as we move into the fourth and first quarters. Elsewhere, I think a lot of what you saw last year in terms of refiners running high on utilization and producing summer-grade gasoline was really a function of the steep carry in the market.

And certainly at least the Brent curve it's flatter this year than what we saw last year. And I think as there's not as much carry in the market, it will go ahead and cause refiners to cut down on utilization and avoid some of the products builds that we saw last year.

Great. Thank you.

Thanks, Ryan.

And thank you. Our next question comes from Roger Read with Wells Fargo.

Good morning.

Good morning, Roger.

Just a couple of questions I'd like to hit on here. First as part of the capital allocation and something that's gotten hammered in some prior conference calls, so let's get out the tools again for this one.

M&A and plenty of units appear to be on the market, not all, of course, would be interesting to you. But I was wondering how you're looking at the M&A market, and is that still something that seems attractive to Valero?

Okay. Yes, Roger, this is Mike. It is attractive. We're -- on the capital allocation side it's definitely part of our strategy. We're interested in acquiring logistics assets that provide third party revenue or are strategic to our core business.

And on the refining side, we're interested in assets that are high quality, globally competitive and advantaged location. So for us that primarily means the US Gulf Coast.

And any thoughts beyond the Gulf Coast of anything that - I mean, is there any real interest in moving beyond kind of your existing footprint further into Europe, anything like that?

Roger, this is Joe. I mean, if assets came into the market, we'd look. But I would tell you, no, there's nothing on the radar screen right now outside of what Mike described to you. I think if you look at our system, you see where we could produce the greater synergies and that would be the US Gulf Coast, and so that is our focus.

Okay. Appreciate that, and then unrelated follow-up. You mentioned the improvement in US drilling being good for diesel demand and for the differentials. Obviously, diesel demand happens quicker. Do you have kind of a rule of thumb that you use for rigs and diesel demand on either a - I don't know -- a daily basis or anything like that?

Roger, this is Gary. I really can't - I don't have any insight into that at all.

Very interesting question, though.

Yes.

We all looked at each other, Roger, when you asked it.

All right. So I've stumped the masters for a change. Appreciate it, guys. Thank you.

You got it.

And thank you. Our next question comes from Phil Gresh with JPMorgan.

Hey. Good morning.

Good morning, Phil.

First question is just on the capital spending for this year. Obviously, you've been running at an exceptionally low rate, even relative to your guidance for the full year. So wondering what the key drivers of the lower capital spending have been, and if there's something specific in the fourth quarter that would suggest such a high rate implicit in the full year guidance.

Okay. The capital for 2016 here is, we've adjusted it for $2.4 billion. It's primarily due to lower turnaround costs than what we had anticipated. And then we have some timing on our growth capital expenditure spend that's being lower. It's really a timing issue, as John discussed in his notes. So some of that's being pushed to the future here.

Okay. And then just maybe a second question on the balance sheet. With your leverage ratio at 22%, which is still pretty conservative relative to the 20% to 30% target range, if fundamentals remain challenging again next year like they were this year, should we think that you'd be willing to be similarly aggressive next year? Is there any reason that this year would be unique?

Aggressive in what matter?

In terms of buying back well above your target.

What we do consider, in a lower earnings environment, the net income obviously is a little bit lower, but we do have quite a bit of depreciation in there. So we look at other factors as well as cash flow. So we'll look at our cash flow generating capabilities and all our sources of cash in paying out and buying back the stock.

My -- the question would be, are you willing to add a little bit more leverage, if necessary, to continue down the path of buybacks?

No, we would not. We would not lever up to buy back stock.

Okay. Thanks.

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

Hello. Good morning, guys.

Hi, Neil.

Joe, can we get your comments on this RINs topic. Thanks for your comments earlier. But what do you think the political appetite is to actually change the RVO this year and then from your dialogue and discussion with Washington to ultimately change the point of obligation?

Well, okay. So, it's very hard for me to comment on the political situation, so let me focus on the second part first, okay? And I mentioned that the conversations that we've had have been very constructive. We've had conversations not only with the regulators, but also with the White House.

And there is a clear acknowledgment that the structure of the current program isn't delivering the desired results. And so, these are smart people that we're talking to, and they're really trying to understand it and figure out. So, as an industry, let me just say this, the independent refiners, AFPM and certainly Valero, we're working with them to help them understand the issue, certainly as we see it. And there's a clear acknowledgment that we've got a situation that needs to be resolved.

Now, as far as the political climate, we're couple of weeks away from the election. And although we would love to see something change this year, I don't know that we'll get that. But it's certainly receiving enough attention and it is being discussed, to the point where we believe that it's getting worked and that we should have some type of resolution and relief in the not too near future.

I appreciate that, Joe. And the second is more specific to the quarter. It was a strong quarter, particularly in the Gulf Coast.

Can you talk about what you think drove the strength of the captures despite the downtime at Port Arthur? And any of these factors that you would define as more one-time versus repeatable?

Neil, this is Gary. I think you know first, we ran very well and that certainly contributed. When I look at the market factors, I would say the biggest thing I see is, we buy a lot of other feedstocks other than crude, a lot of VGO and resids. And if you look at the pricing of the VGOs and resids that we purchased in the US Gulf Coast system relative to Brent, they were much cheaper than what we saw either last quarter or a year ago at this time. And I would say that was the biggest driver to the capture rates.

That's great, guys. Thank you.

Thanks, Neil.

Thank you. Our next question comes from Paul Cheng with Barclays.

Hey, guys. Good morning.

Good morning, Paul.

Joe, I hear you talking about the US Gulf Coast as the desired M&A target region for you. But of course Shell is also putting up their San Francisco refining system for sale and realistically not too many people will be interested in buying. So from an M&A standpoint, does it make it intriguing for you to look at that, given that you already have two refineries?

Now if you add another one, you may get something that you benefit probably not as much as what you can get from the Gulf Coast, but at the same time the competition for the bid is probably much lower.

Yes, Paul, that's a very good question and let me just share this. That when we have looked at our ability to acquire additional assets in California historically, we have been precluded. And it's more of a FTC issue for us than anything else. I think it would be very, very difficult for us to execute another refinery acquisition in California.

Perhaps the West Coast would be something that would be viable, but I don't think we could get another deal done in California. So, it really hasn't been something that we've spent a lot of time talking about.

So even after Tesoro get approval to buy Carson, you think that the whole FTC restriction is still being applied?

Yes, I think for us it certainly would be.

I see. Okay. Second question that you do have a nice UK operation. Just curious that on the ground what have you seen in terms of the European demand?

Are they -- we have seen unseasonal uptick in the European refining margins. So is it driven primarily because people on the refinery downtime or that the underlying strength and the demand is better than people think?

Paul, this is Gary. I don't know if it was really tied to downtime or not, but we did see very good wholesale demand through our UK system. And our wholesale profitability certainly contributed to our results in the North Atlantic Basin.

So, Gary, you think it's more demand-driven than supply?

I really don't know that I see the data well enough to be able to comment on that, Paul.

I see. All right. Thank you.

Thank you. Our next question comes from Evan Calio with Morgan Stanley.

Good morning, guys.

Good morning, Evan.

Hey, Joe. So, some encouraging comments this morning on the RFS and the RFS topic. Can you give us update on your lawsuits? Procedurally, where they stand? What are the key dates moving forward, just so we can at least follow how things have progressed on that more hostile front?

Yes. Hey, listen, Evan, why don't I let Jay Browning, who's neck deep in this thing just give you some color?

Perfect.

The timeline is really going to be driven more by the process that Joe was describing. EPA's expected to finalize a rule, I believe, by the end of November. And the litigation will play out and there's lots and lots of players who are involved with that.

So there is -- at this point there's really nothing to put out there in front of you in terms of detail on timing that would be crucial to the process. I think other factors -- the political process is more the driver at this point.

Litigation is being used in that negotiation or information awareness process at this stage?

The litigation is out there, but it is more or less used as a framework and as a last resort. Obviously, our preference would be for EPA to volitionally move the point of obligation of its own accord rather than being forced through the litigation process. But we've got the litigation out there just to

Great. And November's approaching. My second question is more of a macro question. We look at global turnarounds for the industry, at least planned as being much lower in 2016 relative to 2015 and that having been a major contributor to weaker sequential cracks this year. You can see it and you've mentioned it in the higher utilization data. I know Valero -- I know you guys plan turnarounds several years in advance, but can you give us any color on your expectations for planned maintenance into 2017, at least sequentially higher or lower, and any views on that potential normalization of turnarounds providing a better environment in 2017?

Evan, this is John. I think you summed it up. We really don't have kind of a forward view on turnarounds that we can share. I know there's resources out there where people can go and get views from contractors and whatnot, but our in-house view is we just don't have forward guidance on turnarounds.

Got it. All right, guys. Thank you.

Thanks, Evan.

Thank you. Our next question comes from Jeff Dietert with Simmons.

Good morning.

Hi, Jeff.

Appreciate the guidance, or target on the 75% payout for 2017. I was hoping you could talk about some of the major factors that you expect to influence profitability in 2017. Some of the factors we're watching, tier 3 implementation, CAFE standards, potential OPEC cuts. What do you see as the major drivers for 2017 margin environment?

Jeff, let me go ahead and - that's one of those questions that, we just are going to kind of share musings on. So, why don't I just see if Gary and Lane have any comments for you on it?

I'll start with the OPEC cuts, Jeff, that you brought up. So far, we'll know a lot more about what's going to happen there when they have their November meeting. But if you look at the proposed volumes of the cuts, it looks like the volumes are about the same as what Saudi Arabia typically burns in the summer for power generation. So I don't know that we'll see any real impact on exports even if they had the cuts.

But overall, the world is still oversupplied with oil and we expect we'll see greater exports from Nigeria, Libya, Kazakhstan, Iraq, and Brazil. So we still feel like on the crude feedstock side, you're going have this competition between medium sour crudes and light sweet, where they're competing for available refining capacity, which will cause the medium sour discounts to be wide. And then with additional exports from Canada and South America on the heavy side, the heavies are going to have to compete with medium sours, and so we expect good discounts there. That's kind of a view of the crude markets.

On the product side, we think that the gasoline market, as long as you're in this low price environment, you'll continue to see good demand response on gasoline. And then on distillate, we expect a little bit more normal winter weather in both the United States and Northwest Europe will help the distillate market along with some recovery and economic growth, and we'll see a little bit stronger distillate cracks going into next year. Lane, I don't know what else you -- .

The only thing I'd comment on is tier 3. January 1 of this coming year is when tier 3 really comes into effect. There are people like us who generated credits with our existing units under tier 2, which put us in position not really needing to get all of our capacity up and running until 2020.

But different people -- or different companies and refineries are in different position with respect to that. So between 2017 -- beginning of 2017 and somewhere in the 2020 timeframe you'll see these units start up. That will destroy octane, so you should see alkylate and the premium regrade strengthen throughout that period.

Thanks. Secondly, if I could ask about your RINs guidance for the full year. We've lost our ability to track RINs prices on a regular basis, and I was hoping you could comment on where RINs prices are now. It would appear that there's either a price or a volume increase in the fourth quarter that would be required, given the first three quarters of expenses you've had to get into this $750 million to $850 million range.

Well, yes -- no, Jeff, look, what's going happen in the RINs prices going forward, we've heard a lot of RINs commentary about things that could affect the prices, so we have a forecast. We have a view. We set that out.

It's a pretty wide range accordingly, right, $750 million to $850 million. You can see where our actuals have been through the year. But we just have to stay tuned and see. We're not prepared to change it at this time.

Year-to-date we're at about $525 million is the expense. Second quarter was roughly -- or third quarter was roughly $200 million.

All right. Thanks for your comments.

And, Jeff, just one thing. We're not trying to be resistant to giving you guidance on this. But if you look historically at where they've been, from 2011 to 2015, I think RIN price averaged like $0.33. Last year they were like $0.55 -- $0.50 to $0.55. This year, obviously, they've been higher than that.

I think a lot of it comes down to where is the EPA going to set the RVO? And if they set a high RVO, where they're pushing us through the blend wall, we can all expect that we're going to have high RINs prices. And if they set it at a reasonable level that's achievable by industry, then we'll see it come off again.

There's so many reasons that it's high right now, but it is clearly those with length are taking advantage of those that are short, and we're seeing that in the speculation in the market. So again, it's an unregulated market with not a lot of transparency. It is really very, very difficult to forecast.

Certainly opportunity for substantial volatility. I appreciate that. Thank you.

Yes, sorry, bud.

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

Good morning, everyone.

Hi, Brad.

Gary, following-on on the OPEC question from earlier. I was curious specifically about Venezuela. I think it would be consensus that those are among the most at-risk volumes in the world right now. So I'm curious how much Valero takes from Venezuela, and also if you take any sort of net credit risk in your commercial activities with Venezuela?

Well, so I'll comment on -- really our volumes are not consistent month-to-month. They vary up and down, and I'll let Mike comment on the credit.

Okay. Most of the business that we have is with Citgo, but we really don't discuss our credit analysis and stuff with our various customers.

Okay, got it. And then, Mike, following-on on an earlier question about CapEx, maybe trying to attack it a different way. I think that year-to-date you guys have spent like $1.4 billion in CapEx. You've been doing like $450 million or $500 million a quarter.

So that would imply like $1 billion of spending in the fourth quarter. Is there any reason why that would be the case? Why the spending would go up so much? I know in the past sometimes you've included like an acquisition or something in those numbers. Is that what's responsible for it?

No, we don't include acquisitions in these numbers. I mean, it's the estimate that we have at this time. We've got the turnaround spend being finished here. And so that's the number that we've decided to give at this point. There's probably a little downside, or it will come in a little below that.

Okay. I'll leave it there. Thanks.

Thank you. Our next question comes from Spiro Dounis with UBS.

Good morning. Thanks for taking the question. Just wanted to follow-up on the payout ratio there and maybe narrow it a little bit and focus more on the dividend. I think the goal earlier this year was to get that dividend higher, closer to peers or at least at the top end of the range. And you're there right now. So, just curious your appetite to increase it from here as you head into next year and how that figures into your 75% ratio.

Well, we've already increased the dividend once this year. But if you look at how our history demonstrates, we would like to be in the position of increasing our dividend annually. And as you mentioned, our intention is to pay at the top end of the range, and so we'll monitor that and stay at the top end of the range as we move forward.

Got it. That makes sense. And then second question just wanted to follow-up on your comments around, export demand for refined products and maybe a few different angles here. We're surprised that it's actually held up this strong, because we continue to hear about the bloated stockpiles globally, anecdotally here about Chinese gasoline cargoes hitting the East Coast of the US. And so clearly lot of product out there.

And I'm just wondering how sustainable that demand is, if you can give us some granularity on where that pull is coming from, and how much is maybe refinery outages in South America that maybe you can't count on to always be there.

This is Gary. I think we continue to see very good demand for gasoline into Mexico and South America. I think in the short term some of that is certainly driven by refinery outages, but we see good growth in that region and expect that we'll see continued exports into those regions moving forward.

Certainly, the opening up of Mexico will also help us with our export business as well. Distillates we see good demand in both South America and the yard to Europe is currently open. So we see very good demand on the distillate side as well.

Got it. Appreciate the color. That's it for me. Thank you.

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

Hello, guys. Good morning. Nice results on the quarter. Gary, just following-up on that last comment on the exports, it looks like there was a pretty healthy decline quarter-to-quarter. And I didn't know if that's just seasonal in nature, if the arb window simply closed or anything like that. I didn't know if maybe it was potentially reflective of weakness in demand.

No, Blake, I'll break it apart. On the gasoline side we did 93,000 barrels a day, which is down some, but gasoline typically follows seasonal patterns. While you're in driving season here in the US, we typically don't export as much and it's more a statement of the strength of the US market rather than lack of demand into the export markets.

ULSD we did 236,000 barrels a day. If you add the jet and kerosene, we were at 283,000 barrels a day. There it was more a function of the turnaround activity we had in the Gulf. The Meraux hydro cracker was down and then we had the Port Arthur turnaround. And so it just limited the availability of export quality distillate into our system, and that's why the numbers are down on the distillate.

Got it. Okay. And then the second question. I realize you're not going to want to get into too much detail on guidance on this, but typically when we see a crude spike like we've see in this quarter, there tends to be a negative impact on the secondary product pricing and resid. And I'm just curious if you're witnessing some of that in the marketplace. I guess, what I'm fishing around on is, should capture rates maybe suffer a bit quarter-to-quarter as a result of the rapid increase that we've seen.

Blake, you're correct. Normally you would see that. The one thing that's different for us is we've seen that propylene prices spike fairly considerably. So the strength in propylene in our system thus far has really offset the negative impact of the secondary products that we would normally see when flat price goes up.

Good deal. Okay. Thanks a bunch. Appreciate it, guys.

And thank you. Our next question comes from Doug Leggate with Bank of America Merrill Lynch.

Thank you. Good morning, everybody.

Good morning, Doug.

I appreciate you taking my questions. Hey, Joe. So, Joe, on the buyback, dividend distribution, the 75% target. Given that you've obviously been running pretty well ahead of that, is there any consideration to either reconsider the absolute level or the balance between dividends and buybacks? And I've got a quick follow-up please.

Well, obviously, and I'll let Mike speak to this. But, Doug, obviously, we're always looking at that. And Mike mentioned earlier, okay, you use 75% of net income because it provides absolute transparency into what the number is, and that's one of the things that we use for planning purposes.

Mike's also looking at his percentage of cash flow dependent on how things are there. And then again, we continue to look at the balance between the dividend and the buybacks. In our view, though, the dividend is nondiscretionary. The buyback is discretionary.

And so we need to be very confident that we're going to continue to have cash flows and that we're going to be able to continue to manage the capital budget the way that the Company's done over the last couple of years to be sure that if we increase the dividend, we're good to go. So, Mike, with that what would you -- ?

I don't really have anything to add to that. The dividend is the commitment to the shareholder and that is our priority.

I guess, is there -- maybe I don't want to belabor this particular point, but in terms of dividend growth, if you were thinking kind of mid-cycle earnings level for the Company, is there an aspiration to have a dividend growth target on top of that, or are we just going to stick with the 75%?

Well, for now we're going to stick with the 75%, Doug. And I think we've answered it. We're not going get pinned down right now on announcing a dividend increase, that's for sure. But I think we're going go ahead and stick with the 75% for the time being and we'll continue to look at it.

Okay. I appreciate that. My follow-up hopefully a quick one is, as the earnings mix changes a little bit, as you see more coming from the MLP obviously over time, what's the guidance on the tax rate going forward? Because, obviously, it's consistently been at a pretty better level, compared to what we would have expected. So, this run rate for the tax rate and I'll leave it there. Thanks.

Well, this quarter we had a couple of items that benefited our tax rate. Our guidance was 30%. We had the Aruba disposition and that provided, I guess it was about 6% improvement on the tax position. We had the favorable settlement on an income tax audit. That provided about 4%.

So those would have given us a 28% when you back those out. Our guidance was 30%. So we had a few minor things. Going forward, 30%, 31% looks like a good number.

Got it. Thanks, fellows.

And thank you. Our next question comes from Ed Westlake with Credit Suisse.

Good morning. Maybe just to follow-on from Doug's question on the dividend in a different way. You are investing just under $1 billion of growth capital, which should provide some sort of uplift to EBITDA over time.

Is one way to think about it is, you've got this net income payout and you're willing to sort of keep that flat, and then as this growth capital comes in, you could perhaps use that to drive the dividend higher? And then specifically, on that growth capital, talk a little bit about the funnel to maintain that $1 billion level and maybe the split between refining and logistics just at the very high level.

On our capital, I think next year we're looking at similar to our budget for 2016, about $2.5 billion, $2.6 billion. $1.5 billion of that will be for sustaining and maintenance capital, about $1 billion or so for growth capital, and that will be split about 50%-50% between refining and logistics. So right now we're comfortable at the 75% target on the payout, so that's where we're at on that.

Ed, that was -- your question was kind of a mouthful. But it was -- it's hard to say that, okay, all the incremental income produced from growth projects is going go into the dividend.

If we knew what margins were going to be in two months, if we were selling something where we could set the price and set the margin and just the only issue is how much are you going to manufacture, it'd be wonderful. But that's not the way this business functions.

And because we've made the commitment to the dividend, we're very careful with it. We've also told you guys, we're not going to sit here and accumulate cash. And that's why we've gone ahead and exceeded the payout ratio target of 75%, because we've had stronger cash flows than we had anticipated. And so we've gone ahead and used the funds accordingly.

We have a lot of discipline around the capital budgeting process, and you're not going to see that whipsaw significantly. So, it's not like Lane and Gary and Rich are running out trying to find another $1.5 billion of capital projects so that we can spend the money.

So anyway, I think that you should expect consistent performance from us on this. And, again, we will continue to look at the dividend and I would expect, as Mike said, that we would continue to try to increase the dividend. But we're not prepared to commit to it right now.

Okay, and then the second one is, unfortunately, another follow-up on RINs. So do you think that the November ruling would actually deal with the point of obligation? And if they do deal with the point of obligation and say move it to the blending racks, what would be the impact on your RVO in total?

Well -- .

Because presumably you have a big impact, but just trying to get a clarity on that.

Yes, I'm just trying to think through how to answer that. And I think I would rather not, because we haven't given any guidance on what our absolute RVO is. So giving you a number for it after the fact, but it would go down materially. So -- .

And then on the EPA - sorry -- .

Go ahead, buddy.

Sorry. On the whether this ruling at the end of November is actually going to deal with the point of obligation.

Yes, I don't know. I don't know what their plan is. I would love to think that they were going to do it, but all we've got commitments from them on so far is that they're going to announce the obligations.

It would be very nice if they would open up our petition to a rule making on it so that we could have some conversation around it. And as Jay mentioned, if they would do that, then we would see some effect on the RIN price. But I'm not been very good at trying to predict exactly what they're going to do.

Okay. Thanks very much.

And thank you. Our next question comes from Paul Sankey with Wolfe Research.

Hi, everyone. Just if I could immediately follow-up while we're on the dreaded subject. Joe, did you petition as Valero because -- why didn't the refining industry lobby petition as opposed to you guys doing it individually? Is that an evidence that's there's a split amongst refiners?

Well, okay. So first of all, we did it because it's a material issue to us and we're a large refiner, and we're going to do what's best for us. Secondly, the AFPM did also file and their petition is similar to ours to move the point of obligation.

So it -- your third question is, is everybody in the industry of a like mind on this? The answer would be no, and it depends on where you happen to sit. If you're long RINs with a more integrated system through retail, I think you're going be a lot more comfortable with the status quo.

And if you're an independent refiner or a retail marketer that doesn't have the ability to move up the rack, then you're going to want to see this point of obligation moved. Paul, from my perspective, it's a very simple point of view. It is, you create a situation where the obligation and the point of compliance are two different points, and they shouldn't be.

And so it's -- by moving the point of obligation, obviously, we align the natural point of compliance with the natural point of obligation. And a lot of this speculation in the RINs market goes away. People will not be incentivized to build inventories of RINs to hold out for higher prices, to squeeze the shorts as we've seen. So anyway, I answered you, which -- .

You did. I think earlier in the call, Joe, you said you thought it would be resolved. I guess, then subsequently you seem to be saying that you're not very good at predicting it and you're not sure what will come out in November.

I think that it's going be resolved, but I do not know that it's going to happen before this election cycle happens. And then you tell me what the Obama administration's going to want to deal with between November and January. I can't predict that.

Something tells me it's not going to be RINs, Joe. (laughter) (multiple speakers) If I could just ask about the CapEx. Actually you did define how much was growth, how much was maintenance. Are we assuming around $800 million of turnaround? I don't know if you said you didn't want to comment on that. I think that the guidance was originally maybe for $1 billion this year of turnaround and is being dropped. I'm sorry if I got the numbers wrong.

Typically, our turnaround expense is $700 million to $800 million on an annual basis.

Yes, so that's what you'll be assuming for next year then?

Yes, I think that's fair.

That's great. And I just guess the final one would be, the net income target that you've talked about, the fact that you're sailing over that, why don't you look at it just purely from a cash point of view? Because you said that, because of the strength of cash, you're paying out more. Wouldn't it be smarter or easier for us all to just use a cash-on-cash dividend target? And I'll leave it there. Thanks.

Well, we feel like that the net income is very transparent. There's a lot of things that flow through the cash flow item like working capital items and such that you could have wild swings on your cash flow generation, and so our preference is net income.

Got it. Can I have a final one?

Paul, that's four now. You'll get me in trouble here. (laughter)

Give him one more.

Okay.

While I've got Lane. Could you just talk about the recent draw on inventories that we've seen, Lane, and imports of crude? What's your perspective on that somewhat surprising series of draws that we've seen? And I'll leave it there, I promise. Thanks.

Hey, Paul. I'll have to defer to my friend here, Mr. Gary Simmons, on that.

Yes. Paul, so you see these Brent TIR swinging back and forth, and so what we get into is that TI gets priced to where some barrels leave the Gulf and then the arb comes back in and incentivizes imports. So what we've seen is, we saw some barrels leaving the Gulf. It's imbalanced today to where St. James is marginally getting to the point where you would want to import barrels again. So that's what you've seen in the crude markets.

Cool.

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

Thanks. Good morning.

Hi, Chi.

Hi, Joe. I appreciate your legal and policy change focus on the RINs. But are you specifically implementing any strategies right now to reduce your RIN purchase obligation through increasing terminal exposure, changing commercial arrangements, or any other measure?

Yes. Yes to all of the above, and trying to continue to build the wholesale business. So we're looking at all those things. Those are the levers that we've got to pull, and then exports is the other one. And I think Gary and his team continue to look at the economics of exports with the RIN in mind, and so we're trying to manage our costs down every way we possibly can.

Does M&A focus on the midstream side? Is this a big priority, when you look at midstream growth position?

Yes. No, it's a priority. Obviously, we've seen a lot of things transact here and we've looked at a lot of things. But it is a priority for us, Chi. I think we'd like to -- again, as we said earlier in the call, we'd like to find assets in a perfect world that had third party volume and supported Valero's core business, but either/or is good with us.

Thanks. And then second question, your refining OpEx performance is pretty stellar. I imagine low gas/nat gas prices are a part of it, but I suspect there's probably more to that. Can you talk about the Company's efforts on the cost front? Gulf Coast, you're trending at $3.50 a barrel, which is pretty amazing for your complexity there. And also North Atlantic, looks like you're way down on OpEx relative to the past few years. So any comments on that end would be helpful.

Chi, I'm just going to be -- I'm going to answer this in general. It's a core value for us to manage our expenses aggressively all the time, but we do that in light of being very reliable. One of the tenets of our operation is we believe we get to a lower cost business by making sure that we implement our liability programs, so we minimize big one-time events that can turn into very expensive expense events. And that's essentially the way we think about running our business.

Is there something specific in the North Atlantic? Because it really looks like it's been measurable on the production.

No.

Okay. Thanks, Lane. Appreciate it.

Thanks, Chi.

Thank you. Our next question comes from Sam Margolin with Cowen and Company.

Good morning.

Hi, Sam.

I wanted to go back to 2017 CapEx, if that's all right. The gated process to the capital program sets up a possible scenario where your growth CapEx number could be a lot lower than it has been this year or previous years or what you just mentioned for 2017.

Given the fact that the refining cycle has been challenging this year and it would have been hard for people outside the fence to really easily identify a really good project in this kind of market. What is that -- what would it take for the growth CapEx number to come down to a level that we haven't seen for a while?

And then that would introduce another list of possibilities on the return of cash side, and maybe if you could talk about how those two things are linked, too.

Do you want to talk about capital?

Sam, this is Lane. It's an interesting question. I wouldn't say that we have a complete shortcoming of potential projects. We have a strategic outlook, which we believe is we have -- we believe that octane is going be in short supply going forward and we believe feedstock flexibility is something that we're always continuing to look at.

I'm not going to say that there's not the possibility that somehow our growth CapEx will fall. But we have plenty of small, fast hitting projects that compete in that space. You also got to remember, we have a strategic -- we're strategically trying to get the right network on our secondary costs through building those assets and dropping them into the MLP.

And that's, as Mike alluded to earlier, that's about 50% of our growth CapEx for next year. So .

We -- Sam, the fact that we're not out there talking about a bunch of capital projects just goes back to the fundamental principle that we're operating by, which was we don't talk about them until we're confident we're going to do the project. Again, we don't want to get out over our skis and overcommit and then end up needing to back it down. So I don't think you should read anything into a lower capital number based on lack of opportunities that we're looking at.

Okay. And then, just following-up on a comment you made in the introduction about some positive signals you're seeing in US unconventional upstream. The new crude units position you pretty well for that inflexion.

I remember in the first quarter you gave a result for the first one. I think it was $30 million of EBITDA, which put you right on the fairway of guidance. But production wasn't growing -- at the time production was declining in the US. So at this point can you catch us up a little bit on the performance and establish whether we have seen proof of concept in those projects by this point?

So, Sam, this is Lane again. Our for funding, or FID EBITDA for those projects, for Corpus it's $150 million and for Houston it was about $130 million. And so in the third quarter, they both per unit contributed about $45 million a piece. So you can look at the run rate and they're clearly in line with what our funding decisions were with respect to-- on the EBITDA basis.

Okay. Thanks so much.

And thank you. Our next question comes from Fernando Valle with Citi.

Hi, guys. Thanks for taking my question. I'll keep it brief. Just quickly on the change in regulations, IRS regulations for partnership liability and disguise sales, does that impact your plans for dropdowns into VLP for next year at all? Did they have any impact on previous drops into VLP? Thank you.

It does not have any impact on the previous drops into the MLP. It's not retroactive and it really has no material impact on our plans, on the EBITDA, the amount of EBITDA that we have to drop.

Great. But do you expect a major impact as far as the potential tax liability for VLO on dropdowns? Or it doesn't really impact on -- ?

No, it's not material to the tax liability that we're already incurring.

Okay. Thank you.

And thank you. It seems we have no further questions at this time. I will now turn the call back over to John Locke for closing remarks.

Okay. Thanks, Vanessa. Thanks everyone for calling today. If you have any additional questions, please contact me or Karen Ngo after the call. Thank you.

And thank you. Ladies and gentlemen, this concludes today's conference. We thank you for participating and you may now disconnect.