Valero Energy Corp (VLO) — Q1 2016 Earnings Call Transcript

Good morning, and welcome to Valero Energy Corporation's First 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 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 one on our website at Valero.com. Also attached to the earnings release are tables that provide additional financial information on our business segments. If you have any questions after reviewing these tables, please feel free to contact our Investor Relations team after the call. I would like to direct your attention to the forward-looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we described in our filings with the SEC. Now, I'd like to turn the call over to Joe for a few opening remarks.

Well, thanks, John, and good morning, everyone. The first quarter presented us with challenging markets with gasoline and diesel margins under pressure for most of the quarter. The bright spot was the performance of our team, as we continued to operate safely and reliably. What I'd like to do this morning is take a few minutes to discuss our strategic initiatives that we believe will continue to drive long-term value creation and then share some color on what we are seeing in the markets. First, at the core of everything we do is a relentless focus on safety and reliability. Our dedication and persistence here is what keeps our people and community safe, our operations reliable, our cash operating costs the lowest among the peer group. Having low-cost operations is a major advantage in our industry where product margins can be quite volatile. As a disciplined operator, we are able to run profitably in a lower margin environment as experienced in the first quarter. Second, we apply discipline and rigor, as we evaluate and execute investments that will grow the profitability and competitiveness of our business for many years. The strategic plan that was approved by our board of directors last year included $2.6 billion of capital spending for 2016. Approximately $1 billion was allocated to strategic investments to drive long-term earnings growth. Third, we are committed to delivering value to stockholders by making the right investments in our business and returning cash to our stockholders. We demonstrated this in 2015 when we delivered the highest total stockholder return among our peers for both Valero and VLP. We expect VLP to continue to be well positioned to execute its distribution growth strategy through 2017 despite volatile capital markets. We also continue to keep an eye on M&A. We review opportunities and we have a list of targets that we consistently monitor. We consider M&A a discretionary use of cash, so there's a healthy tension when evaluating M&A opportunities versus other alternative uses. Of course, we can't comment specifically on M&A, but we are diligently reviewing opportunities. For cash returns in 2016, which is made up of dividends and buybacks, we've extended our 2015 payout target of 75% of net income. In January, we increased the quarterly dividend by 20% to $0.60 a share, but we remain focused on maintaining a dividend payout at the high end of our peer group. We're confident in Valero's ability to fund investments in future growth and to meet its payout target. Lastly, let me share some color on the current market. Already this year, we've been in a lot of conversations about various market topics including gasoline demand resurgence, octane strength, diesel length, domestic crude supply, and crude storage levels. As you know, markets for Valero's feedstocks and products are dynamic. Our high complexity refineries, system flexibility, advantage locations, and low cash cost operations enable us to maximize earnings under challenging market conditions. On the crude supply side, we are seeing more medium sour crudes coming into the market. As a result, we are seeing healthy medium and heavy sour crude discounts. We also have greater access to domestic sweet crudes with the logistics build-out in the U.S., allowing domestic production to clear the Mid-Continent region and reach the large Gulf Coast refining center. On the demand side, continued GDP growth and low product prices should continue to support demand. In the U.S., we are seeing gasoline demand continue to grow. We are encouraged by increased vehicle miles traveled and double-digit percentage increases in SUV and truck purchases in the U.S. and key countries around the globe. Distillate demand globally was good, albeit in the U.S. it's been fairly flat. While distillate margins were pressured near term due to unseasonably warm weather in North America and Europe, distillate demand in Latin America remains robust. Overall, we still have structural refined product supply challenges in South America and the developing countries, which we don't expect to be resolved in the near term. With our low-cost Gulf Coast refining presence, we have the ability to compete in markets all over the globe. We also have the opportunity to optimize our system and supply in the Atlantic basin with our refineries in Wales and Québec City. In fact, we generated another quarter of solid distillate and gasoline export volumes. In summary, we still have significant crude supply, ample natural gas availability and growing global petroleum demand that's outpacing refining capacity additions. We don't see this changing anytime soon, so although the markets will be challenging at times, the longer-term macro outlook remains favorable. So, with that, John, I'll hand the call back to you.

Thank you, Joe. Moving on to the results, net income was $495 million or $1.05 per share for the first quarter of 2016. Excluding an after-tax lower of cost or market inventory valuation benefit of $212 million or $0.45 per share, we reported first quarter 2016 adjusted net income of $283 million or $0.60 per share. This compares to $964 million or $1.87 per share for the first quarter of 2015. For reconciliations of actual to adjusted amounts, please refer to page six of the financial tables that accompany our release. Adjusted operating income for the refining segment in the first quarter of 2016 was $695 million or $946 million lower than in the first quarter of 2015. Margins were pressured downward primarily due to weaker distillate margins given high refinery run rates across the industry, product inventory builds and unseasonably warm weather. Other headwinds on refining margins included narrower domestic light sweet crude oil discounts versus the Brent benchmark, low fuel oil and petrochemical product margins, and elevated costs for RINs credits. Low crude oil prices continue to drive slowdowns in North American drilling and production, which coupled with an excess of pipeline takeaway capacity in the Mid-Continent region led to tighter discounts for crude oils relative to Brent. Low energy cost supported by robust North American natural gas production partly offset these factors. Our refineries operated at 96% throughput capacity utilization in the first quarter of 2016 and throughput volumes averaged 2.9 million barrels per day, which was 169,000 barrels per day higher than in the first quarter of 2015. Refining cash operating expenses of $3.55 per barrel were $0.40 per barrel lower than the first quarter of 2015 mostly due to higher throughput volumes and lower energy costs. The ethanol segment earned $9 million of adjusted operating income in the first quarter of 2016 compared to $12 million in the first quarter of 2015. The low crude oil and gasoline price environment challenged ethanol margins, but with the recent recovery in prices, ethanol margins had modestly improved to start the second quarter. For the first quarter of 2016, general and administrative expenses excluding corporate depreciation were $156 million. Net interest expense was $108 million. Depreciation and amortization expense was $485 million, and the effective tax rate for the first quarter of 2016 was 30%. The effective tax rate was lower than the first quarter of 2015 primarily due to higher relative earnings contribution from international operations with lower statutory tax rates. Regarding our balance sheet, at quarter end, we had $7.3 billion of total debt and $3.8 billion of cash and temporary cash investments, of which $102 million was held by VLP. Valero's debt to capitalization ratio, net of $2 billion in cash, was 20%. We had $5.5 billion of available liquidity excluding cash, of which $575 million was only available to VLP. Cash flows in the first quarter included $479 million of capital investments, of which $161 million was for turnarounds and catalyst. For 2016, we expect to invest $1.6 billion of capital to sustain the business and $1 billion for refining asset optimization and logistics to drive long-term earnings growth. With respect to our refining growth strategy, the new Corpus Christi crude unit, which was completed late last year, operated as planned and delivered approximately $35 million of EBITDA in the first quarter. We completed the St. Charles hydrocracker expansion in March, and the new Houston crude unit is on track to start up in the second quarter. The Houston alkylation project, which was approved in January, is now undergoing detailed engineering and procurement. Completion of the alkylation unit is expected in the first half of 2019. Moving to the financing activities, we returned $547 million in cash to our stockholders in the first quarter, which included $282 million in dividend payments and $265 million for the repurchase of 3.8 million shares of Valero common stock. We had $1.1 billion of remaining share repurchase authorization as of March 31, 2016. Our regular quarterly cash dividend is now $0.60 per share. We continue to target a payout of 75% of annual net income for 2016. For modeling our second quarter operations, we expect throughput volumes to fall within the following ranges: Gulf Coast at 1.59 million barrels per day to 1.64 million barrels per day; Mid-Continent at 430,000 barrels per day to 450,000 barrels per day; West Coast at 260,000 barrels per day to 280,000 barrels per day; and North Atlantic at 450,000 barrels per day to 470,000 barrels per day. Refining cash operating expenses are estimated at approximately $3.75 per barrel for the second quarter. Based on today's market prices, we expect costs relating to meeting our biofuel blending obligations to be between $750 million and $850 million for 2016. This is primarily related to RINs in the U.S. The ethanol segment is expected to produce a total of 3.8 million gallons per day. Operating expenses should average $0.37 per gallon, which includes $0.05 per gallon for depreciation and amortization. G&A expenses for the second quarter, excluding corporate depreciation, are expected to be approximately $165 million and net interest expense should be about $110 million. Total depreciation and amortization expense is estimated at $465 million and our effective tax rate is expected to be 31%. This concludes our opening remarks. Before we open the call to questions, we respectfully request that callers limit each turn in the Q&A to two questions. This will help us ensure that other callers have time to ask their question. If you have more than two questions, please rejoin the queue as time permits.

Good morning, guys.

Good morning, Neil.

Joe, you made reference to seeing opportunities in the M&A market in your opening comments. Of course, recognize that you can't comment on anything specific but can you talk about either scale, large-scale or small-scale, or whether those opportunities are more midstream-focused versus refining-focused?

Okay. Neil, I'll provide some color here in a second, but let me let Mike go ahead and speak to this.

Yeah, Neil, we're looking at the opportunities that are available to us both on the refining and the midstream side. We do have a target list as Joe alluded in his comments. Some of those are corporate-related, some of those are asset-related. So, I can't provide any more specifics than that at this point.

You know, Neil, when we look at these though, I mean obviously you want to try to find opportunities where you can buy good assets and where you can achieve synergies in it. And that's certainly true on the refining side. I'll just be honest right now, there's not a whole lot that's being shown to us, but we do have our target list and there are a few conversations that are taking place. Then on the M&A side, it's like Mike said, I think if you think in terms of the type of deal we're going to do, it's not likely going to be some kind of large corporate deal. It's not going to be a step-out deal, but it will be more asset-focused and perhaps in the context of a partnering arrangement with people that are looking at transactions or want somebody to share in their pipe. So nothing super hot right now, though.

I appreciate that, guys. And then secondly, on the distillate market, you made a reference to the fact that it is tough out there in terms of the margins for distillates. And part of that was weather, but part of it seems to be both supply and demand for the product. How do you see that going forward through the balance of the year and then can you talk about what you're seeing in terms of the export market for distillate and if that's ultimately the flywheel that can help rebalance the market?

Okay, Neil. This is Gary. Yeah, I think what we've seen on distillate, we came out of winter with a lot of overhang in distillate inventory as you alluded to. And then on the demand side, you get into March and demand was way off and we've certainly seen for the past several weeks, demand continue to creep up. We've seen some good agricultural demand begin to kick in and so we've trended to where we're now more towards the five-year high, actually last week above the five-year high. So I think some of this demand will help clean up the inventory. And then also, you talked about the exports. We're seeing a lot of good opportunities to export distillate as well, so the combination of the two of those things, I think, will help keep domestic inventories in check. Moving forward, I think as flat price continues to rise, you'll start to see some recovery in the upstream sector, which should improve distillate demand as well. But really we'll have to wait and see if we have a more normal winter this winter and that'll be a key driver in terms of what happens with the distillate fracks moving forward.

All right. Thanks, guys.

Thanks, Neil.

Hey, guys. Good morning. I was hoping to get a little color on your thoughts around the drop-down targets. I believe you have a $1 billion target. I think year-to-date you've done about $240 million, but just in light of kind of some of the challenges we're seeing in the midstream, can you just share your thoughts around how you're thinking about that $1 billion target this year?

Yeah, Blake, sure. This is Mike. Before we get into that target, though, let me start off by talking about the capital markets. VLP does not need to execute any drops to meet its 25% distribution growth through 2017. So VLP does not need to access the capital markets. That being said, we believe the capital markets, both debt and equity, are open for MLPs, particularly high-quality MLPs like VLP. The cost of issuing debt or equity, however, remains more expensive than historical levels. The good news was VLP is well positioned with strong distribution coverage and does not need access to the capital markets from this price environment. Therefore, we are going to revise our drop-down guidance to $500 million to $750 million. We can execute drops in this range without going to the capital markets. We are going to continue to prepare for $1 billion in drops and will be ready to execute $1 billion in drops if the capital markets improve. From a Valero Energy perspective, regardless of whether or not we drive $500 million or $1 billion worth of assets this year to VLP, this amount will not materially change our view on our payout guidance.

Got it. Okay. Thank you, Mike. That's helpful. The second question and this may tie in a little bit with Neil's M&A question, but the amount of, I guess, capital returned to shareholders, $547 million, is well above your adjusted earnings, so you're obviously well on track with that net income target. Obviously 1Q is a little weak, so maybe you see some improving earnings going forward? But I'm just curious if you were to identify some M&A opportunities, does that materially change your thought on this 75% net income target?

I would only say that we would have to look at that at the time of the acquisition. I mean, if it was a huge acquisition that might require some equity, then obviously we'd have to rethink about the buyback target. But it's going to be – right now I'm going to say no, but depending on the size of it, it could.

Hey, guys, good morning.

Good morning, Paul.

I think the first one is for Joe and maybe then for Mike actually. On the financial strategy, I mean are you guys actively looking at and evaluating opportunity on M&A? From that standpoint, Mike and Joe, should we be more maybe conservative on the bond shape and maybe put some of the free cash flow back on the cash so that you will be ready when the opportunities strike?

Our balance sheet, Paul, is very, very strong. We want to keep it that way, but it's very strong. I think right now rather than building cash, we're going to continue to look for opportunities to grow our business and our EPS.

And, you know, Paul, I mean you saw the cash balance that we've got. As Mike said, our leverage levels are very low. We came through a tough quarter with this balance sheet. So I think we are pretty well positioned and I would tell you, though, if there was a significant M&A transaction out there, we would do the right thing as you would expect us to do and perhaps build some cash before we execute the transaction.

Okay. The second question, maybe this is for either Gary or Lane. In the first quarter, your system-wide margin capture rate versus your benchmark is about 62%. In the first quarter last year, it's about 70%, and your average in 2015, 2014 is about 72% and 67%. So, just curious that in the first quarter this year, there much lower margin capture rate. How much is related to just the different pricing environment in the macro fund and how much is related to more company-specific reason? Any kind of insight would be great.

Hey, Paul, this is Gary. I can start with, I guess it's hard to go into a lot of detail on the capture rates here, so certainly invite you to follow up with Karen and John after the call, but on some high-level things, I can tell you in terms of volume variance, there really wasn't a negative impact on volume variance for refineries. Actually, we would show that the volume variance was slightly positive for the quarter. So, what you are seeing on the capture rates is all market-driven. At a high level, there's a few things I would point to. The higher cost RINs certainly had an impact on our capture rates. The butane differential, the gasoline was much more narrow in the first quarter than what we saw last year that had an impact on the capture rates. In the North Atlantic basin, when you look at our crude cost relative to Brent, the narrower Brent-TI arb impacted our crude cost most importantly at Québec. Also the Western Canadian crudes, the Syncrudes were more expensive in the first quarter, so the volumes coming off Line 9, so we had a crude cost impact to our North Atlantic basin system. And the only thing that's really operationally we had the Benecia cat down on the West Coast for a planned turnaround, and so our capture rates there were down a little bit as well, but those are some of the real key factors.

Gary, can I have a quick follow-up. On the second quarter, your turnaround activity, is it focusing on the conversion unit or that is crude unit?

Hey, Paul, this is Lane. We don't give second quarter guidance with respect to what kind of capacity we'll have in turnaround, so.

All right. Will do. Thank you.

Hi, good morning.

Good morning, Phil.

First question on the Gulf Coast, your crude slate clearly shifted more towards mediums. On your slide deck, you have given a range historically for heavies of about 24% to 37% over time, and you were at the low end of that range 24% in the first quarter. That's actually down year-over-year, so I know you talked about the medium and heavy discounts becoming available. Were there any one-time factors that led you to have actually lower heavies in the quarter or just generally how are you thinking about crude slate as we progress through the year?

Yeah, Phil, this is Gary. A couple of things, the way we report our results, we have the heavy sour crudes shown, but we also have a category we show resids, and some of those resids are actually replacements for heavy sour crudes in our system. We run the resids through our crude unit, and so where the heavy sour crudes were down, actually the resids we processed were up. So there really wasn't a significant difference in the amount of heavy sour crude we ran in the first quarter. In terms of the range, some of the things that we talk about, it's not just the discounts that we are looking at, there is a rate lever associated with really pushing heavy sour crudes in our system. If we want to maximize heavy sour crudes, they generally mean we are running at lower throughput, so we have to look at the discounts and also where the crack spreads are, and then we do that optimization.

Got it. Okay. Follow-up question just on the M&A front. With respect to refining to the extent you are looking there, could you just remind us how you think about regionally where you'd want to be adding exposure?

Yeah, I mean, if you look at areas that we feel that we could grow, okay, and I'm doing this from just historical looks at different assets and how the FTC might view something, the West Coast, California in particular, will be very, very difficult for us. We are not really focused there. The East Coast, we've exited and so we're not interested there. The Mid-Con, I think we would be good to go on transactions and we'd be interested in there and then of course U.S. Gulf Coast. And when we look at the acquisitions, we look at them from a perspective of where can we create the greatest synergies. And with the portfolio of assets that we have in the U.S. Golf Coast, we believe that we can create synergies around feedstocks and product movements there perhaps better than anywhere else now. So, that would be the U.S. side. If we go over to Europe, I think we'd be interested in assets in markets like the UK where we've got a presence today and we could bolt something on and support it out of the London office. We're not interested in a lot of the countries in Western Europe just because of the nature of the assets and then the issues that go along with owning assets in those markets. And then I really think from our perspective, the Far East is off the table. So, in a nutshell, the U.S. Gulf Coast would be interesting, the Mid-Continent of the U.S. would be interesting, the UK would be interesting, and that would be our primary focus.

Okay. That's helpful. And if I could just sneak one last one in on RINs? Do you have what the actual RINs cost was in the first quarter of this year relative to first quarter of last year?

Well, we probably do.

Yeah, $161 million versus $133 million last year.

Okay. Perfect. Thanks.

Yeah, good morning.

Good morning, Roger.

I guess let me jump into the gasoline demand, obviously positive comments to start it off. Now that we're getting into the early part of summer driving season, summer grade gasoline, how is the octane market shaping up? Are we seeing significant supplies, any shortages in any particular regions? And just how you look at that as we roll through the rest of the second quarter?

Hey, Roger. This is Gary. I think we're seeing a very similar situation in regards to octane what we've seen the last couple of years. Octane's starting to get tight, so we saw the regrade in the Mid-Continent strengthen significantly. The premium regrade on the West Coast has also strengthened considerably in the last couple of weeks, so I think the industry's short of octane and we'll see similar regrades to what we've been seeing in the past few years.

So, no reason to think there's any sort of surplus octane out there at all at this point?

It doesn't appear that way to me.

Okay. Great. And then just a follow-up on your comment on the diesel demand side, underpinned by the agricultural seasonality. I assume that backs off somewhat as we roll into the middle of the summer. Do you see any other places in the market where demand has picked up or has at least solidified versus where it was in the wintertime?

I think going forward the thing we're looking at is our exports. And so you look to us and yesterday the JBC global refining margin showed Northwest Europe simple capacity at like $0.23 margin, so it doesn't take diesel falling off much before some of that low complexity capacity has to cut and as they cut, it'll open up even greater opportunities for us to export our barrels moving forward.

Okay. That's great. Thank you.

Hi, everyone. I'm not quite sure what I was called just there and I'm not going to repeat it.

Paul, it's better than probably some of the things you've been called.

Thanks, Joe. Appreciate that.

Just kidding.

Joe, you came in as CEO very clearly talking about cash return, a big jump in the dividend. I'm not quite sure why today you're suddenly saying you're going to buy stuff. If I missed something, is that mostly for VLP that you're talking about or is this a change in tone? And further to that, the macro follow-up, it seems like we got a really good environment in terms of demand and everything else out there, particularly for you guys with the heavy/light spreads and stuff, heavy sour. Why are margins not better and is that related to oversupply, do you think, which would further underline that you wouldn't want to be growing in this market? You would want to be shrinking. Thanks.

All right. Well, I'll go first. You know, Paul, I'd say M&A is something that we've had in our capital allocation framework for the last two years and that really hasn't changed. Now it seems like you and your peers are the ones that are interested in that perhaps more than we are. When we look at our approach to trying to drive EPS growth over the next three years to five years, it's really multifaceted and it includes growth investments in refining and midstream. We also look at M&A and we look at share repurchases and we've got a really good pipeline of refining projects that are under development. Now we don't want to get out over our skis, so we don't really discuss the specifics on these projects that are in development until we've gone further down the approval process. But we do have a bunch of great projects that exceed the 25% IRR hurdle rate that we've talked about and we'll try to do as many of those projects as we find. Midstream investments are of interest. They've got a lower hurdle rate, as you would expect, but they will drive earnings growth through optimization, so these are critical to us also. Then when we look at the discretionary uses of cash, M&A fits into that category for us. And really what I just want to communicate on that is that the assets that we would look at there, Paul, would be those that create synergy and would be accretive to the company. We've got a great portfolio today and we do have that tension between the use – the discretionary use of cash via this framework that we put in place and we are not going to do an acquisition, and that's why you've seen we haven't pulled the trigger, we're not going to do an acquisition if we believe it's more accretive to do a share repurchase. So anyway, return of cash to shareholders hasn't lost its priority at all from our perspective. It's just we are looking at that, growth projects and M&A as a competitive use of funds.

And, you know, Paul, I mean you're seeing the cash balance that we've got. As Mike said, our leverage levels are very low. We came through a tough quarter with this balance sheet. So I think we are pretty well positioned and I would tell you, though, if there was a significant M&A transaction out there, we would do the right thing as you would expect us to do and perhaps build some cash before we executed the transaction.

Well, I guess, Joe, just to quickly throw in a follow-up. You're still running with the share of net income target paid out, I guess?

Right. That's right.

And then, do we think – are we oversupplied in this market? Is that why margins are not better for what should be seemingly a much better environment?

Yeah, I think so. You have a couple of key factors. We keep pointing down the distillate side. The warmer weather in the United States and Northwest Europe certainly hindered these demands coming through the winter and so it created this overhang we are living with today. I think the other thing that happened is the combination of relatively strong frack spreads in December and January incentivized higher utilization than what we typically see. In combination, the strong carry in the market and refiners that typically aren't running high utilizations in December and January, running high utilizations and selling their product forward, so those things kind of all contributed to build some inventory and it will just take us a little while to work that inventory off.

Understood. Very quick follow-up. Could you just update us on the impact what you're seeing in Venezuela in terms of if there is impact there and what sort of lost volumes there are? And I'll leave it at there. Thank you.

Thanks, Paul.

Yeah, so, Venezuela was very important piece of our crude supply situation. We've had a very good longstanding relationship with PDVSA. What we've seen is we really haven't seen a decrease in oil coming out of the country. What we have seen is with some of the rolling power outages that they've had, that the grades of oil are changing so we are seeing a greater percentage of diluted crude oils and less of some of the synthetic crude oils into our system, but our system is robust enough to be able to absorb that, so we buy those barrels and continue to run them into our system.

Good morning.

Hi, Jeff.

Joe, in your initial comments, you talked about seeing more medium sours on the market and we are seeing that roll through the DoE statistics historically for January and February. I was hoping you could comment on some of the recent press releases that have highlighted increased supply coming out of Iran, Iraq, Saudi Arabia and some of the other Middle Eastern countries. Are you seeing increases of volumes coming from the Middle East coming into the market?

Yeah, Jeff. Let Gary answer this. He's in the market every day.

Yeah, Jeff, so we certainly are seeing that. I think on the Iranian barrels, of course we don't run any Iranian barrels, but what we've seen there is kind of some rebalancing in the market, so some of those barrels are making their way into Europe and we're seeing some of the Russian Urals come back into the U.S. market that we haven't seen here for a while. And then, yes, we are certainly seeing a lot more Saudi barrels flowing this way. We had decreased our Saudi volumes, but as they continue to put barrels on the market and they are competitive, we are ramping those back up on our system as well.

Yeah, good morning, guys.

Hi Faisel.

Hi. Just two questions. First on the gasoline margins, the realized margins between the Gulf Coast, Mid-Atlantic – or sorry, Mid-Continent, if I look at the markers for the quarter, certainly in the Mid-Continent, the diesel and gasoline minus TI margins were higher than the Gulf Coast gasoline and ULSD minus Brent margins, but the realized margins in the Gulf Coast are much higher, so I just want to make sure I understand sort of what's taking place there with the Gulf Coast realized margins being higher versus the Mid-Continent despite the product market being more profitable in the Mid-Continent, and I know you guys had some run cuts.

So, are you looking on a comparative basis quarter-over-quarter or are you just...?

No. Just in the quarter between regions. The Mid-Continent gasoline minus TI crack was stronger than the Gulf Coast gasoline minus Brent crack, but on a realized basis, it was still much stronger in the Gulf Coast than the Mid-Continent.

Yeah, so, I would say probably the key thing that contributed to that is that the Mid-Continent just had very, very high inventories. And so, in order to move product out over our wholesale racks, we were actually having to discount product in order to clear the refineries and so it lowered our realized kind of crack capture.

Okay, that makes sense. And then on light/heavy differentials, it looks like recently, just in the last week or two, the differentials sort of narrowed a little bit. Just wondering what you're seeing there despite sort of the talk of more availability of heavy sour crudes in the market.

Yeah, I think the thing that happened there is really the K and the Maya formula changed, and at the same time it changed, the Brent-TI arb came in and fuel oil strengthened a little bit, and so it really made it to where Maya isn't pricing competitive with medium sour alternatives or really even pricing competitive with Canadian alternatives into the Gulf, which tells me the Maya formula is going to have to change again and the Maya discount will have to widen going forward.

Okay. Thanks. Good morning.

Hi, Chi.

Hi. Your throughput guidance for 2Q felt a little bit light across all the regions. Was that turnaround-related or more economic-related decisions?

Yeah, Chi, this is John. We can't talk about forward turnarounds, but I mean we take a view of turnaround activity and then also markets to plan our throughputs.

Okay. Thanks. And then I am not exactly sure this is an M&A question specifically or more a broader U.S. market question, but it feels like the breakup of Motiva is potentially a significant development in the domestic downstream market. Kind of how do you assess these opportunities and maybe even the risk associated with that event?

Well, okay. I don't know that I've assessed it the way you're asking. I mean we understand that they had a partnership that they wanted to both exit and they decided to do that. I think Saudi is pleased with the assets that they got in the deal and Shell is pleased with the assets that they have in the deal, and that's really all we know about that one to be quite honest. I do not view this transaction, though, as a precursor to a whole series of other major similar type of transactions in the U.S., Chi. I just don't – we're not hearing it and we're not seeing it.

Do you think Aramco is looking to take more refining capacity here? And will the government even allow that, do you think?

Well, I can't – I'd only be speculating and I really don't have an opinion on it. Again, I think they'd have to find something that was for sale if they wanted to engage and I just don't know if there's a significant portfolio of assets out there that they could get into.

Good morning.

Good morning.

So, on U.S. crude exports, you touched on it for a second, windows not open all that often. But you're still seeing some upstream companies talk about it. There've been a couple of press releases. Have you seen any effect? And I ask in the context of the Corpus Christi topper, which sounds like it had a pretty good result in the quarter and doesn't seem really affected by either diffs or single cargoes exiting the Gulf whenever temporary windows open.

Yeah, this is Gary again. I don't think we've really seen any significant impact of the exports on any of our operations.

Okay. And that's sort of like – so the topper performance is essentially in line, you think, sort of operating with expectations in the current environment? Are there any commodity factors that are dynamic that affect that, if it's not differentials?

Hey, Sam. This is Lane. We started up in December our funding investment decision, which was about $150 million of EBITDA. If you use 2015 pricing, it made about $200 million and if you look at the last quarter, we're estimating it contributed about $35 million. So it's in line with our funding decision, and then Gary spoke to the market on it, so that's where the project sort of fits.

Okay. Any other factors that are affecting it?

Well, you have commodity risk all over the place. I think when we analyze a project, the one that we always stare at the most is naphtha. The Gulf has long naphtha with crude in it backed out resid purchases and so we always have a keen eye on the placement of naphtha that's created due to both of these projects, both the Corpus Christi and the Houston crudes. That's where I would say the greatest commodity risk is.

Okay. Thank you for your questions. We do need to wrap up since we've run out of time. Please contact me or Karen Ngo if you have additional questions after the call. Thank you.