Welcome to the Valero Energy Corporation Reports 2016 First Quarter Earnings Results Conference Call. My name is Bianca and I will be your operator for today. At this time, all participants are in a listen only mode. Later, we will conduct a question and answer session. Please note that this conference is being recorded.
I will now turn the call over to your host, Mr. John Locke. Mr. John, you may begin.
Good morning, and welcome to Valero Energy Corp. Q1 2016 earnings conference call. With me today are Joe Gorder, our Chairman, President and Chief Executive Officer Mike Cieszkowski, 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 our Investor Relations team after the call. I would like to direct your attention to the forward looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our filings with the SEC. Now, I will turn the call over to Joe for a few opening remarks.
Well, thanks, John, and good morning, everyone. The Q1 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 continue to operate safely and reliably. What I'd like to do this morning is take a 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're 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 communities 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 Q1. 2nd, we apply discipline and rigor as we evaluate competitiveness of our business for many years. The strategic plan that was approved by our Board of Directors last year included $2,600,000,000 of capital spending for 2016.
Approximately $1,000,000,000 was allocated to strategic investments to drive long term earnings growth. 3rd, we're 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 and A.
We review opportunities and we have a list of targets that we consistently monitor. We consider M and A a discretionary use of cash, so there's a healthy tension when evaluating M and A opportunities versus other alternative uses. Of course, we can't comment specifically on M and A, but we are 15 payout target of 75 percent 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 payoff 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, advantaged locations and low cash cost operations enable us to maximize earnings under challenging market conditions. On the crude supply side, we're seeing more medium sour crudes coming into the market.
As a result, we're seeing healthy medium and heavy sour crude discounts. We also have greater access to domestic sweet 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 continue to support demand. In the U. S, we've seen gasoline demand continue to grow.
We're 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 the Atlantic basin with our refineries in Wales and Quebec 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 $495,000,000 or $1.05 per share for the Q1 of 2016. Excluding an after tax lower cost to market inventory valuation benefit of $212,000,000 or $0.45 per share, we reported Q1 2016 adjusted net income of $283,000,000 or $0.60 per share. This compares to 964,000,000 dollars or $1.87 per share for the Q1 of 2015.
For reconciliations of actual to adjusted amounts, please refer to Page 6 of the financial tables that accompany our release. Adjusted operating income for the Refining segment in the Q1 of 2016 was $695,000,000 or $946,000,000 lower than in the Q1 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 costs supported by robust North American natural gas production partly offset these factors. Our refineries operated at 96% throughput capacity utilization in the Q1 of 2016 and throughput volumes averaged 2,900,000 barrels per day, which was 169,000 barrels per day higher than in the Q1 of 2015. Refining cash operating expenses of $3.55 per barrel were $0.40 per barrel lower than the Q1 of 2015, mostly due to higher throughput volumes and lower energy costs. The ethanol segment earned $9,000,000 of adjusted operating income in the Q1 of 2016 compared to $12,000,000 in the Q1 of 2015. The low crude oil and gasoline price environment challenged ethanol margins, but with the recent recovery in prices, ethanol margins have modestly improved to start the Q2.
For the Q1 of 2016, general and administrative expenses, excluding corporate depreciation, were $156,000,000 Net interest expense was 108,000,000 dollars Depreciation and amortization expense was $485,000,000 and the effective tax rate for the Q1 of 2016 was 30%. The effective tax rate was lower than the Q1 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 $7,300,000,000 of total debt and $3,800,000,000 of cash and temporary cash investments, of which $102,000,000 was held by BLP. Bluro's debt to capitalization ratio net of $2,000,000,000 in cash was 20%. We had $5,000,000,000 of available liquidity excluding cash, of which $575,000,000 was only available to BLP.
Cash flows in the Q1 included $479,000,000 of capital investments, of which $161,000,000 was for turnarounds in Catalyst. For 2016, we expect to invest $1,600,000,000 of capital to sustain the business and $1,000,000,000 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 $35,000,000 of EBITDA in the Q1. We completed the St. Charles hydrocracker expansion in March and the new Houston crude unit is on track start up in the Q2.
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 twenty nineteen. Now moving to financing activities. We returned $547,000,000 in cash to our stockholders in the Q1, which included $282,000,000 in dividend payments and $265,000,000 for the repurchase of 3,800,000 shares of Valero common stock. We had $1,100,000,000 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 2nd quarter operations, we expect throughput volumes to fall within the following ranges: Gulf Coast at 1,590,000 to 1,640,000 barrels per day Mid Continent at 430,000 to 450,000 barrels per day West Coast at 260,000 to 280,000 barrels per day and North Atlantic at 450,000 to 470,000 barrels per day. Refining cash operating expenses are estimated at approximately $3.75 per barrel for the 2nd quarter. Based on today's market prices, we expect costs relating to meeting our viral fuel blending obligations to be between 750,000,000 dollars $850,000,000 for 2016.
This is primarily related to RINs in the U. S. The ethanol segment is expected to produce a total of 3,800,000 gallons per day. Operating expenses should average $0.37 per gallon, which includes $0.05 per gallon for depreciation and amortization. G and A expenses for the Q2, excluding corporate depreciation, are expected to be approximately $165,000,000 and net interest expense should be about $110,000,000 Total depreciation and amortization expense is estimated at $465,000,000 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 and A to 2 questions. This will help us ensure that other callers have time to ask their questions. If you have more than 2 questions, please rejoin the queue as time permits.
Thank you. We will now begin the question and answer session. From Goldman Sachs, we have Neil Mehta. Please go ahead sir.
Good morning, guys.
Good morning, Neil.
Joe, you've made reference to seeing Joe, you made reference to seeing opportunities in the M and 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.
Yes. Neil, we're looking at the opportunities that are available to us both on the refining and midstream side. We're 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 can't provide any more specifics than that at
this point. Neil, when we look at these though, I mean, obviously, you want to try to find opportunities that 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.
And on the M and A side, 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. So it would be more asset focused and perhaps in the context of a partnering arrangement with people that were 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 rebalance the
market? Okay, Neil, this is Gary. Yes, 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. Now 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 5 year high, actually last week above the 5 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 this wood as well.
So the combination of 2 of those things, I think, will help keep domestic inventories in check. Moving forward, I think, as flat price continues to rise, we'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 will be a key driver in terms of what happens with the distillate cracks moving forward.
All right.
Thanks guys.
Thanks, Neal.
From Howard Weil, we have Blake Fernandez. Please go ahead.
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 $1,000,000,000 target. I think year to date you've done about $240,000,000 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 $1,000,000,000 target this year?
Yes, Blake. Sure. This is Mike. Before we get into that target, let me start off by talking about the capital markets. VLP does not need to execute any drop 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 level. The good news is VLP is well positioned with strong distribution company distribution coverage and does not need access to the capital markets in this price environment. Therefore, we are going to revise our drop down guidance to $500,000,000 to $750,000,000 We can execute drops in this range without going to the capital market.
We are going to continue to prepare for $1,000,000,000 in drops and we'll be ready to execute $1,000,000,000 in drops if the capital markets improve. From a Valero Energy perspective, regardless of whether or not we drop 500,000,000 dollars or $1,000,000,000 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 and A question, but the amount of I guess capital return to shareholders 547,000,000 dollars is well above your adjusted earnings.
So you're obviously well on track with that net income target. Obviously 1Q is a little bit weak, so maybe you see some improving earnings going forward. But I'm just curious if you were to identify some M and A opportunities, does that materially change your thought on this 75% net income target?
I would only explain 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 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.
Got it. Thanks guys.
From Barclays, we have Paul Cheng. Please go ahead sir.
Hey guys. Good morning. I think the first one is for Joe and maybe that's for Mike actually. For the financial strategy, I mean, if you guys are actively looking at and evaluating opportunity on the M and A, from that standpoint, Ma Yi and Joe should we be more maybe conservative on the balance sheet and maybe put some of the free cash flow back on the cash so that you will be ready when the opportunity is right?
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 Paul, I mean, you saw the cash balance that we've got. As Mike said, we're very our leverage levels are very low. And we came through a tough quarter with this balance sheet. So I think we're pretty well positioned. And I would tell you though, if there was a significant M and 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.
Okay. The second question, maybe this is for either Gary or Ling. In the Q1, your system wide margin capture rate versus your benchmark is about 62%. In the Q1 last year, it's about 70%. And your average in 2015, 2014 is about 72% 67%.
So just curious that in the Q1 this year, the 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 I'd 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 from our refineries. Actually, we would show that the volume variance was slightly positive for the quarter.
So what you're 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 RIN certainly had an impact on our capture rates. The butane differential to gasoline was much more narrow in the Q1 than what we saw last year that had an impact on our capture rates. In the North Atlantic Basin, when you look at our crude cost relative to Brent, the narrower Brent CIR impacted our crude cost, most importantly at Quebec.
Also the Western Canadian crude, the Syncrude were more expensive in the first quarter. So the volume is 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 Venetia cat down on the West Coast for a planned turnaround. And so our capture rate there were down a little bit as well.
But those are some of the real key factors.
Gary, can I just have a quick follow-up? On the Q2, your turnaround activity, is it focusing on the conversion unit or that is crew unit?
Hey, Paul, this is Lane. So we don't give 2nd quarter guidance with respect to what kind of capacity we'll have in turnaround.
All
right. We do. Thank you.
Thanks Paul.
From JPMorgan, we have Phil Gresh. Please go ahead.
Hi, good morning.
Good morning, Phil.
First question, on the Gulf Coast, your crude slate clearly shifted more towards mediums. In 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 Q1. And that was actually down year over year. So I know you talked about some 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?
Hey, Bill, this is Gary. A couple of things. The way we report our results, we have the heavy sour crude shown, but we also have a category we show resids. And some of those resids are actually replacements for heavy tower 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 Q1. In terms of the range, some of the things that we talk about, it's not just the discounts that we're looking at. There's a rate lever associated with really pushing heavy sour crudes in our system. If we want to maximize heavy sour crudes, it generally mean we're 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 and A front. With respect to refining to the extent you're looking there, could you just remind us how you think about regionally where you'd want to be adding exposure?
Yes. 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 FCC might view something. The West Coast, California in particular will be very, very difficult for us. We're 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, the 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.
Gulf Coast, we believe that we can create synergies around feedstocks and product movements there perhaps better than anywhere else. Now if we 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 if in a nutshell, the U. S. Gulf Coast would be interesting, the Mid Continent of the U.
S. The UK would be interesting and that would be our primary focus.
Okay. That's helpful. If I could just sneak one last one in on RINs. Do you have what the actual RINs cost was in the Q1 of this year relative to the Q1 of last year?
Well, we probably do. Yes, 1.61 versus 133 last year.
Okay. Perfect. Thanks.
Take care, Bill.
From Wells Fargo, we have Roger Read. Please go ahead, sir.
Yes. 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 starting to get tight, so we saw the regrade in the Mid Continent strengthened significantly. The premium regrade on the West Coast has also strengthened considerably in the last couple of weeks. So I think the industry is short octane and we'll see similar rig rates 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 to follow-up on your comment on the diesel demand side, underpinned by the agricultural seasonality. When that I assume that backs off somewhat as we roll into the middle of the summer. What 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 the Northwest Europe symbol capacity is like $0.23 margin. So it doesn't take people falling off much before some of that low complexity capacity has to cut. And as they cut, it will open up even greater opportunities for us to export our barrels moving forward.
Okay. That's great. Thank you.
From Wolfe Research, we have Paul Leinke. Please go ahead, sir.
Hi, everyone. I'm not quite sure what I was called just there. I'm not going to repeat it. It's
better than probably some of those issue big calls.
Thanks, Joe. Appreciate that. Joe, you came in as CEO very clearly talking about cash return, 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've 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 sales. Why are margins not better? And given 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. I'll go first. Paul, I'll tell you, M and A is something that we've had in our capital allocation framework for the last 2 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. But we look at our approach to trying to drive EPS growth over the next 3 to 5 years.
It's really multifaceted and includes growth investments in refining and midstream. We also look at M and A and then we look at share repurchases. And we've got a really good pipeline of refining projects that are underdeveloped or 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'll drive earnings growth through optimization. So these are critical to us also. Then when we look at the discretionary uses of cash, M and 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're 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 that growth projects and M and A as a competitive use of funds.
So with that, Gary, do you want to answer the Well,
just 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.
Thanks.
Yes.
And then do we think are we oversupplied in this market? Is that why margins are better for what should be a seemingly a much better environment?
Yes. I think so you have a couple of key factors. We keep pointing to on the distillate side, the warmer weather in the United States and Northwest Europe certainly hindered diesel demand coming through the winter. And so it created this overhang we're living with today. I think the other thing that happened is the combination of relatively strong crack spreads in December 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 utilization in December January running at high utilization 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 to what you're seeing in Venezuela in terms of if there's impact there and what sort of lost volumes there are? And I'll leave it there. Thank you.
Thanks, Paul.
Yes. So Venezuela is a very important piece of our crude supply situation. We've had a very good longstanding relationship with SenaVesa. 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're 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. And so we buy those barrels and continue to run them into our system.
From Simmons, we have Jeff Dieter. Please go ahead sir.
Good morning.
Hi
Jeff.
Joe in your initial comments you talked about seeing more medium sours on the market and we're seeing that roll through the DOE statistics historically for January 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? Or are you seeing increases of volumes coming from the Middle East coming into the market?
Yes, Jeff. Let Gary answer this. He's in the market every day.
Yes, 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're 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're competitive, we're ramping those back up in our system as well.
And you're seeing a shift towards an increase in imported crude versus domestic crude just kind of confirming U. S. Lower forty eight volumes down 670,000 barrels a day from peak and imports increasing. It seems most of that is Middle East Lamb and Canada.
Yes, I agree. What you've really seen is a substitution somewhat of domestic light sweet for Middle East medium sours. We've seen sometimes where the arb is open to import foreign light sweet, but that doesn't seem open very long. Same way there's an occasional pop where the market goes where it incentivized exports of U. S.
Crude. But again that doesn't seem to last very long. The big switch has been a domestic light sweet for Middle East medium sour.
Thanks for your comments.
Thanks, Jeff.
From Citigroup, we have Faisal Khan. Please go ahead.
Hey, good morning, guys.
Hi, Faisal.
Hi. Just two questions. First on the gasoline margins, the realized margins between the Gulf Coast, Mid Atlantic 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 margins, 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 you just
No. Between 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 stronger in the Gulf Coast and the Midcontinent.
Racks 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 crack capture.
Okay. Yes. Okay. That makes sense. And then on light heavy differentials, it looks like recently at least in the last week or 2, the differential 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?
Yes. I think the thing that happened there is really the K in the Maya formula changed. And at the same time, it changed. The Brent CIR came in and fuel strengthened a little bit. And so it's 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 just kind of have to widen going forward.
Okay. Makes sense. Thanks for the time guys.
From Tudor, Pickering, Holt, we have Chi Chiao on the line. Please go ahead.
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?
Yes. 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'm not exactly sure if this is
an M and A question specifically or more a broader U. S. Market question. But it feels like the breakup of Motiva is a potentially significant development in the domestic downstream market. How do you assess opportunities and maybe even the risks 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. Gee, 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?
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. Okay. Well, thanks Jim. You bet.
Sorry Chi.
No worries.
From Cowen and Company, we have Sam Margolin. Please go ahead.
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 have 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?
Yes. 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? And what sort of are there any commodity factors that are dynamic that affect that if it's not differentials?
Hey, Sam. This is Lance. I'll answer it. We started up in December. Our funding investment decision was about $150,000,000 of EBITDA.
View 2015 pricing, it made about $200,000,000 And if you look at the last quarter, we're estimating it contributed about $35,000,000 So it's in line with our funding decision. And I'm Gary spoke to the market on it. So that's where the project sort of sits. Okay.
Any other
exposure affecting it? Well, you have commodity risk all over the place. I think when we analyze the project, the one that we always stare at the most is NASA. The Gulf is long NASA. The crude unit backed out resist purchases.
And so we always have a keen eye on the placement of the naphtha that's created due to both of these projects, both the Corpus Christi and the Houston crude. That's where I would say the greatest commodity risk is.
Okay. Thanks. And I hate to harp on M and A because I recognize the opportunity to give color is limited. But I just wanted to touch on something you said about the Gulf Coast and ask about any regulatory elements we should know about. It sounds if the FTC is sort of pretty generous with these market share requirements or if it
would be a little tougher?
Sal, I really never heard anybody use Generous and the FTC in the same context. But what I would describe them is a very reasonable group, quite honestly, and we've had a lot of dealings with them over the years as we've done acquisitions. I believe that what they would look at not only for Valero, but for anybody is your ability to restrict trade in a particular market. And because the Gulf Coast is so long and so oversupplied and the barrels tend to move throughout the U. S.
And abroad, you're not going to run into a situation whereby having a more significant So anyway, I So anyway, I really don't think they'd have a problem with additional Gulf Coast exposure for Valero.
All right. Thanks so much.
From Credit Suisse, we have Ed Westlake. Please go ahead.
Hey, yes, good morning. A couple of small ones. Just on the comment you said seeing a lot more OPEC barrels coming this way. Is that a recent change? Or is that just a general comment around the sort of the Q1 and market conditions?
I'm just specifically thinking about the failure of Doha and whether that has sort of brought any more assertiveness into the marketing of these barrels to you given you're a big medium and heavy consumer?
No, I think we have seen a strategic shift that the Saudis have made an effort to regain the market share they lost to a lot of the domestic crude producers. And they're exporting a lot more barrels to the U. S. Gulf Coast. We certainly saw that in the Q1 and we expect it will continue.
Just then on the Gulf Coast, I mean, you've got these toppers coming up, so that's adding capacity and yet your sort of guidance was still a little bit soft. I mean, just maybe is it the start up of those CDUs within the quarter?
Throughput guidance.
Throughput guidance, yes.
So, Ed, I'll take a stab at this. I mean, John sort of alluded to it. There's now they are both of the crew units are running in the Corpus Christi crew units running in the 2nd quarter and the Houston crew units starts up in the 2nd quarter. All the rest of the volume guidance is related to other activities and then with our market outlook and the capacity that we plan to run
with. Okay. And then on the RIN side, just you've obviously got the costs and we'll do the calculation. But are you drawing down any inventories? I mean folks are getting perhaps even more concerned about RIN prices into 2017 given the mandate and where the inventory position of the refining industry will be.
Obviously, there's an election between now and then, but maybe some color as to what if everything was unchanged, what sort of inflation you might see in that RIN cost into 2017?
Yes. This is Martin Parrish. I think a lot of it there's quite a bit of stock to pull down on the RIN. So we'll see and we still don't have clear sight to what's going to be called for in 2017. So I think right now it's a little early to say.
It's been kind of remarkably stable for the last few months RIN prices. So we'll see.
And then final small one. You mentioned that you thought that waterborne octane components had been cleared up at this point. Maybe just some extra color. I mean, we do hear anecdotes of alkali cargoes floating around, which would make limited sense to me.
Yes. So we had heard the same thing that there was a lot of cargoes, especially parked off New York Harbor. Our understanding is a lot of that has actually come in over the last couple of weeks. And as I mentioned, we're actually seeing the premium rig rates start to widen, which kind of contradicts this idea that there's all this octane laying around.
Yes. And typically it widens more in May. So we'll watch that closely. Okay.
Thanks very much.
From RBC Capital Markets, we have Brad Heffern. Please go ahead.
Good morning, everyone.
Hi, Brad.
Joe, and I guess maybe for Gary too. In the opening remarks, you talked about how strong export or product export demand has continued to be. Can you dive a little more into that? Has there been any changes in terms of where that demand is coming from? And I'm sort of asking about specifically in the context of what seems to be weaker Latin American growth?
Yes, Brad, this is Gary. So in the Q1, we did 249,000 barrels a day of diesel. If you include jet and kerosene with that, we are up to 295,000 barrels a day. That was split with about 80% going to Latin America 20% to Europe. During the Q1, the arc to Europe was closed both of the first half of the first quarter.
It opened back up and has remained open. So I think you'll see a little more volume going to Europe. But we're still seeing very good Latin American demand for diesel as well moving forward.
Okay. Thanks for that. And then maybe for Mike, I'm thinking about the cadence of CapEx. The Q1 number looked pretty light relative to where I expected it to be. And certainly on a run rate basis, it's not particularly close to the 2.6% annual guidance.
Is there a reason to think that the CapEx is going to pick up throughout the year? Or are you guys running ahead?
Right now, the $2,600,000 is what we have in our forecast. On an annualized basis, obviously, we're way short of that, but we're okay on the 4 ks.
Hey, Brad. This is Lane. I'll give a little color on that. I mean, the Q1 is always a little bit of a challenge. You have to come out of the holidays and you have weather to contend with.
And so the Q1 for us at least seasonally is always light with respect to our CapEx. We'll spend some we'll spend more than the run rate than that rate 2nd and third quarter and then it flows down again on the 4th quarter. And so that's where I would say the seasonality of the CapEx spend for our company.
Okay. Thanks for that.
From Bank of America Merrill Lynch, we have Doug Leggate. Please go ahead.
Thanks. Good morning, everyone. I was wondering if I was going to get squeezed in there or not. How are you doing, Joe?
Good. Thank you.
Not too bad. Thank you. I got a couple, one macro and one specific. I guess, as a follow-up to Brad's question. Last year when margins, gasoline in particular, was extraordinary strong at the beginning of the year, European refiners were running pretty hard.
And I guess that dynamic is changing quite a bit. Given your European footprint or your Pembroke exposure, I'm just curious as to what you're seeing there. Is the distillate market starting to tighten up a little bit at least in terms of what your prior comments were about the potential for exports reopening?
Yes. So we've seen the art to export diesel to Europe open since midway through the Q1. It remains open today. And we're seeing good demand for European quality discipline in our system.
So I guess what I'm getting at, are you seeing refinery runs? Is that translating to lower production in the region? At least that's what we're seeing. I just wanted to see if it was showing up on your markets as well locally?
Yes. So I think what you're at least in my view of where they are in Northwest Europe, the refineries that are cutting are predominantly refineries that producing fuel oil because fuel oil is so discounted today. Pembroke is a pretty high conversion refinery, so we're seeing remain very high at Pembroke.
Okay. Two quick follow ups if I may. So the first one I'm afraid is M and A as well. Just very curious, Joel, that you mentioned Europe. I mean, European markets traditionally have not been anywhere near as seasonal or healthy, if you like, as the U.
S. What is how would you characterize the opportunity set that you see there? Or was it just a passing comment?
Yes. It's more of a passing comment. I would say very limited, but I don't want to tell you we would never look at a UK refinery and then we show up at some point in time and do it and you remind me of it. So but I mean, Doug, you know those markets. I mean, frankly, we've said this for years that and we got a gem in Pembroke.
And back to your first question, all the diesel that's produced at Pembroke moves inland, most of the gasoline. And so we've got a fairly unique footprint there and that we're able to supply the domestic markets and in Ireland in a very efficient way. So we really like that. If we could find a similar type of asset in a market that was similar, okay? And when I say that, I really am thinking primarily of the UK.
Well, I think we consider it. Now. Are we having active conversations on anything like that? No. But would we want to move into France, Spain, Italy or the Med?
The answer would be no. So it's more of a passing comment. But we tell you guys we are looking at everything that's out there and we do that because we're always looking for opportunities to continue to grow the EPS. But again, we're very pleased with the portfolio that we have and we can create significant income with it. And So we don't feel desperate to do anything in that M and A market.
Certainly, again, it's in competition for all the other good uses of cash that we have.
Thanks. But unrelated, I guess my follow-up is for Mike. Mike, the tax or the cash received for the drop down relative to the price agreed? Should we how should we think about the after tax proceeds from versus your slightly lower dropdown target?
I would think I mean, we're going to continue to look at each of the drops as we come up on them as far as how we want the financing to mitigate taxes. I think it would probably be on this next drop similar cash tax or after tax cash as
we're going to. But Doug, looking longer term and this is just the reality of it, a lot of the logistics assets that would be dropped are going to they got 0 tax basis. And so, I think for a long time when everybody was looking at 10x multiples, 11x multiples on these drop transactions with all that cash flowing back in, we were really overstating the actual cash that would be coming back into the sponsor. And so the reality of it is, we're not changing the portfolio of assets that we have to drop. We're really looking at the drop structure and doing it as efficiently as we can.
Again, Mike mentioned earlier that we think it's the capital markets are certainly there, but it's a little bit expensive to go to the public markets today. We don't have a gun to our head to do something because we've got the distribution covered for 2 years with the cash flow stream that we have today. And all the things that he mentioned earlier, I think we're in a very, very strong position here and we can take our time and time to market and be patient in doing this. And whether we do $500,000,000 or $750,000,000 now and then we'll start talking about next year what we're going to do. We're going to continue to grow the LP.
We're going to continue to drop. I think we're just waiting to see if things don't improve a bit. And certainly, higher crude prices should take some of this pressure off if we see the crude markets move up and we should be in a good place going forward.
I appreciate all your comments, Joe, and your patience at all our M and A questions this morning. Thanks.
No problem.
We have no further questions at this time. I will now turn the call over to Mr. Locke for closing remarks.
Okay. Thank you, Bianca. We appreciate you all for joining us today. Please contact me or Karen Ngo, if you have additional questions after the call. Thank you.
Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.