Welcome to the Valero Energy Corporation Reports 2015 First Quarter Earnings Results Conference Call. My name is Christine, and I will be your operator for today's call. 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 John Locke. You may begin.
Thank you, Christine. Good morning, and welcome to Valero Energy Corporation's Q1 2015 earnings conference call. With me today are Joe Gorder, our Chairman, President and Chief Executive Officer Mike Cyszkowski, our Executive Vice President and CFO Lane Briggs, 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'd like to direct your attention to the forward looking statement disclaimer contained in the press release. In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward looking statements intended to be covered by the Safe Harbor provisions under federal securities laws. There are many factors that could cause actual results to differ from our expectations, including those we've described in our filings with the SEC. Now, I will turn the call over to Joe for a few opening remarks.
Well, thanks, John, and good morning, everyone. As John will cover in more detail shortly, we reported record first quarter earnings per share. With great performance in a favorable margin environment, we demonstrated Valero's earnings power in a heavy maintenance period. The one thing that I'd like to reaffirm with you before we proceed is that our team remains focused on executing our strategies to improve our valuation through operations excellence, optimizing our business through disciplined capital allocation and unlocking asset value. With that, John, I'll hand it back over to you.
Okay, great. Thank you, Joe. What we'd like to do now is highlight a few accomplishments this quarter that align with our key strategies and then we'll cover the quarterly results. As noted in the release, our focus on operations excellence yielded solid results while we successfully managed a heavy turnaround season in the Q1. For the remainder of 2015, we have a lighter schedule of planned maintenance compared to the Q1.
We remain committed to deliver a payout ratio of earnings to our stockholders that exceeds 20 fourteen's ratio of 50%. So far, we are on track to meet this goal with a 55% payout ratio on Q1 2015 earnings. Regarding capital investments, we continue to optimize and improve our business while maintaining rigor in our capital budget. For 2015, we maintain our guidance for capital spending including turnarounds in catalyst at approximately $2,650,000,000 which excludes $150,000,000 for a St. Charles methanol project.
The proposed St. Charles methanol project and Houston alkylation units remain under evaluation and are progressing through our gated project management process. We expect to make final investment decisions on these projects later in the second quarter. With respect to unlocking asset value and accelerating the growth of Valero Energy Partners LP, which is our sponsored master limited partnership, we are clearly delivering growth and have a backlog of assets to drop down. Given the closing of the $671,000,000 drop down of our Houston and St.
Charles terminal services business in March, we're on track to complete our goal of $1,000,000,000 of dropdown transactions in 2015. Now moving on to the quarterly results, we reported net income from continuing operations of $964,000,000 or $1.87 per share for the Q1 of 2015. Earnings per share was 21% higher than Q1 2014 earnings per share of 1.54 dollars The refining segment reported Q1 2015 operating income of $1,600,000,000 versus $1,300,000,000 in the Q1 of 2014. We cover the key drivers of this increase in the release, but I'd like to highlight that while discounts were more narrow this quarter for most sweet and sour crude oils relative to Brent crude oil on a dollar per barrel basis, on a percentage discount basis, these crudes were priced more favorably in 2015. For example, in the Q1 of 2015, bio priced on average at a 20% discount to Brent versus a 17% discount in the first quarter of 2014.
Our significant crude slate flexibility allows us to adjust feedstocks and optimize margins based on the discount environment. Refined throughput volumes averaged 2,700,000 barrels per day in the Q1 of 2015, which is an increase of 9,000 barrels per day versus the Q1 of 2014. Volumes and utilization rates in both periods were impacted by heavy planned maintenance. Refining cash operating expenses were $3.95 per barrel in the Q1 of 2015 or $0.04 per barrel lower than the Q1 of 2014. That's our 12th consecutive quarter with cash operating expense below $4 per barrel.
Our focus on safe and reliable operations combined with advantaged domestic energy costs provides us a global manufacturing competitive advantage. The ethanol segment generated $12,000,000 of operating income in the Q1 of 2015 versus $243,000,000 in the Q1 of 2014. While ethanol margins compressed in the Q1 of 2015, they have rebounded some here in April. Longer term, we believe ethanol remains a key component of the transportation fuel mix. General and administrative expenses excluding corporate depreciation were $147,000,000 in the Q1 of 20 15, which is $13,000,000 lower than the Q1 of 2014, primarily due to changes in legal reserves.
Also in the Q1 of 2015, net interest expense was $101,000,000 and total depreciation and amortization expense was $441,000,000 The effective tax rate was 31.7 percent. With respect to our balance sheet at quarter end, total debt was $7,400,000,000 and cash and temporary cash investments were $4,900,000,000 of which $28,000,000 was held by VLP. Valero's debt to capitalization ratio, net of $2,000,000,000 in cash was 20.3%. Valero had over $10,000,000,000 of available liquidity including cash. Cash flows in the Q1 included $698,000,000 of capital spending, of which $240,000,000 was for turnarounds in catalyst.
We also issued $1,450,000,000 of debt, which included $1,250,000,000 of bonds in March for general corporate purposes, including the refinancing of current maturities and $200,000,000 issued by VLP to partially fund their March acquisition. We returned $531,000,000 in cash to our stockholders in the Q1, which included $206,000,000 in dividend payments $325,000,000 for the purchase of 5,400,000 shares of Valero common stock. Year to date, we've purchased 7,100,000 shares for $429,000,000 Now for modeling our 2nd quarter operations, we expect throughput volumes to fall within the following ranges. Gulf Coast at 1,550,000 to 1,600,000 barrels per day Mid Continent at 430,000 barrels per day to 450,000 barrels per day West Coast at 280,000 barrels per day and North Atlantic at 460,000 to 480,000 barrels per day. We expect refining cash operating expenses in the 2nd quarter to be around $3.90 per barrel.
Our ethanol segment is expected to produce a total of 3,700,000 gallons per day in the second quarter. Operating expenses should average 0 point $3.8 per gallon, which includes $0.04 per gallon for non cash costs such as depreciation and amortization. We expect G and A expense, excluding corporate depreciation for the 2nd quarter to be around $175,000,000 and net interest expense should be about $105,000,000 Total depreciation and amortization expense should be approximately $445,000,000 and our effective rate is expected to be around 33%. Christine, we've concluded our opening remarks. In a moment, we will open the call to questions.
During the segment, we ask that our callers limit each turn to only 2 questions. Callers may rejoin the queue with additional questions as time
And our first question is from Evan Kaleo of Morgan Stanley. Please go ahead.
Hey, good morning guys. Hi, Evan. Evan. My first question relates to cash distributions and unlocking value. Cash returns averaging 7% yield year to date, yet you also built $1,000,000,000 in cash in the quarter.
You're now through the low end of your leverage guidance of 20% to 30%. I know you mentioned a target payout ratio. How do you determine the optimal cash position as it continues to build and determine when to increase distributions from current rates?
Okay. Evan, this is Mike. I do not have a precise number I can give you, but what I can give you is that in our debt to cap ratio guidance, we reduced our debt by 2,000,000,000 dollars From there, we would like to keep some cushion in our cash balance given the volatility of our business. And then we look at the future capital and working capital requirements and then the payout of greater than 50% that we've already committed to you guys. But I would like to point out that excluding the debt issue that we had in the Q1, we actually had a decrease in cash of about $300,000,000
Right. I guess there's upside scope I guess from a $5,000,000,000 cash position to distribution I guess would be my question.
Yes. I mean, I'd just add further, we have committed to the greater than 50% payout. As we move through the year and if earnings and cash flow continue positively like they are, we will assess this and consider increasing that payout number.
Great. That makes
Go ahead.
Yes. No, no, Asda. That makes sense. And then my second question is more on the product demand side. I mean global crack spreads have been higher than many expected year to date.
Global demand estimates continue to rise in response to low commodity prices. So, is there any comments kind of what you're seeing through the system on demand trends and what you might expect for summer driving season we may not have seen in quite some time? Thanks.
Yes, Evan. This is Gary Simmons. I think definitely we've seen a good crack spread environment. I would say early in the year it was probably driven from we had some heavy turnaround maintenance, refinery turnaround maintenance and that type of activity. Also I think the USW union negotiation came into play and in support of the crack spread.
That's kind of behind us now. And I think really the market is being driven up by demand. We've seen some pretty encouraging numbers thus far. We expect that that trend will continue, but I think it's a little too early to tell what the magnitude of the demand response will be to the flat prices.
Fair enough guys. Thank you.
Thank you. Our next question is from Neil Mehta of Goldman Sachs. Please go ahead.
Good morning.
Good morning, Neil.
So the first question is just thoughts on spreads, in particular Brent LLS, which while Brent WTI is healthy right now, LLS Brent looks a little bit tighter. Just any thoughts there and potential bottlenecks between Houston and St. James?
Yes. This is Gary again. I think the LLS of Brent's bread has been a little bit more narrow than what we would expect. I think ultimately the Gulf Coast sweet market has to price set at a level that allows the East Coast refiners to be
able to
receive domestic light sweet crude by Jones Act ship. So that kind of tells you over time that LLS should be around $2 discount to Brent as long as the standard transportation differentials in the Gulf hole. I think some of what you're seeing today is the Houston market is bottlenecks with logistics getting to St. James. And so we're seeing Houston trade at a much wider discount to St.
James and where it had been. And so that's going ahead and allowing these Jones Act economics to hold, but they're right kind of breakeven and I would expect LLS to come off some.
That's very helpful. And then on RINs, just any thoughts as we get into the Q2 here on where RIN pricings are and how we should assess the impact on a go forward basis?
Yes. This is Martin Parrish.
We think the RINs are just where they are just waiting on the EPA announcement in June and just the uncertainty even though the EPA said they'll set it at the levels, everybody's just waiting to see. So I think after June, we'll see what happens then.
All right. Very good. Thank you very much guys and talk soon. Thanks, Neil.
Thank you. Our next question is from Edward Westlake of Credit Suisse. Please go ahead.
Yes. Good morning. And I guess the first question still on the macro side. We are seeing decent tanker fixtures still from the Gulf. Obviously, the Saudis are still pumping.
I mean, you've got Mexico, Venezuela. How would you characterize at the moment the supply availability of waterborne mediums and sours into the system?
Well, it's been very good. Like you said, we actually in the Q1 ran more South American crews than what we've historically run. The Saudi is still committed to the U. S. Market.
So I don't know that we'll go back to levels of imports that we saw 3 years ago, but I definitely think the medium tower volumes in the U. S. Gulf will be up from what we saw last year. We're seeing a lot more heavy Canadian with the startup of Flanagan. So overall, the Gulf Coast seems well supplied with all grades of crude.
Right. Okay. And then on the VLP, I mean, obviously, a great drop in March, dollars 1,000,000,000 clearly very easy to achieve. Any view of going faster or you just still think that $1,000,000,000 which is obviously still a healthy pace is the right pace going forward?
No, Ed, this is Joe. And we're very comfortable with the $1,000,000,000 pace this year. And so that would imply that we're going to execute another drop sometime in the second half of the year, probably later in the second half of the year. But what our real focus is, is on the distribution increase and we're committed growing it at that 25% plus this year and for the next couple of years. So we're very comfortable with the pace we've got right now.
Okay. Thanks very much, Jeff.
Thank you. Our next question is from Paul Cheng of Barclays. Please go ahead.
Hey, guys. Good morning.
Hi, good morning.
Joe, couple of years ago, I think the company when looking at kind of foreign has always said it's not really a call for the long haul and you're looking for if someone gives you a okay price that you will set. Is there any change in the view from management about how you look at California from a long term standpoint? And if it is now part of your long term portfolio, is there any initiative for you that you are taking to improve the result relative to your peer that you seems to be lacking in there?
Yes. Well, Paul, we've said this before that on the West Coast, we have very good assets and we have very good management teams operating those assets. And frankly, we view our portfolio on the West Coast is an option when the margins are strong on the West Coast. And certainly, we're experiencing that today and we had a very good Q1. If you don't mind, Paul, what I'll do is let Lane just speak to our capital approach to the West Coast.
Hey, Paul, it's Lane. We just continue to be very disciplined in our capital. We look for small opportunistic things to try to improve margin capture. But we in terms of like any major capital program, we in the event that we put in much money, we have better opportunities in our Gulf Coast and Mid Continent systems. I would say though, one of the things you'll see in terms of our margin capture because Venetia makes so much gasoline, you'll see our capture versus an index probably got quite a bit better because the Q1 is really a story of on the West Coast of the West Coast gasoline crack.
The second question, Mike, going back into the cash position, is there a level you can share what is the comfort level of the cash that you want to hold?
Well, I don't really have guidance for you on like a minimum cash balance, but you can start with the $2,000,000,000 that we use in our debt to cap calculation. And then we would like to keep some cushion in
that given the volatility of our business.
I see. Okay. Thanks.
Our next Our next question is from Chi Chiao of Tudor, Pickering, Holt. Please go ahead.
Hi, thanks. Good morning.
Good morning, Chi.
Steve. Yes, a couple of questions
on the North Atlantic market. You've realized strong double digit margins in that region for 3 quarters running now. In PADD 1 and European crack has been pretty robust over this period. What do you think the sustainability of those tighter product markets in that Atlantic Basin region?
Well, I think there's a number of reasons for what we've seen in the Q1. I think some of it is sustainable. Obviously, we had strong turnaround maintenance in that area as well. Colder weather helped always helps with demand. But I think you've seen good demand response to the lower flat price, which is certainly constructive moving forward.
I think the other thing that's happened is that the U. S. Dollar strength versus the euro, it helps us with our operating costs at Pembroke as well. So I think there's a lot of encouraging signs on the Atlantic basin.
And then, Chi, this is Joe. The one thing I would add to Gary's points, which you're all correct is that the Pembroke asset is a very good asset. And what we acquired when we bought that refinery was an integrated system. And so when you think about merchant refining in Europe, you really shouldn't think about Pembroke in that regard. The distillate barrels that we produce are all moved inland and certainly a significant volume of the gasoline moves inland.
So it's a little bit different setup than some might be experiencing.
Okay. Are you concerned about distillate crack spread weakness going forward with all the global capacity that's come online over the last year or so?
I would say we're not that concerned about the distillate cracks in our system. I think there's a couple of things. The U. S. Market has been so strong.
We still see good export demand. However, we've been somewhat priced out of the market because our market has been so strong. So I think we think moving forward, we'll see a combination of better demand domestically and we'll see that our export volumes will pick up again as the U. S. Market falls off a little bit.
What were your export volumes for the quarter on gasoline diesel?
Yes. Our gasoline was down a little bit at 94,000 barrels a day. The reason for that was really just because of the strength in the U. S. Market.
Again, that's an optimization for us and we would kind of say the way we optimize that is more demand pull rather than supply push and the export markets really weren't strong enough on gasoline to pull the barrels away from the Gulf. Our distillate volumes were fairly flat about 205,000 barrels a day ULSD. If you look at ULSD plus kerosene, we were up to 55,000 barrels a day. So fairly consistent there. The change we saw is that for a lot of the Q1, the yard to Europe wasn't open.
So we're usually 60-forty between Latin America and Europe, up 70% of our volume actually went to Latin America and we didn't see that the flow to Europe that we've traditionally seen.
Okay. Great. And one more question on the North Atlantic. Can you talk about how the Line 9B reversal is going to impact your crude sourcing options at Quebec going forward?
Yes. So I'll give you a little update on that. We're still waiting for regulatory approval on Line 9 from the National Energy Board of Canada. We don't know a timeline on that. We feel like there's a good chance the NEB could approve that by mid May.
With a mid May approval, that would mean we really won't see any impact from Line 9 in the second quarter, but we're optimistic we'll start to receive oil in the Q3. It gives us a lot more flexibility in Quebec to be able to have access to those Western Canadian and Bakken grades and not just rely on rail and U. S. Gulf Coast source barrels.
Okay, great. Thanks. Appreciate it.
Thank you. Our next question is from Ryan Todd of Deutsche Bank. Please go ahead.
Great. Thanks. Good morning, gentlemen. Maybe if I could follow-up first with a follow-up question on VLP. Is there I know earlier we've talked about the potential for an evaluation of a wholesale fuel distribution EBITDA as a potential drop to VLP.
Can you talk a little bit about whether that's still under evaluation and any rough guide as to what that figure might look like?
Yes, Brian, this is Mike again. We're still evaluating at the appropriate structure that we would consider to drop to the MLP. So I do not have a number that I can give to you on this call.
Okay, great. I appreciate it. And then maybe just a general I mean, we see the margins on the screen, which looks supportive. But can you give us maybe just an update on what you've seen a month in the Q2 in terms of the general operating environment?
Yes.
I think we're the cracks continue to be strong. We continue to see good discounts on the crude. The big change probably has been in the crude Some of the discounts have come in, so we're running a lot more light sweet crude in our system today than what we did in the Q1. But again, I think we're seeing good demand both in the export markets and domestic demand. And so we feel very encouraged about the profitability moving forward.
Great. Thanks. I appreciate it.
Thanks, Ryan.
Thank you. Our next question is from Jeff Dieter of Simmons and Company. Please go ahead.
Good morning.
Good morning, Jeff.
I had a strategic question. I think historically Valero has been a little bit more of a refining pure play relative to some of the peer strategies that have been more integrated. You guys have sold off NuStar interest and Corner Store. And I was just hoping for an update on how Valero strategy is evolving going forward. What do you think about integration through the value chain?
Do you expect a materially larger midstream business?
Jeff, that's a good question. I mean, very clearly, we are a fuels manufacturing company and certainly that involves refining. It also involves our renewable fuels business. So that is it is such a significant part of the portfolio today to see any significant shift from that. It's just really it's not in the cards.
Now to answer your question on the midstream business, I do think we're going to see our midstream business expand significantly over the next several years. And as we've said, our strategy in midstream is really to develop projects and acquire assets that are supportive of Valero's core businesses. And I think if you look at the investments that we've made today, it would certainly support that. That being said, the refining portfolio is large enough and the renewables portfolio is large enough that it provides plenty of opportunity for growth within that midstream business. I don't think you should expect us though to be looking upstream from where we are today in any material way or significantly downstream from where we are today.
Although opportunities present themselves and you'd look at it, but certainly that's not part of our plan today.
Thank you. And secondly, looking through your refinery throughput guidance for the 2nd quarter, it looked relatively conservative. And my question is what are the LPs suggesting you should max run? Under what conditions would you
run more aggressively or perhaps less aggressively? Can change is we see a pretty good rate lever on some of our plants depending on if we're maximizing heavy sour versus light sweet, especially like at Fort Arthur, Jeff. It can change our throughput significantly when we start maximizing light sweet over heavy sour. I would say that was the only thing I could see.
Thanks for your comments.
Thanks, Jeff.
Thank you. Our next question is from Brad Heffern of RBC Capital Markets. Please go ahead.
Good morning, everyone.
Good morning. Good morning, Brett. So just following up on a
couple previous answers looking for a little more color. I think in the Q1 you all had talked about just the sheer number of waterborne crudes that were trying to find their way into the Valero system. Is the fact that you're running less waterborne now and more domestic suggestive that maybe the global crude environment isn't as oversupplied as it was a few months ago?
I think there's been a couple of events that are kind of driving the crude differentials. First, the medium sour market in the Gulf due to the market structure a lot of people were pulling their barrels off the market trying to hold them and collect the roll. So it kind of tightened up the medium sours. Now the storage is getting full. You also have some turnaround maintenance going on to the deepwater platforms in the Gulf.
That's kind of also tightening the market a little bit. Then the heavy sour side on the Maya, of course, you had the fire on the platform in Mexico, which is also disrupted production there. So my view is that these crudes have to compete with the light sweet and we'll see the differentials come back as we move forward in the Q2.
Okay. That's great color. And then maybe for Joe, a lot of E and Ps have seemed pretty confident of late that the crude export ban is going to be lifted in the near term, maybe in 2015. Do you have any updated thoughts or anything that you've been hearing about that?
Well, I think we're probably hearing the same thing that you're hearing and we know that there's activity in the House and the Senate to bring the issue forward. But certainly the administration doesn't seem at all receptive to this. And just to be clear on our position, I mean, we believe in free and open markets. And as we've talked about many times, there's currently legislation and regulation in place that hinders the petroleum markets from being free and open. And these would include things like the crude export ban, the RFS, the Jones Act and others.
So we believe that looking at a specific issue relative to the overall issue is not the right way to deal with this topic and you need to deal with all of the issues. The one thing about Valero is that we've continued to invest and we're running significant quantities of domestic crude today and we continue to invest to enable us to run more of this crude. So we're doing what we can to process it as are many other refiners. And then really the last point on this is when you look at the general need for crude
exports, the U. S. Remains a net importer
of crude oil with about 7,000,000 exports, the U. S. Remains a net importer of crude oil with about 7,000,000 barrels per day coming in. And we certainly export much lower volumes in that. The question becomes, do you really need the exports?
And I think that's the question on everybody's mind.
Okay, great. That's it for me. Thanks.
Thank you. Our next question is from Doug Leggate of Bank of America Merrill Lynch. Please go ahead.
Thanks. Good morning, everyone. Good morning, Joe.
Good morning, Doug.
Guys, if I could follow-up on the last question on exports, Joe. From what we are seeing, it looks like light sweet imports from the Middle East in particular. I'm looking at Kuwait in particular just as one example. They actually seem to have been increasing. I'm just curious as to what is your strategy around accessing light sweet or just generally crudes outside of the U.
S? And how do you think that impacts the crude export today? Because I think that's one of kind of the key issues is the net balance as opposed to the just the issue in itself?
Sure. Doug, let Gary if you don't mind, we'll let Gary speak to the imports.
Yes. So Doug, I would tell you that primarily what we see from Kuwait is really not light sweet, it's more medium sour barrels. And I would tell you that we have had many discussions with them and they seem interested on maintaining or actually growing market share in the U. S. On that grade of crude.
On the light sweet, a lot of what we see happen is with all this volatility and the Brent TI arc moving in and out, when the arc comes in very narrow, then we start to see incentives to import light sweet. And in the Q1, we definitely saw that. And as I've discussed in the past, the first place we generally see it is in Quebec. And there were certainly times during the Q1 where the Brent TI arc got narrow enough that it incentivized to step back in and buy Brent related West African type crews.
Okay. I appreciate the answer, fellas. Obviously, we're watching this one closely. But my follow-up, Joe, is really on the return of cash to shareholders. And it's obviously the share price, I guess, like all the refiners have done well from a lot of the strength in the Q1.
And I think you guys said yourself in your prepared remarks that the business is obviously volatile. When you think about the last time your predecessor had a very substantial share buyback program and where the share price is now and the fact that you're again embarking on a very substantial share buyback program, How do you think about balancing the timing and I guess the balance between dividends and other measures of returning cash as opposed to is that right buying back stock at current levels? And I'll leave it there. Thanks.
All right, Doug. I'll speak to it briefly and then see if Mike has anything to add. But the timing of the market is something that is almost impossible to do, right. I think the particular transaction you're referring to might have been the accelerated share repurchase that we executed some years ago and we don't have plans to do that. Now I don't want to get into being specific about our strategies around share repurchases other than that we've committed to this greater than 50% payout ratio, which we said would be a blend of repurchases and a dividend.
We had a significant increase in the dividend at the end of January. And we continue to look at cash and how we're going to employ it with a capital budget that is very manageable in the current context. So I think if you said, what are your plans? I think we our plans are to continue to buy back shares certainly to meet that greater than 50% target. Mike, is there anything that you'd add?
No, I think that's what I'll send us. Okay. Thanks a lot, everyone.
All right, Doug.
Thank you. Our next question is from Phil Gresh of JPMorgan. Please go ahead.
Hi, good morning.
Good morning, Phil. First question
is on the midstream M and A potential. Appreciate the color you've given already. Just a follow-up. Would you rather have more EBITDA dropped at this point before you consider midstream M and A at VLP? Or are you comfortable with the amount of EBITDA there already?
And to the extent that you would consider midstream M and A, would you likely want to do it at the Valero level given the amount of cash that you have available right now?
Phil, this is Mike. I think at this point, in VLP's stage that they probably would prefer to do the drops and get a little bit more sizable before they start taking on 3rd party acquisitions. As you know, the drops come with minimum volume commitments that you may not always get in a 3rd party deal depending on the deal. So given their size, I would say the drops are the more likely path
that they will go. Got it. Okay. And just one final question on the export ban. I guess the question is really like if you think about the ban being lifted, if it were to happen, would this materially change how you manage your business whether it's growth projects for refining or logistics, potential M and A aspirations?
Just generally, how do you think about the way you're managing your business today versus in that kind of a world and how you would think about crude differentials?
Well, just I'll fly over this and then we'll let Gary speak to it if he'd like to also. But our strategy is to optimize our operations. And that is a broad statement, I know, but it goes to our crude and feedstock slates, it goes to our disposition of our products and it goes to our capital investments. And so I think what you would see, certainly there's nothing that we're doing today that I would say we need to change in a crude export environment. But we'll have to see what the market does and how the market would respond to that.
I mean, I guess you're pushing you'd be pushing additional crude barrels into a market that seems to be well supplied today. And so the question in our minds is how is the market going to react to that. And honestly, I don't think we're smart enough to tell you what that would be. Gary,
you No, I agree. I think overall, even if the export bans lifted, we would continue to have a location advantage running the domestic crudes. We continue to have a significant operating cost advantage with the cheap natural gas. And then we're very happy with our portfolio of refining assets that are very complex, very efficient refineries.
And would it have a material change on your view of the crude differentials?
No, I don't think so. I think overall the crudes have to continue to compete for space in the refineries and so we're going be the beneficiary of that.
Okay, great. Thanks a lot.
Thank you. Our next question is from Sam Margolin of Cowen. Please go ahead.
Good morning. I wanted to ask about the notes offering from earlier within the context of the gated process that you guys have talked about a lot. How was the pricing relative to your expectations? Did it change anything as far as return hurdles or maybe opening up some more capital intensive optimization plans or even on the M and A side? In your view, was it pretty much in line with what you were expecting?
Yes. The interest rates were low and pretty much where we expected for that offering to come in at. I mean, the funds will be used for general corporate purposes, including the refinancing of our current maturities. And I do not think that the issuance of that debt will increase any gated capital project or anything like that. It was just an opportunity to issue debt at a low rate.
Okay. Thanks a lot. And I don't think I heard you guys mention methanol in the prepared remarks. So I'm assuming this question isn't going to get very far, but I'll ask anyway. Is there anything incremental there to update us with?
Or is it still just in the evaluative stages and we'll wait on the final decision?
Hey, Sam, this is Lane. So I'll just give a bit of update. It's kind of where it's been. We'll anticipate our sort of our funding decision here later in the Q2. I would just add that any real considerate this project go forward and our strategy, we obviously more than likely have a partner.
I would add that in terms of maybe what some of our public comments are in. But we're still on track to review this project here in the late Q2.
All right. Perfect. Thanks.
Thank you. Our next question is from Roger Read of Wells Fargo. Please go ahead. Good morning.
Good morning, Roger. Good morning, Roger.
I just wanted to follow-up, I guess, either in terms of the Brent LLS relationship or are there other sort of last mile pipeline issues in the Gulf Coast to think about you hitting a higher throughput number in the Q2 here, potentially hitting a higher number I'll say?
I don't really know unless Lane comments. The only thing I can think of is we are definitely signaling higher runs of light sweet crude, which can have a rate lever in some of our heavy tower refiners, but I don't know of anything else that would signal significantly different throughput.
No, that's what I would concur. Right now, our economic signals are maximum throughput. And Gary mentioned earlier answer, there obviously a rate thing that occurred depending on whether we're running light, medium or heavy power crews that obviously has an impact on our overall throughput.
Okay. Thanks. And then back to the OpEx, the initial comments mentioning under $4 for several quarters in a row here and then the FX strength that helped out Pembroke. But could you kind of walk us through is there anything that you've operationally challenged and succeeded on? Or are we looking at it's cheap natural gas and it's an FX item flowing through that's helped you lower OpEx?
I mean I know throughputs being high also helps on a per barrel basis, but if there's anything else you could offer that'd be great.
Again, it's Lane. I want to say we are always vigilant on operating cost. It is our culture. We work every day, every month, every hour to make sure that we are vigilant in maintaining our mix and our structural operating costs. We did benefit from lower natural gas prices in the Q1 versus 4th and last year.
Throughputs were a little bit lower and so partially offset by that, but we will absolutely maintain our focus on having low operating costs.
But nothing specific we should think about just it's a general pressure on the system?
No, nothing. Okay. Thank you.
Thank you. Our next question is from Blake Fernandez of Howard Weil. Please go ahead.
Hey, guys. Good morning. Two questions for you, if I could. One, you mentioned in the press release the benefit of secondary product pricing. And I assume that's just kind of some spillover from the collapse in crude prices.
But now that we're starting to see kind of a reversal in the crude markets and moving higher, Are you starting to see a bit of a reversal in that secondary product pricing here into 2Q?
Well, I would definitely say that when you get out into the products other than gasoline and distillate sulfur pet coke LPGs, a lower flat price environment tends to have these products trade closer to crude value and it helps us on track realization. And as crude moved up then the reverse would also be true.
Okay. Gary secondly, just to follow on from your previous export commentary, the shift that we've seen basically away from Europe. Can you just talk a little bit about the arbitrage that's needed there? In other words to drive the economics to incentivize a transport over to Europe? Is it basically like $1 $2 a barrel that's needed?
And then maybe as a follow on to that, do you have any sense I know you mentioned indigenous demand growth here, but do you have any sense that maybe aside from European utilization rates moving up there or any of the new global facilities beginning to penetrate that market? Do you have any color there? I'd appreciate it. Thanks.
Yes. I guess I'll start with that. I think we still feel like our traditional export markets are there for us as long as it's economic for us to supply those markets. And we have seen a move back to where the art to Europe is open. It basically is just looking at the differences in the two markets freight and then we also take into effect the RIN.
And so the higher RIN prices that we're seeing today help to incentivize exports of distillate to Europe. So freight generally a little over $2 to get a barrel to Europe and then the RINs in this $0.71 range and that kind of gives you the differential that's needed to support exports.
Okay. Thanks.
Thank you. And our next question is Paul Cheng from Barclays. Please go ahead.
Hey, guys. Two quick follow ups. One, Joe, can you give us or maybe this is for Ling. The Matikru expansion, are we done yet? Or that what is the schedule
now? No, we'll finish that. This is Lane, by the way, Paul. We'll finish it up in the Q3 of this year.
All right. And that maybe that this is for Gary. Gary, are you guys currently given the current events, are you exporting crude oil from the Gulf Coast to Quebec? And then also after the line B reversal complete, do you still need to export from the Gulf Coast or that you will get sufficient Western Canadian crew into Quebec?
Yes, Paul. So we are exporting from the Gulf to Quebec in the Q1 a little over 70% of our diet was crude sourced from Canada and the U. S. Gulf. And post Line 9, we would still anticipate that we would see some flow of oil from the U.
S. Gulf Coast to Canada over the water.
Can I ask a final question?
Just for you, Paul.
Thank you. In the last two years, when we look at from the first to the second quarter, your margin capture rate seems like it's on average dropped by about 10%. In the first quarter this year that you have a far more heavy downtime especially in the Gulf Coast and in the Q2 your full year is going to be much higher. So should we still assume that your margin capture rate will be the pattern will be similar to the last two years that dropped roughly about 10% from the Q1 level or that we should view it somewhat differently?
Paul, so generally what you see happen as you transition from the 1st to second quarter, you go through our VP transition on the gasoline and with a decreased butane blending, which drives down our frac attainment. You're correct that as we have lighter turnaround maintenance activities in the Gulf, it should offset some of that where we come out. I don't know that I've looked at it.
Okay. Thank you.
Thanks, Paul. Thanks, Paul.
Thank you. We have no further questions. I will now turn the call back over to John Locke.
Okay, great. Thanks, Christine. We appreciate those who called in today and everyone listening. If you have additional questions, please contact me or Karen in the the IR department. Thank you.
Thank you. And thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now