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 first quarter 2015 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'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, 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 first quarter. For the remainder of 2015, we have a lighter schedule of planned maintenance compared to the first quarter. We remain committed to deliver a payout ratio of earnings to our stockholders that exceeds 2014's ratio of 50%. We are on track to meet this goal with a 55% payout ratio on first quarter 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 $2.65 billion, which excludes $150 million 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 MLP, we are clearly delivering growth and have a backlog of assets to drop-down. Given the closing of the $671 million drop-down of our Houston and St. Charles terminal services business in March, we're on track to complete our goal of $1 billion of drop-down transactions in 2015. Moving on to the quarterly results.
We reported net income from continuing operations of $964 million, or $1.87 per share for the first quarter of 2015. Earnings per share was 21% higher than first quarter 2014 earnings per share of $1.54. The refining segment reported first quarter 2015 operating income of $1.6 billion versus $1.3 billion in the first quarter of 2014. We cover the key drivers of this increase in the release, 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 first quarter of 2015, Maya 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. Refining throughput volumes averaged 2.7 million barrels per day in the first quarter of 2015, which is an increase of 9,000 barrels per day versus the first quarter 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 first quarter of 2015, or $0.04 per barrel lower than the first quarter 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 million of operating income in the first quarter of 2015 versus $243 million in the first quarter of 2014.
While ethanol margins compressed in the first quarter 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 million in the first quarter of 2015, which is $13 million lower than the first quarter of 2014, primarily due to changes in legal reserves. Also in the first quarter of 2015, net interest expense was $101 million, and total depreciation and amortization expense was $441 million. The effective tax rate was 31.7%. With respect to our balance sheet at quarter end, total debt was $7.4 billion, and cash and temporary cash investments were $4.9 billion, of which $28 million was held by VLP. Valero's debt-to-capitalization ratio, net of $2 billion in cash, was 20.3%. Valero had over $10 billion of available liquidity, including cash.
Cash flows in the first quarter included $698 million of capital spending, of which $240 million was for turnarounds in catalysts. We also issued $1.45 billion of debt, which included $1.25 billion of bonds in March for general corporate purposes, including the refinancing of current maturities and $200 million issued by VLP to partially fund their March acquisition. We returned $531 million in cash to our stockholders in the first quarter, which included $206 million in dividend payments and $325 million for the purchase of 5.4 million shares of Valero common stock. Year to date, we've purchased 7.1 million shares for $429 million.
For modeling our second quarter operations, we expect throughput volumes to fall within the following ranges: Gulf Coast at 1.55 million-1.6 million barrels per day, Mid-Continent at 430,000-450,000 barrels per day, West Coast at 280,000-300,000 barrels per day, and North Atlantic at 460,000-480,000 barrels per day. We expect refining cash operating expenses in the second quarter to be around $3.90 per barrel. Our ethanol segment is expected to produce a total of 3.7 million gallons per day in the second quarter. Operating expenses should average $0.38 per gallon, which includes $0.04 per gallon for non-cash costs such as depreciation and amortization. We expect G&A expense, excluding corporate depreciation, for the second quarter to be around $175 million, and net interest expense should be about $105 million.
Total depreciation and amortization expense should be approximately $445 million. Our effective tax rate is expected to be around 33%. Christine, we've concluded our opening remarks. In a moment, we will open a call to questions. During the segment, we ask that our callers limit each turn to only two questions. Callers may rejoin the queue with additional questions as time permits.
Thank you. Ladies and gentlemen, if you have a question, please press star then one on your touch tone phone. If you wish to be removed from the queue, please press the pound sign or the hash key. If you are using a speakerphone, you may need to pick up the handset first before pressing the numbers. Once again, if you have a question, please press star then one on your phone now. Our first question is from Evan Calio of Morgan Stanley. Please go ahead.
Hey. Good morning, guys.
Hi, Evan.
My first question relates to cash distributions and unlocking value. Cash returns averaging 7% yield year-to-date. Yet you also built $1 billion in cash in the quarter. You're now through the low end of your leverage guidance of 20%-30%. I know you mentioned a target payout ratio, yet 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 billion. From there, we would like to keep some cushion in our cash balance given the volatility of our business. We look at the future capital and working capital requirements, then the payout of greater than 50% that we've already committed to you guys. I would like to point out that excluding the debt issue that we had in the first quarter, we actually had a decrease in cash of about $300 million.
Right. Right. There's upside scope, I guess, from a $5 billion cash position to distribution, I guess would be my question.
Yeah. Just to 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.
Right.
Go ahead.
Yeah, no. That makes sense. Then my second question is more on the product demand side. Global crack spreads have been higher than many expected year to date.
Global demand estimates continue to rise in response to low commodity prices. Is there any comments on 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.
Yeah, 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 refinery turnaround maintenance and that type of activity. Also, I think the USW union negotiation came into play and were supportive of the crack spread. That's 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 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 price of this.
Fair enough, guys. Thank you.
Thank you. Our next question is from Neil Mehta of Goldman Sachs. Please go ahead.
Good morning.
Morning, Neil.
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?
This is Gary again. I think the LLS to Brent spread 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. That tells you over time that LLS should be around $2 discount to Brent as long as the standard transportation differentials in the Gulf hold. I think some of what you're seeing today is the Houston market is bottlenecked with logistics getting to St. James, and so we're seeing Houston trade at a much wider discount to St. James than where it had been. That's going ahead and allowing these Jones Act economics to hold.
They're right at break even, and I would expect LLS to come off some.
Okay. That's very helpful. Then on RINs, just any thoughts as we get into the second quarter here on where RIN pricings are and how we should assess the impact on a go-forward basis?
Yeah, 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. 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. 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. 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 first quarter ran more South American crudes than what we've historically run. The Saudis seem committed to the U.S. market, so I don't know that we'll go back to levels of imports that we saw three years ago, but I definitely think the medium sour volumes into the U.S. Gulf will be up from what we saw last year. We've seen a lot more heavy Canadian with the start-up of Flanagan. Overall, the Gulf Coast seems well supplied with all grades of crude.
Right. Okay. On the VLP, obviously a great drop in March. A $1 billion, clearly very easy to achieve. Any view of going faster, or you just still think that $1 billion, which is obviously still a healthy pace, is the right pace going forward?
No, Ed, this is Joe, we're very comfortable with the $1 billion pace this year. 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. What our real focus is on the distribution increase, and we're committed to growing it at that 25% plus this year and for the next couple of years. We're very comfortable with the pace we've got right now.
Okay. Thanks very much, Joe.
Thank you. Our next question is from Paul Cheng of Barclays. Please go ahead.
Hey, guys. Good morning.
Hi, Paul.
Joe, a couple of years ago, I think the company, when looking at California, has always said it's not really a call for the long haul, and you're looking for if someone give you an OK price that you will sell. Is there any change in the view from management about how you look at California from a long-term standpoint? If it is now part of your long-term portfolio, is there any initiative that you are taking to improve the result relative to your peer that you seems to be lacking in there?
Yeah. 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. Frankly, we view our portfolio on the West Coast as an option when the margins are strong on the West Coast. Certainly, we're experiencing that today, and we had a very good first quarter. If you don't mind, Paul, what I'll do is let Lane just speak to our capital approach to the West Coast.
Lane, we just continue to be very disciplined in our capital. We look for small opportunistic things to try to improve margins capture. In terms of any major capital programs, in the event that we are to spend 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 Benicia makes so much gasoline, you'll see our capture versus an index probably got quite a bit better. The first quarter is really a story of, on the West Coast, is a 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 a minimum cash balance, but you can start with the $2 billion that we use in our debt to cash calculation. We would like to keep some cushion in that given the volatility of our business.
I see. Okay, thank you.
Thank you. Our next question is from Chi Chow of Tudor, Pickering Holt. Please go ahead.
Great, thanks. Good morning.
Good morning, Chi.
Good morning. Yeah, a couple of questions on the North Atlantic market. You've realized strong double-digit margins in that region for three quarters running now. PADD 1 and European crack's been pretty robust over this period. What do you think the sustainability of those tighter product markets in that Atlantic basin region?
I think there's a number of reasons for what we've seen in the first quarter, I think some of it is sustainable. Obviously, we had strong turnaround maintenance in that area as well. Colder weather always helps with demand. 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. I think there's a lot of encouraging signs on the Atlantic basin.
Chi, this is Joe. The one thing I would add to Gary's points, which are all correct, is that the Pembroke asset is a very good asset. 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. 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 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's been so strong. 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?
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 say the way we optimize that is more demand pull rather than supply push. 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 in the 255,000 barrels a day. Fairly consistent there. The change we saw is for a lot of the first quarter, the arb to Europe wasn't open.
Where we're usually 60/40 between Latin America and Europe, about 70% of our volume actually went to Latin America, and we didn't see the flow to Europe that we've traditionally seen.
Okay, great. 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, 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 third quarter. It gives us a lot more flexibility at 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 sourced 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. I know earlier we've talked about the potential for an evaluation of a whole set of fuels distribution and EBITDA as a potential drop to VLP. Maybe 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?
Yeah, Ryan, this is Mike again. We're still evaluating that and the approach structure that we would consider to drop to the MLP. I do not have a number that I can give to you on this call.
Okay, great. I appreciate it. Then maybe just we see the margins on the screen, which look supportive, but can you give us maybe just an update on what you've seen a month into second quarter in terms of the general operating environment?
Yeah. I think the cracks continue to be strong. We continue to see good discounts on the crude. The big change probably has been in the crude markets. 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 first quarter. Again, I think, we're seeing good demand both in the export markets and domestic demand, so we feel very encouraged about profitability moving forward.
Great. Thanks. I appreciate it.
Thanks, Ryan.
Thank you. Our next question is from Jeff Dietert of Simmons & Company. Please go ahead.
Good morning.
Good morning, Jeff.
I had a strategic question. I think historically Valero's 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, the expected materially larger midstream business?
Oh, Jeff, that's a good question. Very clearly, we are a fuels manufacturing company, and certainly that involves refining. It also involves our renewable fuels business. It is such a significant part of the portfolio today to see any significant shift from that, it's just really 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. As we've said, our strategy in midstream is really to develop projects and acquire assets that are supportive of Valero's core businesses. I think if you look at the investments that we've made to date, 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.
Good. Thank you. Secondly, looking through your refinery throughput guidance for the second quarter, it looked relatively conservative. My question is, are the LPGs suggesting you should max run? Under what conditions would you run more aggressively or perhaps less aggressively?
I think in terms of throughput, probably the biggest thing that 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 Port 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.
Morning, everyone.
Morning.
Morning, Brad.
Just following up on a couple previous answers, looking for a little more color. I think in the first quarter, 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 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. It 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 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 has also disrupted production there. 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 into the second quarter.
Okay. That's great color. Maybe for Joe, a lot of E&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, we know that there's activity in the House and the Senate to bring the issue forward. Certainly, the administration doesn't seem at all receptive to this. Just to be clear on our position, we believe in free and open markets. 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, these would include things like the crude export ban, the RFS, the Jones Act, and others. We believe that looking at a specific issue
To the overall issue is just not the right way to deal with this topic, you need to deal with all of the issues. The one thing about Valero is that we've continued to invest, we're running significant quantities of domestic crude today, we continue to invest to enable us to run more of this crude. We're doing what we can to process it, as are many other refiners. 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 million barrels per day coming in, we certainly export much lower volumes than that. The question becomes, do you really need the exports? 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.
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 debate? Because I think that's one of the key issues is the net balance as opposed to just the issue in itself.
Sure. Doug, if you don't mind, we'll let Gary speak to the imports.
Yeah. Doug, I would tell you that primarily what we see from Kuwait is really not light sweet, it's more medium sour barrels. 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-WTI arb moving in and out. When the arb comes in very narrow, we start to see incentives to import light sweet. In the first quarter, we definitely saw that.
As I've discussed in the past, the first place we generally see it is in Quebec, and there were certainly times during the first quarter where the Brent-WTI arb got narrow enough that it incentivized to step back in and buy Brent related West African type crudes.
Okay. I appreciate the answer, fellas. Obviously, we're watching this one closely, 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 first quarter. I think you guys said yourself in your prepared remarks, 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 methods of returning cash as opposed to just outright buying back stock at current levels? I'll leave it there. Thanks.
All right, Doug, I'll speak to it briefly and then see if Mike has anything to add. 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. 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 the 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.
I think if you said, "What are your plans?" I think 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?
I think that's well said.
Okay.
Thanks a lot, everyone.
All right, Doug.
Thank you. Our next question is from Phil Gresh of J.P. Morgan. Please go ahead.
Hi, good morning.
Morning.
Morning, Phil.
First question, just on the midstream M&A potential. Appreciate the color you've given already. Just a follow-up. Would you rather have more EBITDA drops at this point before you consider midstream M&A at VLP? Are you comfortable with the amount of EBITDA there already? To the extent that you would consider midstream M&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 third party acquisitions. As you know, the drops come with minimum volume commitments that you may not always get in a third party deal depending on the deal. Given their size, I would say the drops are the more likely path that they will go.
Got it. Okay. Just one final question on the export ban. I guess the question is really 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 refinery or logistics, potential M&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, I'll fly over this and then we'll let Gary speak to it if he'd like to also. Our strategy is to optimize our operations. 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. 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. We'll have to see what the market does and how the market would respond to that. I guess you'd be pushing additional crude barrels into a market that seems to be well-supplied today, the question in our minds is how is the market going to react to that?
Honestly, I don't think we're smart enough to tell you what that would be. Gary.
I agree. I think overall, even if the export ban's lifted, we would continue to have a location advantage running the domestic crude. We continue to have a significant operating cost advantage with the cheap natural gas, we're very happy with our portfolio of refining assets that are very complex, very efficient refineries.
Would it have a material change on your view of the crude differentials?
I don't think so. I think overall, the crude would have to continue to compete for space in the refineries, we're going to 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 sort of 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&A side? I mean, was it pretty much in line with what you were expecting?
Yeah, the interest rates were low and pretty much where we expected for that offering to come in at. The funds will be used for general corporate purposes, including the refinancing of our current maturities. 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. 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. I will obviously give a bit of an update. It's kind of where it's been. We'll anticipate our funding decision here late in the second quarter. I would just add that any real consideration, if this project goes forward and on our strategy, we'd obviously more than likely have a partner, and we know it had that in terms of maybe what some of our public comments are. We're still on track to review this project here late in the second quarter.
All right. Perfect. Thanks.
Thank you. Our next question is from Roger Read of Wells Fargo. Please go ahead.
Hey, good morning.
Hello, Roger.
Morning, Roger.
Just wanted to follow up, I guess, Jeff Dietert's question about potential higher throughputs and then what signals maybe we need to look for here, 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 second quarter 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 at some of our heavy sour refineries. I don't know of anything else that would signal significantly different throughputs.
I totally concur. Right now, our economic signals are maximum throughput, and Gary mentioned in an earlier answer, there obviously are rate things that occur depending on whether we're running light, medium, or heavy sour crude. That obviously has an impact on our overall throughput.
Thanks. Back to the OpEx, the initial comments mentioning under $4 for several quarters in a row here, and the FX strength that helped out Pembroke. Could you 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 know throughputs being high also helps on a per-barrel basis, but if there's anything else you could offer, that'd be great.
This is Lane. I would just 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 fixed and our structural operating costs. We did benefit from lower natural gas prices in the first quarter versus fourth and last year. Throughputs were a little bit lower, and so it was partially offset by that, but we will absolutely maintain our focus on having low operating costs.
Nothing specific we should think about, just it's a general pressure on the system?
No.
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 some spillover from the collapse in crude prices. Now that we're starting to see 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 a crack realization. As crude moves up, 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 or $2 a barrel that's needed? 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 or any of the new global facilities beginning to penetrate that market? Do you have any color there? I'd appreciate it. Thanks.
Yeah, 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. We have seen a move back to where the arb to Europe is open. It basically is just looking at the differences in the two markets' freight, then we also take into effect the RIN. The higher RIN prices that we're seeing today help to incentivize exports of distillate to Europe. Freight generally a little over $2 to get a barrel to Europe, then the RINs in this $0.71 range, that kind of gives you the differential that's needed to support exports.
Okay, thanks.
Thank you. 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 Lane. The McKee crude expansion, are we done yet? What is the schedule now?
No, we'll finish that. This is Lane, by the way, Paul. We'll finish it up in the third quarter of this year.
All right. Maybe this is for Gary. Gary, are you guys currently, given the current events, are you exporting crude oil from the Gulf Coast to Quebec? 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 crude into Quebec?
Yes, Paul. We are exporting from the Gulf to Quebec. In the first quarter, a little over 70% of our diet was crude sourced from Canada and the U.S. Gulf. 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 second quarter, your footprint is going to be much higher. Should we still assume that your margin capture rate, the pattern will be similar to the last two years that drop roughly about 10% from the first quarter level or that we should view it somewhat differently?
Paul. Generally what you see happen as you transition from the first to second quarter, you go through RVP transition on the gasoline, and with a decreased butane blending, which drives down our crack 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 IR department. Thank you.
Thank you. Thank you, ladies and gentlemen. This concludes today's conference. Thank you for participating. You may now disconnect.