瓦萊羅能源 (VLO) 2015 Q1 法說會逐字稿

Welcome to the Valero Energy Corporation reports 2015 first-quarter earnings results conference call.

My name is Christine, and I'll your operator for today's call.

(Operator Instructions)

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've not received the earnings release and would like a copy, you can find one 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 free to contact our investor relations team after the call.

I 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'll turn the call over to Joe for a few opening remarks.

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 would like to reaffirm with you before we proceed is that our team remains focused on executing our strategies to improve our evaluation through operations excellence, optimizing our business through disciplined capital allocation, and unlocking asset value.

With that, John, I will hand it back over to you.

Thank you, Joe.

What we would like to do now is highlight a few accomplishments this quarter that align with our key strategies and then we'll cover the quarter 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 ratio of 50%.

So far, we are on track to meet those goals, 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 maintained our guidance for capital spending, including turnarounds and catalysts at approximately $2.65 billion, which excludes $150 million for the 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 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.

Now 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 covered 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 by 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 the average at a 20% discount to Brent, versus the 17% discount in the first quarter of 2014.

Our significant crude spike flexible allows us to adjust feedstocks and optimize margins based on a discount environment.

Refined 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 in 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 $4.00 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-capital ratio, net of $2 billion in cash, was 20.3%.

Valero had over $10 million of available liquidity, including cash.

Cash flows in the first quarter included $698 million of capital spending, of which $240 million was for turnarounds and catalysts.

We've 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 have purchased 7.1 million shares for $429 million.

Now for modeling our second-quarter operations, we expect throughput claims to fall within the following ranges.

Gulf Coast at $1.55 million to 1.6 million barrels per day.

Mid-Continent at 430,000 to 450,000 barrels per day.

West Coast at 280,000 to 300,000 barrels per day.

And North Atlantic at 460,000 to 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 and our effective tax 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 two questions.

Callers may rejoin the queue with additional questions as time permits.

Thank you.

(Operator Instructions)

Evan Calio, Morgan Stanley.

Good morning, guys.

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% to 30%.

I know you mentioned a target payout ratio, yet how do you determine an optimal cash position as it continues to build and determine when to increase distributions from current rates?

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 expect that $2 billion.

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 have already committed to you guys.

But I would like to point out that excluding the debt issue that we had in the first quarter, we actually had an decrease in cash to about $300 million.

Right.

That is there's upside scope from a $5 billion cash position to distribution would be my question.

Yes.

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 positive like they are, we will assess this and consider increasing that payout number.

That makes sense.

And then my second question is more of 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.

Any comments on what you are 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.

Thank you.

Yes, this is Gary Simmons.

I think definitely we've seen 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 is 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 too early to tell what's the magnitude of the demand response will be in the flat pricing this quarter.

Fair enough, guys.

Thank you.

Neil Mehta, Goldman Sachs.

Good morning.

My first question is thoughts on spreads, in particular Brent LLS.

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 you know the LLS Brent spread has been a little bit more narrow than what we would expect.

I think ultimately the Gulf Coast sweet market has the price set at a level that allows the East Coast refineries to be able to receive domestic light sweet crude by rail or by ship.

That tells you over time that LLS should be around two dollars discount to Brent, as long as the standard transportation differentials in the Gulf hold.

I think now 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 is going ahead and allowing these Jones economics to hold, but they're right at break even and I would expect LLS to come off some.

That is very helpful.

And then on RINs.

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?

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.

Edward Westlake, Credit Suisse.

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.

You've got Mexico, Venezuela.

How would you characterize at the moment the supply availability of waterborne mediums in the south in the system?

It's been very good.

Like you said, we actually in the first quarter ran more South American crude than what we historically run.

The Saudis still committed to the US market, so I don't know that we will go back to levels of import that we saw three years ago.

But I definitely think that weakened volumes in US Gulf will be up from what we saw last year.

We've seen 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.

Obviously a great drop in March of $1 billion.

Clearly, very easy to achieve.

Any view of going faster or do you still think that $1 billion, which is obviously still a healthy pace, is the right pace going forward?

No, Ed.

This is Joe.

We are 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.

But what our real focus is on the distribution increase, and we're committed to growing into that 25% plus this year for the next couple of years.

We are very comfortable with the pace we've got right now.

Okay.

Thanks very much.

Paul Cheng, Barclays.

Good morning.

Joe, a couple of years ago 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 gives you an okay price, that you would accept.

Is there any change in the view from management about how you look at California from a long-term standpoint?

And if it's not part of your long-term portfolio, is there any initiative for you that you are picking to improve the results, relative to your peers that you seem to be lacking in there?

Paul, we've said this before.

On the West Coast, we have very good assets and we have a very good management teams operating those assets.

And frankly we view our portfolio on the West Coast as an option when the margins are strong on the West Coast.

And certainly we're experiencing that today and we had a very good first quarter.

If you don't mind, Paul, what I will do is let Lane speak to our capital approach to the West Coast.

Hello, Paul.

It's Lane.

We continue to be very disciplined in our capital.

We look for small opportunistic ventures to improve market capture.

But in terms of any major capital programs, in the event that we spend much money, we have better opportunities in our Gulf Coast and Mid-Continent.

I would say though one of the things you'll see in terms of our market capture, because we need to make so much gasoline, you'll see our capture versus an index probably got quite a bit better because the first quarter is really a story on the West Coast of the West Coast gasoline fracking.

The second question.

Mike, going back to the cash position.

Is there a level you can share -- what is the comfort level of the cash that you want to hold?

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-cap calculation.

And then we would like to keep some cushion in that, given the volatility of our business.

I see.

Thank you.

Chi Chow, Tudor, Pickering, Holt.

Thank you.

Good morning.

I've couple of questions on the North Atlantic market.

You've realized strong double-digit margins in that region for three quarters running now.

You've had one, and European cracks have been robust over this period.

What you think is the sustainability of those tighter product markets in that Atlantic Basin region?

I think there's number of reasons for what we've seen in the first quarter and 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 the US dollar strength versus the euro.

It helped 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 are 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.

When you think about merchant refining in Europe, you really shouldn't think about Pembroke in that regard.

The distillate barrels we produce are all moved inland and certainly a significant volume of the gasoline moves inland, so it's a little bit different set-up than some might be experiencing.

Are you concerned about distillate crack spread weakness going forward, with all the global capacity coming online in 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 things.

The US market has been so strong.

We still see good export demand, however we been somewhat priced out of the market because our market has been so strong.

We think moving forward, we'll see a combination of better demand domestically and we will see that our export volumes will pick up again as the US market falls off a little bit.

What were your export volumes for the quarter on gasoline diesel?

Gasoline was down a little bit at 94,000 barrels per day.

The reason for that was really just because of the strength in the US market.

Again, that's an optimization for us, so we would say that the way we optimize that is more demand pull rather than supply push.

And the export market's really weren't strong enough on gasoline to pull the barrels away from the Gulf.

Our distillate volumes were fairly flat at about 205,000 barrels a day.

If you look at ULSD plus kerosene, we were up 255,000 barrels a day, so fairly consistent there.

The change we saw -- for a lot of the first quarter, the yard to Europe wasn't open, so we're easily 60/40 between Latin America and Europe.

Up 70% of our volume actually went to Latin America and we didn't see that flow to Europe that we traditionally see.

Okay, one more question on the North Atlantic.

Could you talk about how the Line 9B Reversal is going to impact your crude sourcing options in Quebec, going forth?

I'll give you a little update on that.

We're still waiting for regulatory approval on Line 9 from the National Energy Board in 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 impacts from Line 9 in the second quarter.

But we're optimistic we'll start to receive oil in the third quarter, given there's 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 US Gulf Coast sourced barrels.

Okay, great.

Thank you.

I appreciate it.

Ryan Todd, Deutsche Bank.

Great.

Thank you.

Good morning, gentlemen.

If I could follow up first with a question on VLP.

I know earlier we talked about the potential for an evaluation of the whole summer field distribution EBITDA, the potential drop to VLP.

Could you talk a little bit about whether that is still under evaluation, and any rough guide as to what that figure might look like?

Yes, Ryan.

This is Mike.

We are still evaluating that in the appropriate structure that we would consider to drop in the MLP.

I do not have a number that I can give to you on this call.

Okay.

Great.

I appreciate it.

Maybe just a general -- we see the margins on the screen, which look supportive, but can you give us an update on what you've seen a month into the second quarter, in terms of the general operating environment?

Yes.

The crack 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.

But again, I think we're seeing good demand both in the export market and domestic demand.

And so we feel very encouraged about possibilities, moving forward.

Great, thank you.

I appreciate it.

Jeff Dietert, Simmons & Company.

Good morning.

I have 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 in Corner Store, and I was hoping for an update on how Valero strategy is evolving, going forward.

Where you think about integration through the value chain?

Do you expect a materially larger midstream business?

Jeff, that is a good question.

Very clearly we are a fuels manufacturing company, and certainly that involves refining.

It also involves our renewable fuels business.

That is such a significant part of the portfolio today.

To see any significant shift from that, it's really not in the cards.

Now to answer your question on the midstream business, I do think that we're going to see our midstream business expand significantly over the next several years.

And as we have 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 investment 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 to be looking upstream from where we are today at any material way or significantly downstream from where we are today.

Although opportunities present themselves and you'd look at it, but certainly that is not part of our plan today.

Thank you.

Secondly looking through your refinery throughput guidance for the second quarter, it looked relatively conservative.

My question is, are the LPs 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 plans, depending on if we're maximizing heavy sour versus light sweet.

Especially in Port Arthur, Jeff.

It can change our throughput significantly when start maximizing light sweet over heavy sour.

I would say that was the only thing I can see.

Thank you for your comments.

Brad Heffern, RBC Capital Markets.

Good morning, everyone.

Just following up on a couple previous answers, looking for some more color.

I think in the first quarter, you all had talked about 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 has 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 in collective roles, so it tightened up the medium sours.

Now that storage is getting full.

You also have some turnaround maintenance going on to the Deepwater platforms in the Gulf.

That is also tightening the market a little bit.

And in the heavy sour side, on the Maya, you had the fire on the platform in Mexico, which also disrupted production there.

My view is that these crudes have to compete with the light sweet, and we will see the differentials come back as we move forward in the second quarter.

That is great color.

And maybe for Joe.

A lot of EMPs have seemed pretty confident of late that the crude export ban is going to be lifted in the near term, maybe in 2015.

Do have any updated thoughts or anything you've been hearing about that?

I think we're probably hearing the same thing that you are hearing.

And we know that there is 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, we believe in free and open markets.

As we talked about many times, there's currently legislation and regulations in place that hinders the petroleum markets from being free and open, and these would include things like the crude export ban, RFS, the Jones Act and others.

We believe that looking at a specific issue relative to the overall issue is just 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.

We are doing what we can to process it, as are many other refiners.

And really the last point on this is when you look at the general need for crude exports, the US remains a net importer of crude oil, with about 7 million barrels per day coming in, and we certainly export much lower volumes than that.

The question becomes do you really need the exports?

I think that is the question on everybody's mind.

Okay, great.

That it for me.

Thank you.

Doug Leggate, Bank of America Merrill Lynch.

Thank you.

Good morning, everyone.

Guys, if I could follow up on the last question on exports, Joe.

From what we were seeing, it looks like light sweet imports from the Middle East in particular, looking at Kuwait in particular as one example, they actually seem to have been increasing.

I'm curious as to what is your strategy around accessing light sweet or just generally crudes outside of the US?

And how do think that impacts the crude export debate?

Because I think that's one of the key issues, the net volume as opposed to the issue in itself.

Sure, Doug.

I'll let Gary speak to the imports.

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've had many discussions with them, and they seem interested on maintaining or actually growing market share in the US on that grade of crude.

On the light sweet, a lot of what we see happening with all this volatility in the Brent TI R moving in and out.

When the R comes in very narrow, then we start to see incentives to import light sweet.

In the first quarter, we definitely saw that and as I discussed in past, the first place we generally see it is in Quebec.

And there were certainly times in the first quarter were the Brent TI got narrow enough that it inncentivized to step back in and buy Brent-related West African type crudes.

Okay.

I appreciate the answer, fellows.

Always good work.

I'm watching this one closely.

My follow-up, Joe, is really on the return of cash to shareholders.

It's obviously a share price.

I guess oil refineries have done well from a lot of the strength in the first quarter.

I think you guys said yourself in the prepared marks 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, in the fact that you are again embarking on very substantial share buyback program, how do you think about balancing the timing and the balance between dividends and other methods of returning cash, as opposed to outright buying back stock at current levels?

And will we be there?

Thank you.

Doug, I will speak to it briefly and then see if Mike has anything to add.

But the timing of the market is something that it's almost impossible to do.

I think the particular transaction you're referring to might have been the accelerated share repurchase that we executed some years ago.

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 have committed to this greater than 50% payout ratio, which we've 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.

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 would --?

No, I think that was well said.

Thank you.

Good luck, everyone.

Phil Gresh, JPMorgan.

Hello, good morning.

First question is on the midstream M&A potential.

I 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&A at VLP?

Or are you comfortable with the amount of EBITDA there already?

And 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.

At this point in VLP's stage that they probably would prefer to do the drops and get a little bit more excitable 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.

So given their size, I would say the drops are the more likely path that they will go.

Got it.

Good catch.

And just one final question on the export ban.

The question is really if you think about the ban being lifted, if it were to happen, would this materially change how you'd manage your business?

Whether it's growth projects for refining or logistics?

Potential M&A aspirations?

Just generally how you think about the way your managing our business today versus in that kind of a world, and how you'd think about crude differentials?

I will fly over this and then we will let Gary speak to it, if you would like to also.

Our strategy is to optimize our operations.

And that is a broad statement, I know, but it goes to our crude and feedstocks 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 is nothing that we are 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.

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 --?

I agree.

Overall, even if the export ban was 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.

And then we're very happy with our portfolio of refining assets that are very complex, very efficient refineries.

They wouldn't have a material change on your view of the crude differentials?

No, I don't think so.

Overall, the crude has to continue to compete for space in the refineries, and so we're going to be the beneficiary of that.

Okay, great.

Thank you.

Sam Margolin, Cowen.

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&A side?

In your view, was it pretty much in line with what you are expecting?

The interest rates were well 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 projects or anything like that.

It was an opportunity to issue debt at a low rate.

Okay.

Thank you.

I don't think -- I heard you guys mentioned 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 still just in the evaluative stages and we'll wait on the final decision?

Sam, this is Lane.

I will give you a bit of an update.

It's where it's been.

We anticipate our funding decision here, late in the second quarter.

I'll just add that any real consideration, if project goes forward in our strategy, we obviously more than likely have a partner.

I would add that in terms of making any public comments, but we're still on track to review this project here, late in the second quarter.

All right.

Perfect.

Thank you.

Roger Read, Wells Fargo.

Good morning.

Just wanted to follow up 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 last mile pipeline issues in the Gulf Coast to think about you hitting a higher throughput number in the second quarter?

Potentially getting a higher number also?

I don't really know.

I'll let Lane comment.

The only thing I can think of is we're definitely signaling higher runs of light sweet crude, which can have a rate leverage over heavy sour refiners, but I don't know of anything else that would signal significantly different throughput.

No, I thoroughly concur.

Right now, our economic signal is our maximum throughput and Gary mentioned earlier, there's obviously a rate thing that occurred, depending on whether we're running light, medium or heavy sour crude.

That obviously has an impact on our overall throughput.

Okay.

Thank you.

And then, back to the OpEx.

The initial comments mentioning under $4.00 for several quarters in a row here, and then 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 been high also helps on a per barrel basis, but if there's anything else you could offer, that would be great.

This is Lane.

We're always vigilant on operating costs.

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 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.

Okay.

Thank you.

Blake Fernandez, Howard Weil.

Hello, guys.

Good morning.

Two questions for you.

One, you mentioned in the press release the benefit of secondary product pricing.

And I assume that is some spillover from the collapse in crude prices.

But now that we are 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 Q2?

I would definitely say that when you get out into the product other than gasoline and diesel, sulfur and coke LPGs, a lower flat price environment tend to have these products trade closer to crude value and it helps us on frac realization.

And as crude moves up, then the reverse would also be true.

Okay.

And Gary secondly just follow-on from your previous export commentary, the shift that we've seen away from Europe.

Can you 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 $1.00 or $2.00 a barrel that's needed?

As a follow-on to that, do have any sense -- I know you mentioned indigenous demand growth here -- but you have any sense that maybe aside from European utilization rates moving up, are any of the new global facilities beginning to penetrate that market?

Do you have any color there.

I'd appreciate it.

Thank you.

I'll start with that.

Thank you.

We still feel our traditional export markets are there for us, as long as it's economic for us to supply those markets.

And we have seen it move back to where the yard to Europe is open.

It basically is 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 the exports of distill to Europe.

Freight, generally lower than $2.00 to get a barrel to Europe, and then the RINs in the $0.71 range, and that gives you the differential that is needed to support exports.

Okay.

Thank you.

Paul Cheng, Barclays.

Hello, guys.

Two quick follow-up.

One, Joe, can you give us -- maybe this is for Lane.

The McKee crude expansion.

Are we done yet or what is the schedule now?

No, we will finish that.

This is Lane, by the way, Paul.

We'll finish it up in third quarter of this year.

All right.

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 that 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 US Gulf.

And post-Line 9, we would still anticipate that we would see some flow of oil from the US Gulf Coast to Canada over the line.

Can ask a final question?

Just for you, Paul.

Thank you.

In the last two years, when we looked at from the first to the second quarter, your margin capture rate seems like it was on average up by about 10%.

In the first quarter this year, that you have far more heavy downtime, especially in the Gulf Coast, and in the second quarter, your full year going to be much higher.

Should we still assume that your margin capture rate would be -- the pattern will be similar to last two years, that drop of roughly about 10% from the first quarter, that's all?

Or that we should read it somewhat differently?

Yes, Paul.

Generally what you see happening as you transition from the first to second quarter, you go through RPT transition on the gasoline and we decrease butane blending, which drives down our crack containment.

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.

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 at 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 disconnect.