瓦萊羅能源 (VLO) 2014 Q4 法說會逐字稿

Welcome to the Valero Energy Corporation announced fourth quarter 2014 earnings results conference call.

My name is Hilda and I will be your operator for today.

(Operator Instructions)

This conference is being recorded.

I will now turn the call over to Mr. John Locke.

Mr. Locke, you may begin.

Good morning, and welcome to Valero Energy Corporation's fourth quarter 2014 earnings conference call.

With me today are Joe Gorder, our Chairman and CEO; 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 web site at valero.com.

Also attached to the earnings release are tables that provide additional financial information on our business segments.

If you have any questions after reviewing these tables, please feel free to contact our investor relations team after the call.

I would like to direct your attention to the forward-looking statement disclaimer contained in the press release.

In summary, it says that statements in the press release and on this conference call that state the Company's or Management's expectations or predictions of the future are forward-looking statements intended to be covered by the Safe Harbor provisions under Federal Securities laws.

There are many factors that could cause actual results to differ from our expectations including those we've described in our filings with the SEC.

Now I will turn the call over to Joe for an update on Company operations and strategy.

Thanks very much, John, and good morning, everyone.

As John will cover in more detail momentarily, we did have a great fourth quarter and a great year.

What I'd like to do is spend a few minutes discussing our key strategies and highlight a few of our accomplishments in the quarter.

As you've seen from our recent disclosure, our strategies are focused on operations excellence, returning capital to stockholders, maintaining disciplined capital investments, and unlocking asset value.

Operations excellence continues to be important to us.

Our team understands that reliability drives safe and profitable operations, so we are relentlessly committed here.

An example of this can be seen in our Meraux refinery where we completed our reliability improvement program and the hydrocracker revamp project.

We expect the investments we've made here to improve the refinery's reliability and performance.

Disciplined capital allocation is another key focus for us.

Last week, we increased our regular cash quarterly dividend by 45% to $0.40 per share or $1.60 annualized.

This increase demonstrates our belief in Valero's earnings power and our commitment to returning cash to stockholders.

Regarding capital investments, we completed our 2014 capital program under budget as noted in the release.

This resulted from the rigor and discipline that Lane and his team applied to spending throughout Valero's gated project management process.

We're committed to applying this same rigor to future investments.

The majority of our growth investments for 2015 and 2016 are allocated to logistics and to increasing our capability to access and process advantaged crude oils through our flexible refining system.

We expect the majority of the logistics investments to be eligible for future drops to Valero Energy Partners, which is our sponsored master limited partnership.

On the topic of VLP, we're committed to its growth in unlocking value.

As we noted in the release, we're targeting approximately $1 billion of drops into VLP in 2015.

At that level of growth, we also expect VLP's distribution to exceed the 50% tier for our general partner in incentive distribution rights by the end of this year.

We're continuing to evaluate and structure new potential earnings streams that can be dropped to VLP and those represent incremental growth opportunities.

We understand the MLP landscape has changed since our IPO and we're committed to unlocking value.

In summary, we're focused on operational excellence, disciplined capital allocation, and value creation.

Our team remains committed to high performance and achievement.

And with that, John, I'll go ahead and turn it over to you to cover the results.

Thank you, Joe.

As shown in our earnings release, we had another strong quarter.

We reported fourth quarter 2014 earnings from continuing operations of $1.2 billion or $2.22 per share.

Adjusting for special items described on page 7 of the financial tables that accompany our release, we earned $952 million or $1.83 per share which compares to $963 million or $1.78 per share in the fourth quarter of 2014.

For the full year 2014 we reported earnings from continuing operations of $3.7 billion or $6.97 per share.

Adjusting for special items, we earned $3.5 billion, or $6.68 per share in 2014 versus $2.4 billion or $4.41 per share in 2013.

The refining segment reported fourth quarter 2014, operating income of $1.9 billion versus $1.5 billion in the fourth quarter of 2013.

Nearly all of the $377 million increase in operating income resulted from the previously noted special items.

Excluding the special items, operating income was flat in the fourth quarter of 2014, versus the fourth quarter of 2013, as stronger gasoline, distillate and other product margins relative to Brent crude oil, as well as higher refining throughput volumes were offset by lower discounts for sweet and sour crude oils relative to Brent crude oil.

Refining throughput volume averaged 2.8 million barrels per day in the fourth quarter of 2014, which is an increase of 41,000 barrels per day versus the fourth quarter of 2013.

Refining cash operating expenses in the fourth quarter of 2014 were $3.76 per barrel, which is $0.03 per barrel lower than the fourth quarter of 2013.

The ethanol segment generated $158 million of operating income in the fourth quarter of 2014 versus $269 million in the fourth quarter of 2013.

The decrease in ethanol segment operating income was mainly due to a $0.31 per gallon decrease in gross margin driven by lower gasoline and ethanol prices with relatively stable corn prices.

Production from the Mount Vernon plant contributed to record quarterly ethanol production volumes which averaged 3.8 million gallons per day in the fourth quarter of 2014.

General and administrative expenses, excluding corporate depreciation, were $214 million in the fourth quarter of 2014, which is $35 million higher than in the fourth quarter of 2013, primarily due to changes in legal reserves.

Also in the fourth quarter of 2014, net interest expense was $101 million and total depreciation and amortization expense was $425 million.

The effective tax rate was 28.4%.

The rate was lower than normal due primarily to earnings from our international operations that were higher than projected and taxed at statutory rates that are lower than in the US, the biodiesel blenders tax credit that was passed into law in December and the reversal of certain tax reserves.

With respect to our balance sheet at quarter end, total debt was $6.4 billion and cash and temporary cash investments were $3.7 billion, of which $237 million was held by VLP.

Valero's debt-to-capitalization ratio, net of $2 billion in cash and excluding VLP, was 17.4%.

Valero had approximately $6.1 billion of available liquidity, in addition to cash, including VLP's $300 million of available liquidity.

Cash flows in the fourth quarter, included $857 million of capital expenditures of which $157 million was for turnarounds and catalysts.

In the fourth quarter, we returned $640 million in cash to our stockholders which included $143 million in dividend payments and $497 million in purchases of approximately 10.3 million shares of Valero common stock.

Our total cash returned to stockholders for 2014 was $1.9 billion, a 33% increase over 2013 and included $554 million in dividend payments and purchases of 25.7 million shares for $1.3 billion.

For 2015 and 2016, we maintain our guidance for capital expenditures including turnarounds and catalysts.

In 2015 we expect to spend approximately $2.65 billion, consisting of approximately $1.5 billion for stay-in-business capital, and $1.15 billion for growth investments and this excludes $150 million for a St.

Charles methanol project that remains under evaluation.

For 2016 we expect to spend approximately $2.4 billion, consisting of $1.4 billion for stay-in-business capital and $1 billion for growth investments, excluding $300 million for the St.

Charles methanol project.

For modeling our first quarter operations, we expect throughput volumes to fall within the following ranges: Gulf Coast will add 1.45 million to 1.5 million barrels per day; Mid-Continent at 430,000 to 450,000 barrels per day; West Coast at 240,000 to 260,000 barrels per day; and North Atlantic at 450,000 to 470,000 barrels per day.

We expect refining cash operating expenses in the first quarter to be around $4.20 per barrel.

For ethanol operations in the first quarter, we expect total production volumes of 3.7 million gallons per day, and operating expenses should average $0.37 per gallon which includes $0.04 per gallon for noncash costs, such as depreciation and amortization.

We expect G&A expense, excluding depreciation for the first quarter, to be around $170 million and net interest expense should be about $100 million.

Total depreciation and amortization expense in the first quarter should be approximately $440 million and our effective tax rate should be around 33%.

Operator, we have concluded our opening remarks.

In a moment we will open the call to questions.

During the segment, we request that our callers limit each turn to two questions.

Callers may rejoin the queue with additional questions.

(Operator Instructions)

The first question comes from Chi Chow from Tudor, Pickering, Holt.

Great, thank you.

I've got a couple questions regarding your very strong performance in the Gulf Coast region.

I guess first, can you explain the gross margin adjustments you show on the back of the table, in particular that blenders tax credit and if that's going to be sustainable going forward?

And then, secondly, even with the adjustments, looks like your capture rate was very strong sequentially versus 3Q when all the indicator cracks were down.

I was wondering if you can explain some of the factors that were coming into play versus the indicator.

Okay.

Chi, this is Mike.

On the blenders tax credit, that was passed into law in December for 2014, so it was available to us last year.

At this point, it is not passed for 2015, so we would not have that in our earnings going forward.

Okay.

Then on the margin capture, Gary, do you want to speak to that?

Yes, I would say in the Gulf Coast, margin capture is largely attributable to great performance on the hydrocrackers in terms of refinery operations.

And we also began to see some good advantages on running some of the South American heavy sour crude again in our Gulf Coast system in fourth quarter.

Okay.

Great.

How much impact was there just with the decline in crude prices?

Is that something that if crude prices stabilize or eventually increase is the capture rate going to switch there versus what we saw in the fourth quarter?

We definitely see some benefit in terms of capture rate at a lower flat price.

It's mainly the other products that we produce, the sulfur, petcoke, LPG, those types of things.

When the flat price is lower, we tend to have higher capture rate because those products tend to be a little sticky with crude.

Okay.

Great.

I guess one final question on the Gulf Coast, looks like the Maya light-heavy differentials were pretty wide here in the first quarter so far on a percentage basis.

How has your crude slate changed versus 4Q?

Looks like you ran a lot of light crudes in the fourth quarter.

Has that changed here going forward, and do you have any sort of earnings sensitivity to the Maya spread?

Yes, I guess to answer the question on our crude diet.

We tend to buy crude out quite a ways.

Probably the first month you start seeing a significant change in our crude diet will be March.

And we have started to move in the direction that's exactly what you talked about.

At several of our Gulf Coast refineries we're backing down on some of the light domestic type crudes and starting to run a higher percentage of medium sour crudes and heavy sour crudes, as those have been more economic for us to process in the Gulf.

Do you have any sort of EPS sensitivity to changes in the light- heavy?

No, Chi, we don't.

Okay.

All right.

Thanks a lot.

The next question comes from Brad Heffern from RBC Capital Markets.

You all announced a pretty substantial dividend increase last week, I think.

Has that changed your thoughts at all on the buyback?

And how do you think about dividend versus buyback in general and then versus capital projects or acquisitions?

Mike, do you want to.

Yes.

No, we're committed to returning more of our cash to our stockholders based on our analysis of the market data and capital allocation scenarios.

We're still interested in high-return projects, but our capital is down, projected as we've disclosed, so we felt it was appropriate to increase the dividend at that level.

So we're going to be looking at exceeding our payout ratio going forward in 2015 from what we've had the last couple years.

This is Joe.

As far as our consideration of the dividend versus buybacks, when we did the analysis and looked at where our dividend was relative to the peer group, we felt that we were a little bit low.

And so this type of move was something to get us more aligned with the other guys.

It's also something that we view as being nondiscretionary when we look at our use of cash going forward.

The share repurchases, we're committed to trying to achieve a metric that we've defined internally and we're going to continue to pursue that, as Mike said.

But that will be more flexible for us than the dividend, which we consider to be, as I mentioned, nondiscretionary.

Okay.

That's great color.

Thanks.

And then looking at refined product exports for the fourth quarter, do you have a figure you can provide as to how much you exported?

And can you also talk about how demand is looking for those exported barrels.

Yes, this is Gary Simmons again.

In the fourth quarter, we did 139,000 barrels a day of gasoline exports on the distillate side; ULSD, we did 208,000 barrels a day.

In addition to the ULSD, we also exported kerosene and jet and if you included that total distillates would be 255,000 barrels a day.

In terms of the current market, I would tell you we're starting to see some incentive to export gasoline again, especially to Latin America and to Canada.

Most of the distillate arbs was the strength in the Gulf.

There's not a lot of incentive to do much distillate export in the current market.

Thank you.

The next question comes from Phil Gresh from JP Morgan.

Hey, good morning.

Good morning.

Just a follow-up on the capital allocation question.

You talk about having a payout ratio that exceeds the 50% of net income for 2014.

Consensus actually has EPS down year-over-year.

You also have some excess cash; you have this accelerated drop program.

I'm trying to calibrate how high you're comfortable going, in 2015, as a percent of net income if, indeed, consensus is right.

I figured that you'd probably ask a question like this, and really the target we've set is the one that we've stated.

It's to exceed the previous year.

As I mentioned previously, internally we've got a target that would be higher than that.

I'm not prepared right now to give you a fixed percentage for the overall payout ratio.

I just think we need to see how the year evolves.

Look at the dynamic nature of the market we're dealing with today.

We have seen crude go from $100 late last year to $50 this year.

And so for me to give you a committed number right now is something that probably just wouldn't be prudent to do.

So I think for now, if I were you, I would just assume that we're going to exceed the 50% target and go with that.

Okay.

Understood, and that actually tees on my next question, which is just your general outlook for the market.

As we exited 2016, it's starting to look like crude oil production growth could actually be down year over year.

There is talk of increased global refining capacity.

So given this dynamic market, I would love to hear your general big-picture views and how you're thinking about planning for this type of environment?

That's a fine question.

And Gary Simmons is so very close to this.

Let us let him go ahead and comment on it.

Overall, I think we see that the crude market will continue to be in an oversupplied position for the foreseeable future.

I think the fact that the Saudis have signaled that they are going to continue to put medium sour barrels on the market will mean that our medium sour differential should remain supportive.

The combination of that with additional Canadian heavy into the Gulf, we believe will give us good heavy sour differentials, as well.

Both those things we think are very supportive in terms of Valero's performance moving forward.

When you turn to the refined product side, it's a little unclear at this stage to see exactly what will happen with refinery margins.

However, we think that the fall-off in flat price, we should see a positive demand response, and you have been able to see that in the past few weeks in the BOE stats, and so as demand increases that should also be supportive of refining margins.

Thanks a lot.

The next question comes from Paul Cheng from Barclays.

Hey, guys.

Good morning.

Good morning, Paul.

Two questions.

First, if I look at your margin capture rate against your Valero index that you post in your web site, it was quite amazing that the last two year, 2013 and 2014 versus the two year before in 2011, 2012, your capture rate actually improved somewhere between 3% to 9% between these two period, with the exception of the West Coast.

So I'm wondering if you can help us that how much of the -- trying to quantify, how much of the improvement you think is just that the market condition is just in favor of your configuration and how much of that is really based on the better operation reliability that you guys have been able to improve?

And how much is related to the large capital investment that previous years you have made and have subsequently come on stream?

The second question, however, you want to answer that before I go to a second?

Yes, because Paul, that was a pretty long one, huh?

Paul, I tell you, we'll let Gary speak to this, but just as a member of Management for the last several years, I'd like for us to take credit for all of it.

But that being said, Gary, do you want to give your view?

Yes, so I would tell you, Paul, probably you have to look at this regionally.

And when you look to the Mid-Continent, you know, some of our improvement capture rate has been due to the fact that the Midland market has been very disconnected from the Cushing market over the past couple years, and the wider Midland spreads, we're running a lot of Midland barrels to Ardmore and McKee.

That's certainly helped our capture rates there.

Same thing in the North Atlantic basin.

I would say a lot of that is market driven, especially as we transition Quebec from a foreign crude diet to a North American light-sweet crude diet.

We saw a significant increase in our capture rate there.

However, in the Gulf, I would say that the improvement in capture rate is primarily just the fact that we're seeing a lot better yields and the operational improvements we've made in our Gulf Coast system.

And how much of the benefit is coming from the investment that you have been making?

Is there any way that we can quantify it?

Paul, in the recent analyst presentations we have put together, we have included a lot of information on the economics associated with the projects, and the hydrocrackers are the ones we tend to focus on.

I think what you can expect is that we'll continue to disclose this information as we go forward.

And we obviously believe that the capital that's been invested over the last several years has had a significant effect, not only in, for example, the hydrocracker projects in driving the capture rates relative to more distillate production, but the increase in the reliability in our system and so on.

It's all beneficial.

We haven't tried to pin down specifically what's related to what, but I think we can all see it in the results.

Final one.

I think that there's a change in your project investment decision process comparing to the past.

Maybe that you can elaborate a little bit more in terms of what condition may have changed or what criteria you have changed differently now?

Thank you.

Paul, it's Lane.

As you mentioned, we're bulking up for a deliberate gated process.

Really, what we look for are projects that will enter our gated system.

We don't even look at them unless they have sort of a 50% IRR at the gate one.

And they also right now have a tendency to be a little bit more focused toward feed stock optimization, and not nearly as large as maybe some of the projects that had started in the past.

Thank you.

Our next question comes from Jeff Dietert from Simmons & Company.

Good morning.

Good morning, Jeff.

There's been some refining margin strength in Europe and on the US East Coast, the Atlantic basin refining margins overall have been pretty healthy relative to the other regions.

Could you talk about what factors you believe are contributing to this strength as a marginal product on the US East Coast?

Is it supplied by US Gulf Coast via Jones Act Ship or what do you think is causing the strength in the Atlantic basin?

Hey, Jeff, this is Gary, and I think you hit exactly on it.

We saw the New York harbor market get very strong; the Colonial pipeline is always full, so that means the barrel is flowing in there to set the price as either a barrel from the US Gulf Coast on a Jones Act ship or a barrel from Western Europe.

And so when you incentivise imports and incentivise the flow as with Jones Act ships from the Gulf, the harbor market had to strengthen.

So Jones Act laws are actually increasing prices on the East Coast?

Yes.

Secondly, I was hoping you could comment on the EPA and the renewable fuel standard and what you're anticipating could happen there; rents prices have risen with the uncertainty that's been created there.

Could you comment on that issue?

Yes, so we're still waiting for the final numbers for 2014, and the numbers for 2015 to come out from the EPA.

We're hopeful we'll have something by the end of March.

That's kind of what we're hearing.

And as you pointed to, until those numbers are set, we see the rent market as being very volatile, and so we're hopeful we get some direction here pretty soon from the EPA.

Thanks for your comments.

The next question comes from Blake Fernandez from Howard Weil.

Hello.

Good morning.

My question's on the VLP drop.

Appreciate the more aggressive strategy.

The way I had kind of envisioned this in the past was a progressive increase over time.

So I'm just curious, do you think the $1 billion in 2015 kind of sets a baseline to where we should expect progressive increases into 2016, 2017, et cetera?

Yes, this is Joe, Blake.

This drop, as you had mentioned, is really much larger than we had previously planned.

But, you know, we have quite a portfolio of logistics assets, which we mentioned.

And obviously this level of drops based on the EBITDA that we have in the system would allow us to sustain this level of drops for some years to come.

It's our intention to continue to drop at a pace that makes sense for Valero and for VLP.

As you know, we continue to invest in logistics projects that support the refining operations and then Mike Ciskowski and his team are evaluating additional sources of qualifying EBITDA, such as that from the fuels distribution business.

So when we look at our portfolio today, we believe that this is sustainable for some period of time.

If you look at VLP specifically, we stated that our plans were to increase the distribution by 20% to 25% a year.

And based on this particular drop, I think that you can expect that we're certainly going to be at the high range of that for this year, and it looks like it's very sustainable going forward.

Great, thanks, Joe.

Second question.

The OpEx guidance you have of $4.20 a barrel, if I'm not mistaken, that seems a little bit higher than where we've been trending last year?

And I'm just curious if there's anything in there that's driving that, and maybe if you could tie in with that as we move more toward heavy sour runs.

Should we expect that to create some upward pressure on the operating costs?

I'll leave it there, thanks.

Hey, Blake, this is Lane.

So the guidance really is a function of we have some turnaround, some essential turnaround activity that's going to occur here late in the first quarter, so our volumes are a little bit lower.

And then I would also say that the outlook is pretty consistent in terms of natural gas price from the fourth quarter to the first quarter, so that's sort of the reasons we have the guidance where it is.

Okay.

And if you don't mind, just any comments on, again, with the heavy sours coming back into favor, should we think of -- would that have an upward pressure on operating costs moving forward?

No, not really, no.

Okay.

Thank you.

The next question comes from Evan Calio from Morgan Stanley.

Nice to see strong results in energy somewhere.

My first question is -- it's a different take on a prior question on the outlook.

You address the souring and heavy and crude oil global slate with higher OPEC market share growing Gulf of Mexico and Canadian production.

Can you discuss the developing and steepening contango and how it benefits Valero, especially given the structural way in which the crude markets are being forced to balance with the US as the new swing producer?

Evan, this is Gary Simmons.

Really the contango market structure is just a good indication that the crude market is oversupplied and so as a buyer of crude, Valero benefits from the competition for producers to gain market share.

So we think this is supportive for us for at least the next couple of years.

Right.

And can you quantify how much you're hedging on TI to avail one to two or one to three months contango and how you think about your own storage assets in this market, or even do you see the potential for US storage filling?

Yes, so I think definitely when you look at the economics of what you can get tankage in Cushing, those economics are supportive of putting oil in tankage and storing it there.

I think we'll continue to see Cushing builds.

I read something this morning, they expect Cushing to continue to build about a million and a half barrels a week through April.

In terms of us particularly, we do some of that; we don't do a lot of it.

When we choose to put barrels in storage and take advantage of contango, it's also for other reasons.

We may see an opportunistic barrel that we think has a good discount.

We might not be able to fit it into our system, so we'll go ahead and put those in tankage in Aruba and take advantage of the contango and also what looks to be an opportunistic purchase for us.

Great.

Maybe a second one for me.

And it's maybe more a request for detailed information if you don't have that data, but can you break down the $900 million of [MLP-able] EBITDA into any subcategories?

And I guess I raise the question, the sense of one of the subcategories of recent spending is rail, also has some commodity price exposure to that subsegment.

Yet, I know, however, you use a significant portion of that rail fleet to move product under ethanol which should have relatively higher utilization tariff.

Any breakdown or help us in the composition of the EBITDA and/or -- sorry, I made this a multi-type question, I didn't intend to -- or any breakdown of just that rail segment?

How much is product in ethanol?

I'll leave it at that.

Evan, no, that's fine.

And because it's a multi-part question, we'll let Rich and Martin Parrish answer this.

Obviously Rich is President of the VLP, and Martin runs the ethanol business, the renewables business.

So why don't we let those two guys speak to this and see if we can get you some color here.

Great.

On the rail cars, just to kind of break that down a little bit, obviously they are qualifying to drop down to the VLP.

We've created a company to hold these cars and our intent is to drop these cars down in tranches over time.

But if you look at the cars that we have, there's general purpose, and they're coil and insulated cars.

The coil and insulated cars, obviously, fit well into the ethanol business, and the coil and insulated would fit into the asphalt and crude and fuel oil business.

But our intent would be to drop these down over time in tranches.

Okay.

This is Martin Parrish.

We have about 3,000 cars in ethanol service to general purpose cars, as Rich said.

As those leases expire, we'll take those off and use the VLP cars.

As you know, rail is the primary transport for ethanol.

We expect these cars to be highly utilized and a good fit for VLP.

Now to the broader question on the $900 million.

Rich, do you want to provide a little more -- ?

Evan, this is Rich again.

To kind of break down broadly the $900 million of EBITDA.

When we were out on the road a year ago, we talked about our retained assets.

So there's probably about $620 million of EBITDA implied upstairs at the parent level.

And from 2013 and 2014, we've got about $1.4 billion capital spending, which is mostly complete.

So that would generate roughly another $140 million of EBITDA.

So that kind of gets you to an $800 million number.

And then in 2014, we've got another $400 million of capital spending, which generates another $40 million in 2017.

We've got 2016 and 2017.

We've got large spending on our -- what we talked about in the past, the Diamond pipeline, and some other pipeline projects.

So kind of through 2017, in capital spending, it gets you to about $900 million of EBITDA.

That's helpful.

Maybe at some point, just color on the types, how much is pipeline, how much is storage, how much is rail or fuel marketing distribution, to at least better highlight the dropdown values given the assets have some different multiples on them.

Evan, we can sure do that.

I mean, obviously, in this case the bulk of this is logistics assets.

The numbers that Rich is quoting doesn't include anything that would be associated with the fuels marketing business.

Thanks again and good results.

Thank you.

Our next question comes from Roger Read from Wells Fargo.

Good morning.

Morning.

Morning, Roger.

Just maybe hit a couple questions here.

You've done a fairly phenomenal job the last several quarters of outperforming volume expectations, particularly in the Gulf Coast.

Clearly from guidance here you're expecting decent amount of turnarounds in the first quarter.

But could you just sort of give us a -- is it strictly market conditions or have there been other things that have allowed you to outperform volume expectations?

And I'm thinking you made comments earlier about the hydrocrackers having run very well in the fourth quarter.

Just walk us through that, maybe how that could imply stronger results in the first half of the year?

Yes, Roger, our performance, when we give guidance, it's based on what we plan.

We plan conservatively.

If the market provides opportunity -- and we're constantly seeking opportunity.

As crude prices or as product prices change, we try to optimize.

And if we have the opportunity to go after extra barrels, we'll do it, and that's kind of what you've seen the last -- that's probably what you're talking about here.

That's a fact.

And then I would tell you that the fact that we have invested capital in the business, the way we have invested it over the last several years, and our commitment to continuing to maintain the high levels of reliability and safety within our refining system, is going to contribute to this.

I think what you're beginning to see here is a realization of the value of the investments that have been made and then the capabilities of this Management team to execute, to optimize the [slates] in, the movement of products out and then the day-to-day operations of the refineries.

Okay.

That's helpful.

And then coming back on the other side of that, the comment earlier about distillate exports not exactly being incentivized in this environment.

There's all kinds of seasonal factors and other things going on.

But are you seeing anything particularly different on just general volume demand sides here in the US?

We have seen decent data, although obviously somewhat -- we have to be skeptical exactly what we see out of the EIA and API on a weekly basis.

Looks like gasoline demand is better here, and how maybe that's flowing through, both in terms of the export market demand-wise, not just arbitrage-wise, and then local demand as well.

Yes, Roger, I would tell you that we have definitely, since the flat prices have fallen off, we see greater demand for refined products on the gasoline and distillate side.

That's some of the reason why the Gulf has been supported, and when the Gulf is supported, then we might not see quite the incentive to export that we do.

I would tell, we're still sending distillate to South America.

So we still see good export demand.

Not necessarily quite the demand in Europe.

And some of the reason for that is just they've had mild weather in Europe, so distillate demand is down there.

And just a last question.

The North Atlantic margins, if you were to -- I know you don't like to do this, but if you were to break down sort of how Pembroke performed versus how Canada performed, was there an unusual item?

Both units were better, one was better than the other, justify any granularity you can offer there?

You prefaced the question by the fact that we weren't going to answer it.

We appreciate you doing that.

I mean, both refineries are performing well, and obviously our Canadian operations, it's a very strong operation.

But beyond that, I don't think we want to try to get into that detail.

All right.

Had to be worth a try anyway.

Roger, I'll give you credit for that.

Thank you.

Thank you.

See you.

The next question comes from Doug Leggate from Bank of America.

Good morning, it's Jason Smith on for Doug.

Hello, Jason.

Just to follow up on refining projects and being a bit more selective, can you just update us as to where the Benicia loading facility is, first in the [primmer] process and then is there incentive on your end to continue moving forward given the recent narrowing in spreads?

This is Lane.

We are still working with the city to try to address all the comments that came out that we had when we submitted the ERR for review, and so we're in the process with their folks to continue to push this forward.

We're still pretty optimistic we'll get the permit.

Timing at this point is a little bit difficult for us to project.

I'd say sometime early next year would be when we would actually get started putting the crude by rail project in place.

And I'll let Gary speak to the economics of crude by rail right now.

Yes, so I would say definitely over the last few weeks of where the Brent TIR was, we wouldn't be incentivized to move crude by rail to Benicia.

We're starting to see that arc widen back out, and our view is that we'll see a wider Brent TI than what we've seen over the last few weeks.

And we believe that we'll have an economic incentive to move the crude to Benicia.

Is there anything in your 2015 or 2016 budget for that project at this time or is there anything else in your budget for 2015 or 2016 that could potentially get cut beyond the methanol project that you guys, obviously, are slowing down on?

This is Lane again.

There is money budgeted in the 2015 budget for crude by rail.

And then slowing down?

Clearly that will mean that we'll slow that spend down versus the budget is what we at least perceive it right now.

Got it.

Okay.

And just one quick follow-up on the splitter projects?

I think you guys talked about $500 of EBITDA in a 2014 environment.

Can you just frame what those look like in the current environment?

You're talking about the crude toppers projects?

Yes.

This is Lane again.

What I would do is refer you to our investment or our slides.

We have sensitivity, so, again, you're right, the $500 million EBITDA is based on 2014 prices.

And the very next page, right in there, we have a full set of sensitivities and drivers that affect the economics of that project.

Okay.

Thanks, appreciate it.

The next question comes from Sam Margolin from Cowen and Company.

Good morning.

Good morning.

Back to the capture rate question, I guess in light of the outperformance and some of the comments you made in general about crude oversupply.

I was wondering if you could give us some color on some crude prices that maybe aren't necessarily on the benchmark that we can't see every day.

You mentioned the South American barrels, but I was also wondering about some domestic areas, so that's Houston, and South Texas, and maybe even the Bakken wellhead where you have some rail exposure, too, if there's some contribution for pricing there at discounts below what we see on the boards?

It's difficult to get into a lot of detail, but we continue to see that if you look at an LLS-related market in terms of the Eastern Gulf, the Houston market is discounted a couple dollars below that.

And then you move further west and you get into the Corpus Christi area market.

And again we see another couple dollars of discount off LLS for an Eagle Ford-type barrel.

The same thing as you move up into the Mid-Continent, the discounts get deeper as you move up on the light sweet side.

On the heavy sour side, definitely we're seeing some incentive to run a lot of these South American barrels.

The biggest switch, without going into a lot of details on discounts, as the Canadian differentials came in, we started to see an advantage to switch to more Brazilian grades and less Canadian grades, and that's an optimization we do every day.

And switching gears to the dropdown commentary.

So the MLP space has obviously been really volatile; VOP has outperformed.

I'm wondering if there's any consideration or any effect on evaluation of dropdowns in general?

There was a question before about the valuation spectrum between types of midstream assets, but I'm wondering as a complex if there's been any impact, or if it's simple -- as long as VLP is over 10 times EBITDA, the dropdown values can stay at 10 times EBITDA and there's no real problem?

We haven't seen any change in the dropdown multiples of the deals that have been occurring here recently.

There's still roughly 12% pretax for VLP and -- (inaudible).

Okay.

Great.

Thank you so much.

The next question comes from Mohit Bhardwaj from Citigroup.

Yes, hi, thanks for taking my question.

The question is on ethanol.

If you could just talk about the ethanol markets in 2015.

Obviously in 2014, ethanol was a big support and you guys made like $700 million to $800 million in operating margins and going to 2015 and then it looks like the corn prices have kind of held up, and the oil prices are coming down, based on blending economics.

Can you just talk about that?

Sure.

This is Martin Parrish.

Ethanol margins are likely to remain low in a $50 crude environment, and we don't know how long crude's going to stay at these prices, obviously.

What we do know is we have the best assets in the ethanol industry in the US and we're in advantaged locations.

We know we're not the marginal producer.

We expect to weather this fine.

Great.

And the market, do you expect to be in the positive territory or do you think (inaudible) negative markets in that?

I think it's going to chop around some, but we think overall we'll be positive with our fleet.

And it's positive today.

Yes.

Okay.

And you mentioned crude barrels to California.

I was wondering, is running at (inaudible) plus.

Have Port Arthur and St.

Charles been utilizing the rail site, or are you looking at getting heavy sours from Latin America?

Your question is -- can you restate your question?

Yes, I was just wondering if economics or crude by rail into Port Arthur and St.

Charles for heavy Canadian are still working out or is it more profitable to just look for opportunities for Latin American heavy metals right now?

Yes, so I would tell you today, the barrels that we're bringing to Port Arthur with today's economics would be breakeven versus a Maya alternative with where the market is today.

And one final one from me.

Just looking at California, there are competitors of yours who talk about California models improving for them, and your California remains the only place where the market is (inaudible) for you guys.

Are there opportunities that you see to improve margins there?

To improve margins in California.

So this is Lane.

The only project that we are working on really besides our ongoing optimization efforts and maybe real small things is the crude by rail.

We believe in the optionality to source crude from the Mid-Continent ultimately.

But because our view is the West Coast is a very challenged environment, we are very careful and very disciplined in how we approach capital into the West Coast versus all of our opportunities we have elsewhere in our operations.

Thanks for your comments.

The next question comes from Ed Westlake from Credit Suisse.

Hey, good morning and congratulations on the earnings.

I guess last year we were talking about LLS and this year we're talking about all-around good performance in margin capture, so well done.

One of the opening comments you made was it was attributable to great performance from the hydrocrackers?

Obviously oil has fallen further and that's just sort of a swirl.

And you obviously mentioned that diesel demand is a bit weaker, partly due to weather.

Presumably some of that will give back, although, obviously take the point that the crude market part of it could still be an area of positive surprise?

Just some thoughts there.

This is Lane Riggs.

We have a pretty good slide in our IR presentation on how these hydrocrackers perform and sensitivities around it.

So you have a basic set of economics on the 2014 price set.

With that said, yes, oil prices have fallen, and the distillate crack is where it is, but natural gas prices have fallen as well.

So I think when you look at it, and you look at these drivers, you need to take all that into consideration.

Today we still have very good margins on these hydrocrackers.

Good.

Was there any wholesale benefit, off the, I guess racks in 4Q as crude fell?

Yes, we did see a benefit on the wholesale side.

The rack prices tend to lag a little bit.

We had very good rack margins through the fourth quarter.

Is there a way to quantify in dollar millions, just obviously trying to get to a sense of a more steady-state level of earnings.

I appreciate there's lots of volatility in the fourth quarter and still today.

I don't have those numbers.

Right.

Okay.

Or any volumes of wholesale products which perhaps where the mar -- because there's stuff which you can sell over the rack where the wholesale margin may not have expanded as much, and then there are other parts of the US, I'm thinking, some of these states which don't have refining, where you'd imagine there would be a greater sensitivity to wholesale.

I mean, any sort of overall number for production that is sold in rack prices, which surprised to the positive?

Well, I mean, our wholesale business really consists of, I would say, several different types of businesses.

We've got the branded wholesale business; we've got the unbranded contract business.

We've got our national accounts business, and then we've got our spot wholesale business.

And all that is volume that's moved across the rack.

You know, Ed, I mean, we don't have a problem talking about it, but quite honestly, the income associated with the wholesale business is embedded right now in the way we report our refinery operations and the volume and the margins on the wholesale business are so much smaller than we would have if you look at the refining margin, that it hasn't made sense to break it out before.

And it also tends to vary so much.

So I would tell you, if you want, we can talk about it offline, but I don't think it's going to have a material impact to your forecasting going forward.

Good, I was just trying to check, when you have surprises like this, you're trying to work out where they came from.

Sure.

I understand.

But I would tell you that it was a good quarter for wholesale, but it wasn't something that materially affected the numbers that we reported.

Okay.

Very helpful.

And then just a pet theory of mine.

We're all driving F150s to Disney World this summer.

I'm driving from New York, it's a long way.

I might even take the F350 on the road.

That's a boy.

Six tires.

Use a credit card, okay.

Okay.

That's what I'm saying.

How do you think the industry is going to be prepared to make the summer grade gasoline, given that we probably haven't had this type of market for some time.

Give us color on any constraints that you see in making summer grade gasoline -- or not, just a view.

I don't see anything where I would tell you that we will have any constraints on being able to produce the gasoline for the summertime market.

Okay.

So it should just be a normal seasonal trade as we switch out from winter to summer, but nothing exceptional in your view?

Yes.

Okay.

Great.

Very helpful.

Thanks very much for your time.

Look forward to seeing you soon.

Our next question comes from Neil Mehta from Goldman Sachs.

Joe, just as a follow-up from a conversation a couple months ago, obviously Brent PI is tighter.

So we're inside this export arbitrage, but for now in 2015 the politics in Washington are a little bit different.

I wanted to get your temperature on the discussion around the crude export ban and what discussions in Washington feel like around that right now?

Okay.

That's a good question.

I mean, we maintain our position that we're totally supportive of free and open markets.

If the crude export ban were lifted, we believe that Congress is going to address this and needs to address this and the other issues associated with this as well, such as the Jones Act across border pipelines in the RFS.

That's been our position, and I think that we continue to believe that.

It's hard to pick one particular issue and focus attention on that without looking at the overall energy policy that we have here in the US in aggregate.

So we talk to our government relations guys all the time.

We know that there is a lot of conversation taking place around crude oil exports.

But we're not seeing it being promoted in any kind of material way at this point in time.

Now, if you go to the practical side of this, we're still importers of crude in the United States.

We import significant volumes, probably still 4 1/2, 5 million barrels per day.

And that's not from Canada.

There's additional volumes that come in from Canada.

You've got crude being brought into the country.

You've got a market right now that is putting downward pressure on crude prices, and you ultimately will get to who's got the lowest cost to produce to determine who's going to be continuing to produce and provide the supply.

So, I honestly am not sure where you would see domestically produced crude being exported to today as it's trying to find its way into refining capacity globally.

So issues flare up and then they tend to calm down a little bit.

This one is still getting some conversation.

I don't think our perspective has changed from what we've talked about historically.

That's very helpful.

The other question is around Brent WPI just separately.

You made the comment that you think that has the potential to widen out here over the next couple of months.

What's driven the widening over the last couple of weeks?

What do you guys see in Cushing happening?

And then as you think about where that widening could occur, is it on the PILS piece of the equation or is it Brent LLS?

So I would say the thing that's driven the Brent TI to widen is if you look at the DOE stats over the last two weeks.

We've had two very large crude builds.

So it starts to tell you that as the Saudis start forcing more medium sour barrels into the market, it displaces some of this light sweet and then we begin to build light sweet.

And as inventories build, then it means we need a wider Brent TIR in order to start incentivizing refiners to take that light barrel back into the market.

So I think that's what's happened.

I think it will get wider to the point where we are incentivized to go back to a light sweet.

And I would tell you that I would expect that the Brent TI to be a little bit wider.

And part of that is also due to the fact that we're building all this inventory in Cushing.

And so maybe the Brent TI, a little bit wider than the LLS to Brent spread.

Perfect, thank you very much.

The next question comes from Chi Chow from Tudor, Pickering & Holt.

Just a couple of follow-ups here.

We know how to pronounce your name.

I figured that.

I've heard it all.

I guess this is really a question for the second half of the year.

With the Line 9 reversal, what sort of volumes do you have committed on that line?

And what types of crudes are you expecting to move on, is it Bakken or syncrude or some other Canadian barrel?

I don't think we've talked about what our line commitment is.

What we've said is when Line 9 comes up, we'll be able to completely supply the Quebec refinery with North American domestic barrels.

In terms of the quality of crude, we would expect to ship about 50% of the volume we ship would be a synthetic-type barrel and the other a mix of other Canadian light sweet and Bakken.

And do those crudes, when you bring them in, is it going to change the yield at all or is it going to increase the profitability from a product standpoint on yields or volumes?

So what we would say is with the change in diet, the crudes that we anticipate getting off Line 9 tend to be a higher distillate yield crude.

We do show that they have a margin advantage as long as distillate is over gasoline compared to some of the West African grades that we run today, which tend to be a higher gasoline yield crude.

Okay.

Great, thanks, that's helpful.

A couple questions for Mike.

You have got a couple debt maturities this year.

What's the timing of those?

And secondly, how do you think about a minimum cash balance that you're comfortable operating at?

The timings, there's [400] is due next week, I believe it is, and then we have [75] that's a couple months later.

It's on the timing.

And what was the second question?

Just how you think about a minimum cash balance.

What sort of minimum wells are you comfortable operating at?

Okay.

We really don't have a minimum cash balance identified, but when you look at our operations, I think we're comfortable in the range of around $2 billion.

Okay.

Great.

Thanks a lot.

Take care, Chi.

Thanks Joe.

At this moment, we show no further questions.

I would like to turn the meeting over to you for any closing remarks.

Okay.

Thank you, Hilda.

We appreciate everyone calling in and those listening today.

If you have any additional questions, please contact our IR department.

Thank you very much.

Ladies and gentlemen, this concludes today's conference.

We thank you for participating.

You may now disconnect.