瓦萊羅能源 (VLO) 2015 Q4 法說會逐字稿

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

My name is Yolanda, and I will be your operator for today's call.

(Operator Instructions)

Please note that this conference is being recorded.

It's now my pleasure to turn the call over to Mr. John Locke.

You may begin.

Good morning and welcome to Valero Energy Corporation's fourth quarter 2015 earnings conference call.

With me today are Joe Gorder, our Chairman, President, and Chief Executive Officer; Mike Ciskowski, our Executive Vice President and CFO; Lane Riggs, our Executive Vice President of Refining Operations and Engineering; Jay Browning, our Executive Vice President and General Counsel; and several other members of Valero's senior management team.

If you have not received the earnings release and would like a copy, you can find one on our website at valero.com.

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

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

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

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

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

Now I will turn the call over to Joe for a few opening remarks.

Thanks, John, and good morning, everyone.

The fourth quarter and full-year 2015 were really great for Valero.

We operated safely and reliably, achieving our lowest ever employee injury rate in refining and reaching an annual average refinery utilization rate of 95%.

The markets were favorable during the quarter.

Domestic product demand grew supported by lower pump prices and sour crudes discounts relative to Brent were refractive to our highly complex refining system.

While distillate margins were pressured during unseasonably warm weather in North America and Europe, distillate demand in Latin America remained robust.

In fact, we exported record volumes of distillate and gasoline in the fourth quarter.

We continue to execute well in our projects.

In the quarter, we successfully commissioned the new Corpus Christi crude unit, the Port Arthur (inaudible) hydrocracker expansion, and the McKee crude unit expansion.

Our Quebec City refinery also began receiving crude via Enbridge's Line 9B.

We exercised our option with [Plains] All-American to acquire a 50% interest in the Diamond crude oil pipeline project.

Once completed, this project will connect Cushing with Memphis and provide us with crude optionality and long-term cost savings versus sourcing crude oil from St.

James.

Additionally, Valero Energy partners continues to execute its growth strategy and Valero GPs interest in VLP reached a high split with the distribution increase we announced earlier this week.

We also continued to advance our refining growth strategy.

Construction of the Houston crude unit remains on schedule with startup planned in the second quarter of 2016, and earlier this month our Board of Directors approved a Houston alkylation project.

This project is estimated to cost $300 million and is expected to be completed in the first half of 2019.

Finally, regarding cash returns to stockholders, we put out 80% of our 2015 adjusted net income, exceeding the 75% annual payout target, further demonstrating our belief in Valero's earnings potential.

Last week our Board of Directors approved a 20% increase in the regular quarterly dividend of $0.60 per share, or $2.40, annually.

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

Okay.

Thank you, Joe.

(Technical difficulty), we reported fourth quarter 2015 adjusted net income from continuing operations of $862 million, or $1.79 per share, versus $952 million or $1.83 per share for the fourth quarter of 2014.

Actual net income from continuing operations was $298 million or $0.62 per share, which compares to $1.2 billion or $2.22 per share in the fourth quarter of 2014.

Please refer to the reconciliations of actual to adjusted amounts as shown in the financial tables that accompany our release.

For 2015, we reported adjusted net income from continuing operations of $4.6 billion, or $9.24 per share, compared to $3.5 billion or $6.68 per share for 2014.

Actual net income from continuing operations was $4 billion or $7.99 per share in 2015 versus $3.7 billion or $6.97 per share in 2014.

Fourth quarter 2015 refining segment adjusted operating income of $1.5 billion was in line with the fourth quarter of 2014.

Stronger gasoline and other product margins combined with higher refining throughput volumes were offset by lower distillate and petrochemical margins and lower discounts for sweet crude oils relative to Brent crude oil.

Refining throughput volumes averaged 2.9 million barrels per day, which was 34,000 per day higher than the fourth quarter of 2014.

Our refineries operated at 97% throughput capacity utilization in the fourth quarter of 2015.

Refining cash operating expenses of $3.47 per barrel were $0.29 per barrel lower than the fourth quarter of 2014, largely driven by favorable property tax settlements and reserve adjustments and lower energy costs.

The ethanol segment generated $37 million of adjusted operating income in the fourth quarter of 2015 versus $154 million in the fourth quarter of 2014 due primarily to lower gross margin per gallon driven by a decline in ethanol prices versus relatively stable corn prices.

For the fourth quarter of 2015, general and administrative expenses, excluding corporate depreciation, were $206 million and net interest expense was $107 million.

Depreciation and amortization expense was $494 million and the effective tax rate was 28% in the fourth quarter of 2015.

The effective tax rate was lower than expected due primarily to a reduction in the statutory tax rate in the United Kingdom and the settlement of income tax audits in the United States.

With respect to our balance sheet at quarter end, total debt was $7.4 billion and cash and temporary cash investments were $4.1 billion, of which $81 million was held by VLP.

Valero's debt-to-capitalization ratio net of $2 billion in cash was 20% at $5.6 billion of available liquidity, excluding cash.

Cash flows in the fourth quarter included $732 million of capital investments of which $164 million were for turnarounds and catalysts and $136 million was for our investment in the Diamond Pipeline.

For 2015, capital investment included $1.4 billion for stay-in-business and $1 billion for growth.

We returned $1 billion in cash to our stockholders in the fourth quarter, which include $240 million in dividend payments and $767 million for the purchase of 11.1 million shares of Valero common stock.

For 2015, we purchased 44.9 million shares for $2.8 billion.

For 2016, we maintain our guidance of $2.6 billion for capital investments, including turnarounds, catalysts, joint venture, and strategic investments catalyst, joint venture, and strategic investments.

This consists of approximately $1.6 billion for stay-in business and $1 billion for growth.

For modeling our first quarter operations, we expect throughput volumes in the following ranges: US Gulf Coast at 1.61 million to 1.66 million barrels per day; US Mid-Continent at 430,000 to 450,000 barrels a day; US West Coast at 245,000 to 265,000 barrels per day; and North Atlantic at 465,000 to 485,000 barrels per day.

We expect refining cash operating expenses in the first quarter to be approximately $3.85 per barrel.

Our ethanol segment is expected to produce a total of 3.8 million gallons per day in the first quarter.

Operating expenses should average $0.37 per gallon, which includes $0.05 per gallon or non cash costs such as depreciation and amortization.

We expect G&A expenses, excluding corporate depreciation, for the first quarter to be around $175 million and net interest expense should be about $110 million.

Total depreciation and amortization expense should be approximately $470 million, and our effective tax rate is expected to be around 32%.

That concludes our opening remarks.

Now, before we open the call to questions we again respectfully request that callers adhere to our protocol of limiting each turn in the Q& A to two questions.

This will help us ensure that other callers have time to ask their questions, which are also important.

If you have more than two questions, please rejoin the queue if time permits.

(Operator Instructions)

Blake Fernandez from Howard Weil.

Just a quick question on the alkylation unit.

First, can you provide any kind of return expectations that you have for the project?

Secondly, on the spending profile, it looks like your CapEx guidance into 2016 is about the same as it was before.

I'm just kind of confirming that most of the spending probably is weighted toward 2017 and 2018?

Blake, this is Lane.

The Board approved the alkylation unit, normally about $300 million.

The funding [submitted] in EBITDA is about $105 million.

If we use 2015 prices, it would be about $140 million EBITDA.

With respect to the budget, when you look at our original -- when we gave out the 2016 guidance on our budget for this year two years ago, it is up about $100 million and it is nominally the Port Arthur turnaround.

We have a little more turnaround than our outlook was two years ago.

Certainly -- and then all the rest of it, the alky is clearly fitting inside our $100 million a year strategic capital.

If not -- it's normally about $100 million a year and it is back weighted, like you said, towards 2017 and 2018.

Okay.

Thanks, Lane.

Secondly, if you don't mind sharing some thoughts around light heavy spreads into 2016, and I guess what I'm thinking, especially in light of Iranian barrels coming to market that could potentially displace some other barrels globally, it seems like maybe that would have an indirect benefit to Valero given your leverage to Gulf Coast and heavy processing?

Blake, this is Gary Simmons.

Overall, we have seen some very good spreads between the medium sours and light and heavy sours as well.

Certainly the Iranian production coming online will put further pressure on those differentials.

I think we see several things in the market.

The increase in OPEC production is putting medium sour barrels into the Gulf.

You see Gulf of Mexico Deepwater medium sour production rising.

At the same time, we're seeing some of the light sweet production falling off here in the United States which is leading to very good differentials.

I think the other thing that a fundamental shift is where fuel oil had been trading around 80% of Brent, it's no trading around 60% of Brent which should mean that we would expect to see good medium sour and heavy sour differentials throughout the year.

I think the other thing for us, the Iranian production of course we won't be running any of those barrels but we do think the market rebalances and makes some additional heavy and medium grades available to us from Latin America.

Great.

Thanks for the color, Gary.

Appreciate it, guys.

Neil Mehta from Goldman Sachs.

Joe, Lane, and Gary, you guys have a unique window into what's happening from a product demand perspective.

It's one of the big debates in the oil markets right now.

Can you talk about what the export markets look like from your perspective for diesel and gasoline?

And then to piggyback off of that, we've seen four weeks now of these gasoline builds in the DOEs.

Is that consistent with what you are seeing on the ground?

Neil, this is Gary.

I think we continue to see very good export demand for our products.

As Joe mentioned, we had record volumes in the fourth quarter.

We continue to see good demand for both distillate and gasoline abroad.

Our rack volumes remain very strong.

We're moving a lot of product over the racks.

We've seen good domestic demand for our product as well.

Certainly, I think when you get this early in the year its kind of hard to dissect the DOE data.

We've seen the large builds as well.

Some of the data to us looks a little suspect.

I think we've seen a lot of weather issues in the Gulf.

Our belief may have been that it hindered some of the waterborne barrels from being able to leave due to fog and weather that we've had in the Gulf.

The Mississippi River flooding also has hindered some of the refineries along the river, their ability to clear those barrels as well.

I think we're just too early to really get a good view of what demand is going to look like, but everything from our perspective looks good.

Yes.

The fundamentals for strong demand are still there, there's no question about that.

We continue to have prices that are very attractive at the street, and then there is a lot of data that's coming out recently on vehicle miles traveled being up and also on auto sales being skewed towards larger SUVs and light heavy trucks.

Again, as Gary said, it seems like every January, Neil, we find ourselves in a situation where we're looking at the year and everybody's trying to figure out, gee, is this over and is demand going to be totally eroded?

And as he said, I think it's just a little early to tell.

Fundamentally, it looks like things should go well for us going forward.

I appreciate that.

The second question, Joe, to you is just the outlook for M&A.

I think in the past you've said that you want to see that relative multiple between Valero and the group move a little bit higher before you'd be more aggressive around M&A.

Just your latest thoughts there and also at the parent level and then also at the midstream level?

Okay.

Neil, you know we gave Cisko the responsibility for this M&A activity, which he greatly appreciated the added responsibility.

I'll give him a crack at this to start.

Thanks, Joe.

I appreciate it.

For Valero, our appetite for midstream M&A and M&A in general hasn't changed.

We continue to look at opportunities, particularly those that support the earnings growth we can achieve in our core business.

The good news is we have a great portfolio and significant earnings capability as we demonstrated in 2015.

More specific to VLP, VLP hasn't reached a size where it can execute most of the M&A transactions on its own, but we do continue to evaluate opportunities there as well.

As we said before, we remain committed to VLP's drop-down growth strategy, and we are not interested in a step out transaction that would change VLP's risk profile or it's growth story.

Appreciate that.

Thank you.

Ed Westlake from Credit Suisse.

Congrats.

I think this time last year I said I was going to drive down in an F350 to Disney World and would there be enough gasoline yield from Valero and the other refiners in the summer to make it possible for me to do so.

I'm going to ask the same question after a year of looking at gasoline markets and some very strong cracks and strong demand.

What are you guys doing to be able to make more summer grade gasoline?

In the short run, I don't think we really have anything on the horizon that's going to be able to increase our gasoline yield.

The big thing is the alky project that Lane mentioned.

That will give us additional ability in terms of making additional gasoline when that project comes online.

We are in maximum gasoline mode now though.

It's a new system, aren't we?

That's right, yes we are.

Okay.

And then switching to the self-help, obviously the [top] is coming on stream.

We started to see that maybe in 4Q and into this year.

You used to have sort of a $500 million number.

I think that's gone down to $430 million.

Just a reminder of what you think the key drivers will be in terms of the spreads driving that $430 million?

This is Lane.

The funding decision on both those units we had Brent and LLS at parity, so you're pretty much in that environment.

We like to reference the historical price set.

If you look at those projects, in 2015 the Corpus unit would give us about $200 million of EBITDA and the Houston crude unit would be about $230 million.

It is slightly exceeding obviously our funding decision, but in the current market we're pretty much at our funding decision.

Again, as Joe alluded to, the Houston crude unit will start up in the second quarter and we started up the crude unit in Corpus Christi without any incident and started up fine.

Okay.

And it's mainly crude against [VGO] spreads we should look at?

That's right, the driver here is crude versus really resid, so low sulfur resids.

Okay.

Helpful.

Thank you.

Evan Calio from Morgan Stanley.

A follow-on to the product demand question.

Given the macro uncertainty, pacing your cash, returns to the net income make sense on a on a quarterly basis yet how do you think about using the balance sheet to fund cash returns, buyback?

Has that changed at all given macro uncertainty or share price volatility?

Our balance sheet is -- Evan, this is Mike.

Our balance sheet is very, very strong.

We intend to keep it that way.

Our guidance is to pay out 75% of net income for 2016.

So, as far as levering up to meet that target, I'm not sure we will be required to do that.

It's early in the year, so we will just have to see how the year plays out.

Got it.

Then maybe a different followup.

You shared the EBITDA on all these new projects that will be contributing in 2016 in Corpus, Port Arthur, McKee, and Houston in 1Q.

Any color in aggregate how they affect your crude slate flexibility or just related -- given the right economic indicators, where do you think you could max out your heavy sour and the medium sour runs?

The topper really just gave us more capability to run domestic light sweet barrels or foreign light sweet barrels.

It really added to that.

We haven't done anything that really materially changes our ability to process medium or heavy sour grades in our system.

It is mainly of those two units are adding, what, 160,000 barrels a day of light sweet capacity.

Right, but the uptick quarter to quarter on overall heavy and medium sour runs, where could that be?

And I'm sure that's an average number, so I'm just trying to get a sense of if you are kind of max flexed at this point or where we take that?

A little color on that, Evan.

I will take the topper out so you can kind of have an apples to apples comparison.

If we take the toppers out, between last quarter and where we are today, we backed out about 400,000 barrels a day of lower 48 domestic light sweet crude and we've replaced that with medium sour grades and foreign light sweet imports.

That the big change in our system; heavy sours are about the same.

Got it.

Appreciate it.

Paul Cheng from Barclays.

Mike, this is for you.

I'm going to ask from the other angle on the balance sheet.

The last several years that you guys have done phenomenally well both operationally and financially and also the return to shareholder.

Just curious that as the cash flow remains strong at this point, does it make sense even though you already have a very strong balance sheet to maybe utilize part of the free cash flow, maybe 20% or so, to further strengthen the balance sheet?

I think that we all lived through the ups and downs.

While I'm bullish on the market, I could be wrong.

We have seen what happened.

Everyone was bullish in 2007 and then the bottom fell off because of the economy.

So should we actually take maybe a slightly different view at this point just as a safeguard to ensure that we build up some additional cushion even though your balance sheet is already remarkably strong but your cash flow cut by half then?

Maybe that will allow you even to have a better opportunity to strike and take the opportunity when everyone is weak?

That is quite a question, Paul.

I remember those days very well.

Our balance sheet is very strong and we intend to keep it that way.

If you're suggesting that we build cash here, our current focus is to continue to look for opportunities to grow our business and increase our earnings per share.

If you're suggesting that we prepay some debt, the majority of our remaining debt contains make-whole provisions that made those prepayments less than compelling.

I see.

So, you won't be able to prepay and you won't add on some additional cushion into your balance sheet by adding cash?

No.

I don't think at this time that's what we will be doing.

I think we think we can execute on our payout strategy and all that type stuff, as I said earlier, without levering up the balance sheet.

Joe, just curious.

With I think some of the other companies in distress and looks like some retail assets maybe become cheaper, if you're looking at your portfolio, does it make sense that the entry point is right for you to re-enter into retail?

By doing so that can -- maybe that can cushion your gains or any win cost increase or that you provide even more direct outlet to your own [refine portal] (inaudible) into that business?

Paul, that's a good question.

We look at it periodically.

The retail business is materially different from the refining business and you know that.

Refining is capital-intensive and pure people and the retail businesses is people intensive.

When we look at it, I think our view would generally be that we don't need to control the retail outlet to be able to be a very good supplier into that market.

So, frankly, what we're focused on is further extending our wholesale business where we could have contractual relationships and support the Valero brand at the street from the wholesale side rather than from a direct retail operation.

If you reflect back on our retail volumes when we owned CST in the 1000 or so sites and the sites in Canada, the volume we moved through them was about 125,000 barrels a day.

When you look at that as its order of magnitude relative to the total motor fuels that Valero is producing, it's a very small percentage.

It would take a real huge step for us to have any kind of material presence to really allow us to hedge the benefits associated with owning retail directly.

I don't know that unless there was really something that was incredibly good that allowed us to sustain our contractual relationships with customers, I don't see us reentering that market in the retail business.

Thank you.

Jeff Dietert from Simmons & Company.

It's Jeff Dietert with Simmons.

Good morning.

I appreciate the update on all of the projects.

I think the St.

Charles hydrocracker, I didn't see an update on that.

I apologize if I missed it.

Could you talk about St.

Charles?

This is Lane.

We are currently changing the catalyst out and doing the capital -- it's a small capital project, $40 million.

It's just really a catalyst change out which is based on the cycle when we change out the catalyst and the capital implementation and we're doing at right now.

So, it will be ready to go here in the second quarter.

Okay.

Could you talk about your EBITDA expectations on Port Arthur and St.

Charles hydrocrackers, what those are expected to contribute?

We spend normally about $80 million on the two and sort of our funding decision EBITDA is somewhere between a total of $60 million to $80 million.

So these are examples that are sort of quick hitting, self help.

These are the low-hanging fruit that sort of arbitrage out that after we start running these units to figure out where can put a little capital in and get a pretty good hit on it.

I don't know if that will show up as a revenue stream or something like that to you guys but it will certainly show up in our margin capture going forward.

Could you talk a little bit about Line 9 now that it has started up and what your flexibility is to take Canadian heavy versus Syncrude versus Bakken?

What's the flexibility there and the environment where you're encouraged to take those grades?

This is Gary.

Line 9 we began taking crude in December.

It's fully up and operational in that capacity.

In terms of flexibility of grades, all of our crude through Line 9 goes through Montreal and we really don't have logistics to be taking heavy or medium sours.

It's pretty much just for light sweet crude for the Quebec refinery.

Great.

Thanks for your comments.

Roger Read from Wells Fargo.

I guess maybe coming back to the gasoline question for this summer.

Octane availability, as you look around, what do you think the biggest roadblock will be again?

Is it going to be octane alkylate side?

It is going to be blending stocks?

What is your assumption for gasoline demand growth this year as you set up your expectations and budget?

Roger, this is Gary.

I think we see that as long as we have a strong gasoline market and we have lengthened a sub octane blend component like naphtha, the gasoline pool is going to try to draw naphtha in and it's going to mean octane is fairly expensive.

We expect is output values fairly strong again this summer.

I don't see anything on the horizon that really leads me to believe that's going to change anytime soon.

Where will the industry look?

If you thought about it as a low-hanging fruit thing, where would you be looking to pick up octane?

One of the thoughts is if US light sweet is declining and we are importing a light barrel, maybe we create a little bit more that way since the US barrels tend to be on the low end for octane?

But where else should be consider?

Well, I think for us we try to look everywhere we can and this alky project was the best thing we really felt was out there.

We studied expanding, reforming, building new reformers and the alky project has the best return in our system.

I mean more near term are we just going to struggle 2016 and 2017?

I understand where we are in 2019, but --

I think we will.

I don't see anything in the near-term that's going to have a significant impact on the octane balance.

Okay.

Great.

Thank you.

Sam Margolin from Cowen and Company.

I wanted to ask one more about the alky project here.

There's a couple others out there in the system.

A lot of times these units, as newly built units, are paired with like a midstream acquisition or some other project to produce the feed by the operator, but is it fair to say that there is no real necessity to commit capital to source incremental NGLs here, there's plenty available and so this alky unit can be built as a standalone or actually is it paired with maybe something coming off the toppers or another attribute of your yield right now?

This is Lane.

Ours is a little bit different than other people in the industry.

What we're doing is taking an existing alkylation unit in Houston and we're converting it to alkylate C5 olefins.

Normally alkylation units alkylate C4 olefins and sometimes C3 olefins.

So, we're taking the existing one and retrofit it such that it could alkylate C5 olefins and we're building new C4 olefins.

What we're really doing, if you drew a boundary around the Houston refinery is we are shifting C5 olefins that are going out in [cat] gasoline, bringing in IC4 from Mont Belvieu, which is readily available and inexpensive, and that's really what's happening in making an alkylate and also blending some additional butane for this low RVP.

That's really what this project is.

It is different, I would say, than other people that are looking this.

We're clearly ahead of everybody else in the industry with this project.

Okay.

That makes sense.

I think it's been evaluated for quite a while.

It's clear that there's a lot of thought into the process.

This next one is sort of a moon shot.

As you know, it's been reported Aramco is maybe looking to monetize some assets.

You might also know that Shell has a fairly aggressive divestment target, too.

Is it fair to say that Motiva today is at least as attractive or as sensible of a consolidation candidate as maybe Citgo was two years ago in terms of sort of what's out there to bring into the fold to the extent that, Mike kind of alluded to, the appetite hasn't changed but maybe availability of assets has?

Sam, that is a moon shot.

Look, Motiva has a good business and they've got good assets.

If they were for sale, I suspect that we take a really good hard look at them, but we are not hearing anything.

I haven't heard anything that they are in the market.

All right.

Appreciate it.

Have a good one.

Phil Gresh from JPMorgan.

First question just on VLP.

How are you thinking about the drop-down potential to VLP this year?

Last year I think you had committed to $1 billion in drops but you didn't give any specific commentary on the release.

Just curious how you are thinking about the MLP market more broadly, evaluation impacts, et cetera?

Yes.

Phil, right now, $1 billion is our current plan for the drop-down.

The capital markets are pretty challenging right now.

We'll just have to continue to monitor this as we move through the year.

Okay.

Second question is there's been some talk about the uplift we could see from greater utilization rates from these Chinese teapot refineries and the impact it could have on product exports out of China.

I'm just wondering how you're thinking about this risk and do you think China's product quality can compete on the global market, especially on the gasoline side?

Bill, this is Gary.

I don't know that I can comment on the quality of their products.

Overall, to me that capacity is capacity that is going to be very challenged globally because of the weak fuel markets.

It's going to be very difficult to run low complexity capacity with a very low fuel oil environment.

Okay.

Thank you.

Ryan Todd from Deutsche Bank.

Good morning, gentlemen.

Maybe -- and you've said all you wanted to say on it, but maybe a quick followup on the prior question on potential drops to VLP.

Any thoughts as to what the mix might look like between cash proceeds and equity to Valero or any thoughts on evolution of multiples of those drops?

Or too much uncertainty in the market at this point?

Well, there's quite a bit of quite a bit of uncertainty in the market.

At this point in time I really can't comment on how the cash proceeds would be and how the financing of those drops would be structured.

Okay.

Then, may be one -- appreciate the comments that you made earlier in terms of some of your thoughts on medium sour and heavy sour differentials and the sustainability going forward.

Could you give any thoughts in terms of how you see light sweet diffs, whether it's Brent TI or LLS TI, evolving over the next three to six months?

Are we going to need to see a widening of those spreads in order to clear Cushing and disincentivize imports?

In particular, I was kind of curious given the fact that you backed out 400,000 barrels a day of lower 48 light sweet crude through your system, just generally how you've seen -- what your outlook is for those light sweet differentials going forward over the course of this year?

This is Gary.

I think over time LLS and Brent traded at pretty close to parity, but I think we're going to have a lot of volatility between the grades as the year goes on.

You can see LLS was -- we would perhaps pay a premium for LLS over Brent, so we started importing foreign light sweets.

You have inventory gains here in the US, which I think tells you LLS was too expensive so then LLS will be discounted.

I think we will go through that volatility for the next six months where we swing in and out of domestic light sweet production into our refining system.

Great.

Thanks.

I appreciate the help.

Doug Leggate from BofA Merrill Lynch.

Joe, I wanted to go back to your comment about gasoline.

I think you said you were in max gasoline mode right now.

What I'm trying to understand is what happens to gasoline yields as the US kind of swings back to imports on light sweet crude declines?

I know everyone is focused on octane, but I'm just wondering if we start to see a tightening of your balance (inaudible) gasoline at this point I'm guessing that's because (inaudible).

I'm just trying to understand the interplay as you see things going into the summer.

I guess I'm really looking to your prognosis on how those things balance out.

Okay.

Gary, do you want to go ahead?

Overall, if you look at a foreign light sweet barrel versus and Eagle Ford or a Bakken-type barrel, the naphtha yield from West African Saharan barrel is about the same as Bakken or Eagle Ford.

So in terms of refining yield, it's not significantly different whether we are running that West African barrel or we're running a domestic light sweet barrel.

As you swing back towards medium-heavy, does the yield mix change then?

For medium to heavy barrel it would except for most of the refineries who were running those barrels are very high complexity refining assets and again we don't see much of a yield difference with that complexity of our refineries when we are running a heavier diet.

The only thing that we can get into is as we go heavy in some of our plants it can lower utilization some.

So we got a lever effect by running light sweet in some of our refineries, so if we have a big incentive to run much heavier crude diet it can mean we are running slightly lower crude rates in some of those plants.

Kind of back to the old scale.

Thanks for that.

My followup, it's probably more as a Ciskowski question.

Mike, the tax rate looks like it's been consistently low now or becoming kind of a regular thing.

Should we be looking at tax rate guidance moving lower as a kind of permanent shift?

Well, we had a couple of unique items this past quarter because the tax law that got final approval in the UK.

And then we had -- we have some audits that are under way in the US and we happened to get those settled this quarter and so that was reflected, which pushed the rate down to 28%.

We try to do the best that we can in giving that guidance to you.

The 31%, 32% is what I would say for the first quarter.

Is that a good run rate going forward, Mike?

Yes.

Right now that would be.

Okay.

Helpful.

Thanks, everybody.

Chi Chow from Tudor, Pickering, Holt.

Back on the products markets, can you comment on how you're assessing the supply-demand balance of the global distillate market heading into this year?

We saw material weakening of the diesel cracks as the year progressed last year and just wondering your thoughts on the cause of this?

Chi, this is Gary Simmons.

Overall, if you look at what drives distillate demand, it's weather and then it's economic activity and thus far both in the US and in northwest Europe we've had warmer winters than what we've historically had and so it's led to lower distillate demand.

In terms of how do we correct from there, I think a lot of that correction gets back to some of this low complexity refining capacity.

With discounted fuel oil pricing, I think will see some economic run cuts and some of that low complexity capacity that will bring the distillate market back into balance.

What about the economic activity side of things?

Are you seeing -- you mentioned your exports are still pretty good but are you concerned about global slowdown on the economic front?

I don't know that I can really comment on the global economic activity, but I can say we continue to see very robust demand for our products throughout the globe.

What were your exports of gasoline and diesel in the quarter?

Gasoline, we did 157,000 barrels a day of gasoline.

We did 264,000 barrels a day of diesel.

If you add kerosene in with that, it would be 307,000 barrels a day of total distillate.

Thanks, Gary.

One other question.

This is just kind of specific to your Gulf Coast system.

We just noticed that your realized margin captured rate versus your index is always better in the fourth quarter in the Gulf Coast than the other three quarters of the year and that's been pretty consistent the last four years running.

Why is that the case?

Is there any specific reason for that?

I would say certainly you get butane blending would come into play there.

So as butane has been discounted and we are able to blend it into the pool, it helps our capture rates.

I don't know if you have anything else.

This is Lane.

I'd only add normally seasonally what you see is medium heavy sour discounts widen out.

So, when you are using sort of the standard capture rate versus light sweet we always outperform on that as well.

Okay.

Thanks, Lane.

Appreciate it.

Faisel Khan from Citigroup.

Just a quick question.

On the timing of the projects that came online in the fourth quarter, the Corpus Christi crude unit, the hydrocracker, and the expansion of McKee and also Line 9B sort of highlighted that because that was December startup.

How did those start up in the quarter?

I'm just trying to understand what the contribution was from the commissioning of these assets in the quarter just so we get sort of the uplift right going into 2016?

This is Lane.

McKee, we finished that project which really took us about two years to fully implement the entire scope of that which was two things.

One, it was an energy efficiency project and distillate recovery and the second was for the plus crude rate and we finished it in October.

I assume that's what you're after.

You're sort of after the timing.

Yes.

Port Arthur, again the hydrocracker was down in October and then we replaced the catalyst and did the expansion.

And then Corpus Christi really started up during sort of early to mid December, so you wouldn't have seen anything with respect to fourth quarter improvement.

That's really going to be entirely a 2016 thing.

Okay.

Got it.

In McKee we would've seen a full contribution in the quarter, but it sounds like Port Arthur was down in October and then of course nothing from the Corpus.

Right.

Nothing from Corpus and obviously St.

Charles we're doing right now.

Okay.

Right now, given where crude prices are in Canada versus the Atlantic basin, does it make sense to max out Line 9B?

Where are we with the market in terms of how you benefit from that?

I would tell you on Line 9B we are seeing some value in the Bakken that we are running.

Most of it Western Canadian light sweets we're not seeing a material difference in uplift and running those barrels compared to foreign light sweets that we can import into Quebec.

Got it.

Great.

Thanks for the time.

Appreciate it.

Vikas Dwivedi from Macquarie Group.

A quick question on gasoline and ethanol.

Now, they've been inverted for a while.

Does that change how you guys blend or any of the approach to the overall gasoline operation given sort of upside down from normal?

This is Martin Parrish.

It's really the impact on the blending margin, not on the refiners margin.

Ethanol is selling at about its blend value, everything kind of at its blend value that's high octane.

You have to remember, that the blender still gets the RINs if they choose to blend ethanol, so it kind of works out.

I would say there is really no impact on (technical difficulty) gas blended.

Got it.

Coming back to the alky plant.

The C5 technology, is that also a call on kind of an oversupply to ethane or ethylene market down the road?

It's not a call, its it's just really, you look at the whole NGL market.

It's been long.

It's really a view that we can take and move NGLs into the gasoline pool and we can do it by alkylating amylenes] in the refinery, which is a little bit different.

It makes a good high-octane low RVP component which then in turn allows us to blend additional butane in the summer, in particular.

Got it.

We were just thinking if it was a call, it would be a great call.

I think we're going to be drowning in the lighter end of the NGL barrel for a long time.

I wouldn't tie it to ethane.

It's the whole NGL space, right, which we believe is [virtually] long going forward, too.

Yes.

All right.

Think you guys.

Brad Heffern from RBC Capital Markets.

Circling back to VLP, I'm just curious.

We all know the uncertainty and the turmoil in the capital markets.

It seems like the strategy is basically unchanged and you have 55% of the growth in 2016 in terms of budget going into VLP.

At what point do you think about that and maybe re-examine the pace of growth given that the market doesn't necessarily seem to be rewarding growth as much as it once was?

Yes.

We'll continue -- right now our plan is to do the $1 billion, but we'll continue to examine and monitor the markets as we move through the year.

It is very challenging right now.

We do have our revolver that we could use that as a financing source for some of the drops.

The bank market seems to be a little bit more attractive than the capital markets at this point in time.

Brad, let me just add to what Mike said though.

The capital that we're investing in logistics assets at Valero Energy are assets that can be dropped to VLP.

We'll continue to build the droppable EBITDA base, but the motivation behind it, and we shared this before, the motivation behind Valero investing in logistics assets are projects that benefit Valero's core business, it's core refining business.

There are projects to help us optimize our operations.

We're not taking flyers on projects that we wouldn't be willing to commit contractually long term to.

So, again, the things that we're investing in today, for example, the Diamond Pipeline, that is going to be a direct benefit to the Memphis refinery and provide crude optionality there that they don't currently have today.

It's a long game and even though markets are challenged right now, I don't think we should sit here and throw the baby out with the bath water and totally redirect strategies to try to accommodate it.

The other thing that Mike hasn't mentioned is that VLP is in a great position.

They have very high coverage ratios to maintain distribution growth, that the targets we talked about are not going to be an issue.

Again, we're running the business to continue to improve the business and drive EPS growth at VLO and VLP is going to go along for the ride.

Anyway, that's just a little more color.

Yes.

Thanks for that, Joe.

I think that's clear.

Thinking about logistics opportunities as well, I'm curious.

Obviously the lifting of the crude export ban is seen as negative for refiners in general.

I would think there might be some opportunity to present themselves to Valero given the amount of dock space and general footprint in the Gulf Coast?

Have you thought along those lines yet?

This is Rich Lashway.

Yes, we started up that opportunity.

We're in conversations with a lot of different parties on projects that they have that they're willing to share now that they might not have been in the past.

So, we do see quite a bit of opportunity out there given not just the decline in crude prices but also the export opportunity.

Okay.

Thank you.

Our last question is a followup question from Paul Cheng from Barclays.

Real quick.

Maybe this is for Gary.

Gary, just curious.

The crude inventory over the last several weeks quite substantial.

Do you have any rough idea what is the split between the financial buyer buying it to take advantage on the contango curve or what percentage is the operator actually the refiner then who is building inventory here?

Yes, I don't suspect it's a lot of refiners building inventory.

Most of our tankage and most refiner's tankage is more operational in nature and so it's hard to really utilize that tankage for contango play.

Most of that you see some inventory builds in Cushing, but I don't know that I really could comment in terms of the build.

I think what we had happen is LLS got at a premium to a foreign light sweet alternative and Valero, along with many other refiners, started buying light sweet.

It caused the inventory to build and certainly the market structure has incentivized people to store as well.

Okay.

Thank you.

Okay.

Yolonda, I think that was the last of the questions.

So, we want to thank everyone for calling in today.

Please feel free to call me and Karen if you guys have further follow up questions.

Thank you.

Thank you, ladies and gentlemen.

This concludes today's conference.

Thank you for participating.

You may now disconnect.