瓦萊羅能源 (VLO) 2017 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Valero Energy Corporation's Fourth Quarter 2017 Earnings Conference Call.

(Operator Instructions)

And I would now like to introduce your host for today's conference, Mr. John Locke.

Sir, you may begin.

Good morning, and welcome to Valero Energy Corporation's Fourth Quarter 2017 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 and COO; Jay Browning, our Executive Vice President and General Counsel; and several other members of Valero's senior management team.

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

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

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

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

In summary, it says that statements in the press release and on this conference call that state the company's or management's expectations or predictions of the future are forward-looking statements intended to be covered by the safe harbor provisions under federal securities laws.

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

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

Well thanks, John, and good morning, everyone.

Well, 2017 was certainly a tale of 2 halves.

In the first half of the year, we saw a gradual but steady improvement in margins from the low levels of 2016.

The return of global economic growth created strong product demand.

And on the supply side, our flexibility allowed us to optimize our system away from the OPEC supply-constrained crudes to capture more margin available on Canadian and domestic crude supply.

In fact, we processed a record 1.4 million barrels per day of light crude during the fourth quarter.

In the second half of the year, catastrophic weather-related events accelerated the decline in industry product inventories to below 5-year averages, brought national attention to the complexity and inefficiency of the U.S. fuel supply chain and renewed appreciation for the critical role that products play in the lives of families and communities.

In December, to the delight of many, our nation's lawmakers passed unprecedented tax reform.

We believe tax reform further strengthens the competitive position of the U.S. refining industry versus our global competition through greater tax efficiency and increased earnings power and cash flow generation.

We were glad to see this positive step change for American manufacturing businesses and for American families.

I'd also like to recognize Valero's tax, accounting and legal teams who dedicated significant time and effort over the recent months and during the holidays to analyze and account for the requirements of the tax reform.

Now looking ahead, we expect a significant reduction in our taxes and effective tax rate versus pretax reform levels.

And Valero's net cash provided by operating activities should also benefit significantly.

That being said, you should expect us to remain committed to our capital allocation framework, which prioritizes maintaining our investment-grade credit ratings and nondiscretionary spending to sustain the business and pay our dividends.

Incremental discretionary cash flow resulting from tax reform would need to compete with other discretionary uses including growth investments, M&A and tax returns.

Turning to Valero business.

In 2017, we set new operational performance records for safety, reliability and environmental stewardship.

Our accomplishments in these areas exemplify Valero's commitment to premier operations in our key drivers that enable us to deliver more stable earnings.

Also in 2017, we invested $2.4 billion to sustain and grow the business.

The Diamond Pipeline and the Wilmington cogeneration unit both started up in November and are running well.

The Diamond Pipeline connects Cushing to Memphis and has improved our Memphis refinery's crude supply flexibility, providing a cost advantage versus crude delivered on Capline.

The cogeneration unit is helping reduce Wilmington's operating expenses while also increasing the reliability of its power and steam supplies.

Construction on the capacity expansion of the Diamond Green Diesel plant and the new Houston alkylation unit remains on track.

We expect to complete these projects in the third quarter of 2018 and the first half of 2019, respectively.

Our logistics investments in Central Texas and along the Houston ship channel are also progressing.

Estimated start-ups are in mid-2019 for the Central Texas pipelines and terminals, and then early 2020 for the Pasadena terminal.

We also expect to break ground soon on a new 25,000 barrels per day alkylation unit at the St.

Charles refinery.

This project was recently approved by our Board of Directors.

The estimated total cost is $400 million with the start-up scheduled for the second half of 2020.

Regarding cash returns to stockholders, we paid out 63% of our 2017 adjusted net cash provided by operating activities, which exceeded our target annual payout range of 40% to 50%.

Last week, our board approved a 14% increase in the regular quarterly dividend to $0.80 per share, or $3.20 annually, further demonstrating our commitment to our investors.

In closing, with days to supply for refined light product inventories near 5-year lows and continued global economic growth, we expect good demand in domestic and export markets and healthy margins this year.

Given our advantaged position as a low-cost manufacturer and premier operator with flexibility to process a wide range of feedstocks and reliably supply quality fuels to consumers, we are optimistic about 2018.

So with that, John, I'll hand the call back to you.

Thank you, Joe.

For the fourth quarter, net income attributable to Valero stockholders was $2.4 billion, or $5.42 per share, compared to $367 million or $0.81 per share in the fourth quarter of 2016.

Fourth quarter 2017 adjusted net income attributable to Valero stockholders was $509 million or $1.16 per share.

For 2017, net income attributable to Valero stockholders was $4.1 billion or $9.16 per share compared to $2.3 billion or $4.94 per share in 2016.

2017 adjusted net income attributable to Valero stockholders was $2.2 billion or $4.96 per share compared to $1.7 billion or $3.72 per share in 2016.

The 2017 adjusted results exclude an income tax benefit of $1.9 billion from the Tax Cuts and Jobs Act of 2017, while the 2016 adjusted results exclude several items reflected in the financial tables that accompany this release.

For reconciliations of actual to adjusted amounts, please refer to those financial tables.

Operating income for the refined segments in the fourth quarter of 2017 was $982 million compared to $645 million for the fourth quarter of 2016.

Excluding $17 million of expenses primarily related to ongoing repairs at certain of our U.S. Gulf Coast refineries to address damage resulting from Hurricane Harvey, adjusted operating income for fourth quarter 2017 was $999 million.

The increase from 2016 is attributed primarily to higher gasoline and distillate margins in most regions and wider discounts for domestic sweet crudes relative to Brent crude, which were partially offset by narrower discounts for medium and heavy sour crudes versus Brent and higher premiums for residual feedstocks.

Refining throughput volumes averaged 3 million barrels per day, which was 156,000 barrels per day higher than the fourth quarter of 2016.

Throughput capacity utilization was 96% in the fourth quarter of 2017.

Refining cash operating expenses of $3.55 per barrel were $0.19 per barrel lower than the fourth quarter of 2016, mostly due to higher throughput in the fourth quarter of 2017.

The ethanol segment generated $37 million of operating income in the fourth quarter of 2017 compared to $126 million in the fourth quarter of 2016.

The decrease from 2016 was primarily due to lower margins resulting from lower ethanol prices.

Operating income for the VLP segment in the fourth quarter of 2017 was $80 million compared to $70 million in the fourth quarter of 2016.

The increase from 2016 was mainly due to contributions from the Red River pipeline, which was acquired in January 2017; and the Port Arthur terminal assets and Parkway Pipeline, which were acquired in November 2017.

For the fourth quarter of 2017, general and administrative expenses were $238 million and net interest expense was $114 million.

General and administrative expenses for 2017 were higher than 2016, mainly due to reserve adjustments and a fee for terminating the agreement to acquire certain terminals in Northern California owned by Plains All American Pipeline, L.P.

Depreciation and amortization expense was $490 million and the effective tax rate, excluding the income tax benefit related to tax reform, was 30% in the fourth quarter of 2017.

With respect to our balance sheet at quarter-end, total debt was $8.9 billion, and cash and temporary cash investments were $5.9 billion, of which $42 million was held by VLP.

Valero's debt-to-capitalization ratio, net of $2 billion in cash, was 23%.

At the end of December, we have $5 billion of available liquidity, excluding cash, of which $340 million was available for only VLP.

We generated $1.7 billion of net cash from operating activities in the fourth quarter.

Excluding the favorable impact from a working capital decrease of $800 million, cash generated was approximately $900 million.

With regard to investing activities, we made $641 million of growth and sustaining capital investments, of which $142 million was for turnarounds and catalysts.

For 2017, we invested $2.4 billion, of which $1.3 billion was for sustaining and $1.1 billion was for growth.

Our sustaining capital expenditures were $300 million lower than guidance primarily due to lower turnaround cost and hurricane-related delays on certain projects.

Moving to financing activities.

We returned $727 million to our stockholders in the fourth quarter.

$421 million was for the purchase of 5 million shares of Valero common stock and $306 million was paid as dividends.

As of December 31, we had approximately $1.2 billion of share repurchase authorization remaining.

Including the $2.5 billion of additional repurchase authority approved last week by our board, we have approximately $3.7 billion available for stock buybacks going forward.

We expect capital investments for 2018 to be $2.7 billion, with about $1.7 billion allocated to sustaining the business and $1 billion to growth.

Included in this total are the turnarounds, catalysts and joint venture investments.

For modeling our first quarter operations, we expect throughput volumes to fall to the following ranges: U.S. Gulf Coast at 1.65 million to 1.7 million barrels per day; U.S. Mid-Continent at 440,000 to 460,000 barrels per day; U.S. West Coast at 250,000 to 270,000 barrels per day; and North Atlantic at 415,000 to 435,000 barrels per day.

We expect refining cash operating expenses in the first quarter to be approximately $4 per barrel.

Our ethanol segment is expected to produce a total of 4 million gallons per day in the first quarter.

Operating expenses should average $0.38 per gallon, which includes $0.05 per gallon for noncash costs, such as depreciation and amortization.

For 2018, we expect G&A expenses, excluding corporate depreciation, to be approximately $800 million.

The annual effective tax rate is estimated at 22%.

For the first quarter, net interest expense should be about $115 million and total depreciation and amortization expense should be approximately $500 million.

And lastly, we expect RINs expense for the year to be between $750 million and $850 million.

That concludes our opening remarks.

(Operator Instructions)

(Operator Instructions) Our first question comes from the line of Roger Read with Wells Fargo.

I guess, could we talk a little bit here -- kind of 2 main things: crude diffs, which have been bouncing around quite a bit lately; and then your general access to heavy barrels, given that if I remember correctly, you don't have quite as much pipeline access to Canadian barrel, which means rail is probably beneficial for you here, and then the further declines in Venezuelan production and what that's been along the Gulf Coast for heavy access.

Roger, this is Gary.

Yes, we've seen diffs move quite a bit.

I'll start with Venezuela.

Although production has been declining in Venezuela, our volumes had remained fairly constant versus our term contracts.

We kind of attribute this to the fact that although production is declining, refinery utilization is down in Venezuela.

And so it's kind of keeping exports available to us.

On the crude diffs side, we've seen some pretty good swings, obviously, the Western Canadian market is very discounted, WCS and Hardisty this morning is $34 under Brent.

And then I think some of the turnaround activity and cold weather in the Gulf is causing medium sour market at least in the U.S. Gulf Coast to weaken some with [Aski] now trading close to 580 off of Brent.

So seeing pretty good quality discounts.

Maya doesn't seem to be quite keeping up with either the Western Canadian or the medium sour values that we're seeing in the Gulf today.

In terms of access, we have good pipeline access, really to our Houston area refineries.

Where we don't have as good a access is to St.

Charles.

St.

Charles has a lot of capability to process Canadian barrels, but we don't have a good way to get it there.

And so we are starting some barge operations from our Hartford terminal where we'll barge some heavy Canadian into St.

Charles, which will start in February.

And on the rail side, are you seeing the kind of walking from the rails in the U.S. that we've seen out of some of the Canadian rail companies, thinking of the term contracts here?

Yes.

So what we're really seeing is just there is not the availability of locomotives in order to move the train.

So real wide arb and great economics to ship Crude by Rail, but you don't have the power to move the trains.

Some of that is the trains have been in grade service.

And so we see some things that we think could open up some more movements of Crude by Rail.

We're planning to ramp up our volumes through our Lucas terminal to Port Arthur.

But so far, it's been very limited.

And our next question comes from the line of Doug Terreson with Evercore ISI.

I wanted to get your updated views on the likely market impact of some of the new environmental regulations that are set for the next few years, which seemed pretty meaningful to me, meaning between Tier 3 sulfur and IMO 2020, my question is whether you feel the U.S. and global refining industries are making adequate enough investments to satisfy the new rules?

And then second, how margins for they key products, such as the octane sources, fuel oils and crude oil spreads, are going to vary?

And finally, how Valero is positioning for these changes.

So there's really 3 parts: Is the industry ready?

Two, what happens to spreads?

And three, how you feel Valero is positioned for these new regulations?

Doug, it's Lane.

Actually, I'm going to start with your last one first.

Valero is very well positioned for certainly IMO.

We have a lot of coking capacity, a lot of resid destruction, so we have a lot of preinvestment for that regulation change.

And secondly, on that point, the interesting thing about this regulation change is it's trying to add grassroots capacity in this space with resid destruction.

It's very expensive.

So I think you'll see the industry do what it can to debottleneck existing units in terms of laying out a lot of capital for the big grassroots unit that will be -- remain to be seen, but it is expensive, as compared to some of the other process units.

With respect to Tier 3, it's in our strategic view, Tier 3 is going to destroy a lot of octane.

Where we are versus the industry, we think we're better positioned, we're are going to spend -- our total spend in this space is $470 million is where we think we are today.

Where we still got about $200 million in front of us.

We spent about -- the rest of it's behind us still, so we feel like we're in really good position with respect to Tier 3 as well.

Okay.

And you guys want to just make a couple of points on IMO 2020 or should we wait until we get closer?

Well, in terms of its likelihood or...

Well, not so much of likelihood.

I mean, it feels like it is going to happen.

But whether you think it's that meaningful and what the key market implications are?

Do you have a view there, too?

I'm sorry.

Yes.

So I started there, I think absolutely the fact that we are heavy coking refinery and resid destruction, like I said, we are very well positioned for and that regulation is going to cost 3% to get very displaced in the world.

I think everyone is trying to figure out exactly how our industry and the shipping industry is going to try to solve this issue.

But it will definitely widen, as you don't run 3% and you probably reuse fuels that are a substitute distillate, you're going to see that driver, which is a driver for coking and other resid destruction between resid and diesel widen out.

And I think that's the market impact.

Gary, you want to add anything on that?

No.

I think that's it.

And our next question comes from the line of Paul Cheng with Barclays.

Joe, maybe just wanted to clarify, when you guys saying that the adjusted operating cash flow 40% to 50%, how you define as the adjusted operating cash flow?

And also that, in the event the operating cash flow however way that you define is much better than you expected?

Should we assume the incremental cash will end up that coming to the shareholders, so you will end up that -- exit that range?

Or that it would be used for other purpose like debt reduction or maybe increasing the organic CapEx?

Paul, this is Mike.

On how do we define that, it's net cash provided by operating activities on our cash flow statement and then we back out the working capital impact.

And then the second part of the question was on assuming we have additional free cash flow, what are we going to do with it.

Right.

I mean, as Joe talked about in his opening comments, we're still going to pay out the 40% to 50% as our target.

And this increase in discretionary cash flow will just compete with the nondiscretionary.

Paul, we put in place several years ago that capital allocation framework and we have adhered to it.

And I think perhaps the best forecaster for what we're going to do going forward is our history.

We'll retain enough cash to be sure that we've got the liquidity in the business to do the things we want to do and to the extent that we end up with surplus cash, I think it's a fair bet that we're not going to sit on it.

So again, I think history probably speaks well to what we would probably do going forward.

We've been pretty consistent in that now for some time.

Okay.

My second question is, is Diamond at full capacity right now?

And that if we look in that what is the incremental margin to Memphis?

And comparing to say in the fourth quarter, how much is Diamond that you are running?

And also that whether you can give the same number on Line 9 to capacity in the fourth quarter?

And what do you expect in the first quarter?

Well Gary, you want to go ahead?

Take the first of those 4 questions.

The Diamond Pipeline started up kind of latish November.

We had a very good start-up and the line has run extremely well since coming online.

December was our first full month of operation.

And in December, what you're really looking at in terms of the economic benefit is that spread between WTI and LLS.

In December, during our first month of operation, that spread was $5.33 a barrel.

In January, it remained wide, so in January, that spread between WTI and LLS average $4.18 a barrel.

So that gives you an idea of the economic impact that Diamond is having on our system today.

Line 9, similar with the wide Brent TIR.

We're seeing very good economics through Line 9 as well.

So I don't have exactly where that spread was in December and January, but on a prompt basis, Line 9 barrel beats an alternative by about $1.20 a barrel.

But Gary, do you have a throughput volume that you're shipping from Line 9 into capacity in the fourth quarter?

And what do you expect in the first quarter?

So we don't give guidance on that.

We are utilizing our full capacity that we have available to us.

And our next question comes from the line of Douglas Leggate, Bank of America Merrill Lynch.

So I wonder if I could touch on the cash distribution.

Obviously, the reset towards cash flow has really given a lot of clarity to the market.

And I think you've been rewarded for that.

But it doesn't mean that you're buying back shares pretty much at the all-time high in the stock price, whereas the tax cut, obviously, resets whatever the margin is the low point for your cash flow at the bottom of whatever we think the cycle is now.

So I guess what I'm really trying to get to is how much is too much of a buyback in terms of -- do you have a limit as to where you would slow down the buyback and skew back towards a more sustainable dividend?

Obviously, you've already done that.

I'm just wondering how much probably you think that balance has to go.

And I've got a follow-up, please.

No, that's a fair question.

Mike, you want to take a crack at this?

Yes.

We have increased, as we did this year recently, our dividend so that will take up a bigger piece of our 40% to 50% of the target.

Now I mean, as our taxes is reduced through tax reform, this amount of available cash flow will increase and it will -- we'll continue to evaluate that through our capital allocation process, as Joe talked about, and it will compete with growth investments and M&A and cash returns.

Doug, when you think about it, I mean -- and this has been a consistent question that we've received for several years.

Are we buying back shares at $50?

Is it too high?

Are we buying back shares at $60?

Is that too high?

And here we are.

We find ourselves kind of in the mid-90s and is that too high.

I mean frankly, I think our view would be that we remain undervalued.

And the paradigm on independent refining is shifting.

We are much more focused, certainly Valero is, on producing free cash flow and maintaining capital discipline around the use of funds.

And to the extent that we continue to throw off significant amounts of free cash flow, we're going to have the opportunity to continue to buy back our shares and create higher lows and higher highs in the stock price.

So if you ask me personally if I think we're overvalued today, I would say the answer is no, and do I think there's upside in the stock price, I'd say, yes.

And as a result, I thank that you should expect that we're going to continue to balance out our payout with repurchases.

I appreciate this answer.

I know it's not an easy one to answer, but I guess I -- we don't view that you've kind of shifted to be on S&P 500 yield stock.

And I think the dividend for what it's worth probably gets rewarded.

But that's -- that's just our take.

Anyway, I appreciate you taking to question.

My follow-up is really -- we just had the Marathon call before you.

And Gary made some really interesting comments, I thought, about the prospects of getting a RIN resolution by the spring.

RIN cost for both diesel and/or biofuel and ethanol will both come down, it seems.

I am just wondering if you could share your thoughts.

Do you share that kind of optimism on the time line?

And if so, what's your best guess on how it plays out from here?

That's a good question.

Doug, Jason Fraser is here and he runs policy and strategic planning.

He's been obviously neck deep in this particular issue, as have I. We'll let him share some insights on that.

Yes.

This is Jason.

Things have definitely heated up.

And we're seeing an increased focus here in the past few months, especially with the PES situation.

That's dramatically shown how bad these RFS reforms needed.

That's helped shed some light on it.

We also do have the 2 efforts going within the within the Senate now with Senator Cruz trying to get the Midwest Senators to sit down to discuss a near-term solution for high Brent prices and the solution would also benefit the oil producers.

We also have Senator Cornyn who's been working very hard and over a long period of time with stakeholders and other senators to try to come up with long-term legislative reform.

So I didn't hear his comments, I don't know about his specific time line.

But there does seem to see more urgency and visibility and effort around this area in the past couple of months.

So we're more optimistic than we've been.

Things are looking better.

Jason -- do you think, Jason, that's the reason why RIN costs have really come off a bit in the last couple of months?

Or is that more seasonal?

Well, Gary may have more of a view on the market, but that's got to be something affecting it.

There's a risk.

And there's also, the EPA has kind of signaled they're looking at these small refinery exceptions.

And there's been a lot of discussion of that.

If they were to grant those and not reallocate them to other obligated parties, which is what we think they would do, they would not redistribute that mandate, that would have a negative effect on RIN prices, too.

So there are several things floating around.

But Gary -- I don't know if Gary has a view on beyond that.

No, I see it the same way.

I think anytime you read something in the press on potential regulatory changes, you see people that are hoarding RINs start dumping them in the market.

They learn that they may be hoarding RINs that aren't worth much in the future.

And our next question comes from the line of Spiro Dounis with UBS.

Just was hoping for comment on the M&A environment for refining assets, specifically here.

I think there are a few assets on the block last year and '16, and it seems like a lot of them got pulled just due to really bid-ask spreads between buyers and sellers.

Curious if you're seeing that is still the case?

And does your renewed optimism on the refining outlook and tax reform change any of the calculus on valuation for you?

Okay, yes.

This is Mike.

Yes, tax reform does change the economics a little bit on the M&A.

We would have the ability to deduct the purchase price of the PP&E in year one.

And so we are in the process of updating our analysis on various potential targets.

But I don't know of anything in the marketplace today that is really for sale or products of interest.

So -- and you're right, I think the bid-ask spread, not only on refining assets but on logistics assets also, has been pretty broad.

And as you guys know, we tend to take a look at everything that's out in the market and then we have a target list of things that we particularly track that we'd be interested in.

And it just hasn't come together in a way that has allowed us to execute something that we would be pleased with.

So we'll continue to watch it.

But there's just nothing there right now.

Got it, got it.

And then just on Mexico.

I was wondering if you could update us on the progress of the project there.

How it's progressing?

And maybe along that line, I believe that project is kind of a stepping stone for you into Latin America, and so I guess when you do you think you'll be able to expect -- expand on that position?

This is Rich here.

The facilities are in the progress of acquiring land for the inland terminals and Veracruz should be handed over to IEnova, who's going to be doing the construction for us here in early February.

We expect that all of the facilities would be up and running in the first quarter of 2019.

So that's kind of on the operational side.

Maybe Gary wanted to share a little bit on just the marketing side?

Yes.

So I think for us, you'll see the ramp-up in penetration into the wholesale market after the terminal comes on.

And yes, we are looking at a lot of different opportunities in Mexico and South America.

And you know -- but don't really have anything to communicate on at this time.

And our next question comes from the line of Brad Heffern with RBC.

Just a question on the new ALKi project and the old ALKi project.

I guess -- I mean -- so now your 2 marquee CapEx projects are both ALKi and a lot of your peers have been more focused on the distillate side of the barrel.

So what's the thesis there?

Is this the Tier 3 octane destruction like you talked about?

Or is it just octane demand increasing over time?

What makes you pursue that side of things?

Okay.

So Brad, it's Lane.

So you hit upon the first part that we are optimistic about the requirements in the industry to meet octane for gasoline and it's obviously, 2 things are happening there.

One is Tier 3 is destroying octane.

Two, the autos, their trajectory is to require more octane to help them with their emissions compliance.

The other part of that is we're just -- we have a view that NGLs are going to be long, and that's all a function of the shale play that's out there, you have all these export facilities.

So even as a floor you're going to have NGL exports to the world, that's a little different position.

So at the end of the day, it really is sort of a butane to high-octane gasoline spread that we're bullish on.

And we think both these projects fit into that -- into those -- into that strategic view.

And then our position on diesel, Lane?

Gary?

Well, obviously on diesel, we've made big investments to make diesel.

We built 2 big hydrocrackers, if you remember.

We -- and we sort of -- and that was a similar view.

It was our NG -- basically our gas to liquids viewpoint, cheap natural gas, a function of shale play making diesel, which is really the world fuel.

We've invested a lot of money in that area and we are really -- our -- going forward, that's not really what we're focusing.

We're not focusing on trying to make more diesel, unless it's through resid destruction.

Okay.

Got it.

And then shifting to California, it is seeming more likely that the AQMD out there -- if they don't ban hydrofluoric acid, there's going to be a lot of mitigation procedures required.

How are you guys thinking about the potential CapEx spend at Wilmington?

And how likely you are to pursue that as an avenue?

Well, we absolutely are -- we feel pretty good that all stakeholders are working out there to find the right buyable solution for how to mitigate HF in that area.

And we're working with the South Coast to get there.

We, obviously, will -- depending on how all that works out, we'll make -- either we'll or won't make the right investment, the total investment to meet that -- to comply.

But we're very optimistic that everybody involved will get to the right place.

And our next question comes from the line of Blake Fernandez with Scotia Howard Weil.

Sticking on the West Coast theme.

The margins really collapsed into the second half of the quarter.

And maybe this is a question for Gary, but I'm just curious if you have any thoughts on what was driving that?

It seemed relative to the rest of the country, it was significantly weaker.

I know Torrance was back up and running but any other thoughts on that?

Yes.

Blake, I think historically you see the weakness in the West Coast in the fourth quarter.

This was a little more severe than what we generally see.

I think you touched on some of it, refinery utilization was high.

You were in high RBT season, so you had butane kind of swelling the gasoline pool.

And then a little bit softer demand with some of that weather issues on the West Coast.

I think all of that drove to the weakness that you've seen.

Moving forward, we have a little bit of turnaround activity going on and then already in Los Angeles, we switched to summer-grade gasoline.

The bay will go to summer grade in another couple of weeks, which will help slow supply into the market and start to bring inventories back into balance.

Great.

Okay.

And this is maybe a question for Mike.

But on the tax reform, obviously given that you have some European operations, I was just curious, given the $5 billion of cash, should we be thinking about any impact as far as repatriation and any benefits on that?

Yes.

We do have some cash both in Canada and the U.K. And we could bring that back if we need to.

But our cash position here in the U.S. is adequate, and so we don't need to bring it back at this time.

And our next question comes from the line of Justin Jenkins with Raymond James.

I guess, Joe, I'm sorry to beat a dead horse here as I think you've been pretty clear about capital allocation, but I'm curious if the lower tax rate affects anything as it relates to strategy for VLP, whether it's drop-downs or the mix of growth spending.

Any thoughts there?

Mike, you or Rich, you want to talk to it?

Or Donna?

Yes, go ahead.

On the drop-down, I mean, are you -- I guess it remains to be seen how that the tax reform, obviously, had just happened in December and how that's going to affect the drop-down activity.

The multiples are market related.

And so we just don't know for sure how tax reform will affect those multiples.

Well, Mike and then if you're doing a drop-down, you got a related-party transaction and is the treatment on that different than an acquisition from a third party?

You talk about full expensing?

Yes.

Yes.

So normally at a broad perspective, immediate expensing will not be allowed because Valero and VLP are related parties.

And in regards to third-party acquisition, VLP would likely not elect that because it does create some significant fluctuations from year to year in the allocation or calculation of remedial income to the public unitholders.

So bonus depreciation had been available for many years.

And yet generally MLPs do not -- have not chosen to take that.

I'm not sure that answers your question, but...

No, that's perfect.

I appreciate that.

And then maybe just shifting gears here, following up on Roger's question on access to the Canadian crude.

Can you talk about the pipeline projects that are in the queue?

I'm thinking along the lines of Keystone XL and then how that might fit to VLO's overall strategy.

Yes.

So obviously, we were big backers of Keystone XL and believe it's a great project as it kind of brings that heavy Western Canadian oil to the high-complexity U.S. Gulf Coast refining system and direct access to our Port Arthur refinery.

So we're excited that, that project is moving forward and it will certainly improve our access to the growing production in Western Canada.

And our next question comes from the line of Peter Low with Redburn.

Just 2, please.

The first is on your West Coast operations.

Do you see any synergies there between those refineries and the rest of the portfolio?

And would you ever consider in the future the need to exit that region?

And then secondly, just can you provide an update on your proposed doubling of capacity at Diamond Green Diesel?

I'd be interested to understand what Valero's primary motivation is with DGD.

Is it the returns project makes on its own light or rather that they can help mitigate your own biofuel blending costs?

All right, Peter.

Well on the West Coast, I mean, there's some synergies, but largely limited synergies, I would say, between the West Coast and the rest of the Valero system.

That being said, it's a good operation, we have good management and it is a great option on strong West Coast margins when we experience them.

So it's part of our portfolio, it cash flows and so we don't have any interest to divest ourselves of it.

Now as far as DGD, Martin, you want to...

Yes.

On Diamond Green, we have a project underway to go from 160 million gallons a year to 275 million gallons a year.

That will start up in the third quarter.

We've also talked about a second expansion from 275 million to 550 million.

That final investment decision will be made in 2018.

And it will stand on its own rights.

We look at that as the JV and we look at cash that, that throws off and decide what we're going to do.

So that's how we decide here.

And our next question comes from the line of Phil Gresh with JPMorgan.

Just a clarification on the tax reform.

You gave a 22% effective rate.

Was curious if there was additional savings you expect from the bonus depreciation benefit, et cetera from a cash basis, percentage basis or a dollar basis.

How you think about it?

Okay, yes.

On the reform, what we did was we pro forma-ed our 2017 results and we had $3.2 billion of pretax income.

We wanted to determine the change in our tax provision as well as the cash taxes.

And so we assume that all available capital employed in '17 was available for foreign expensing.

So in regard to our income statement, the tax provision would be low by approximately $230 million or $0.50 per share.

On the cash side, our cash taxes, our U.S. cash taxes would decrease by approximately $400 million, based on those assumptions.

And then when you include the repatriation tax to transition to the territorial system, the savings would be $350 million.

Okay.

So just to clarify, if we're looking at your CFO, year-over-year, it would be the $350 million number?

That would be correct.

Okay, great.

Second question is just on the OpEx.

In the fourth quarter you came in well below your expectations.

And then in the first quarter, your guidance is quite a bit higher.

I mean, is that just simply net gas cost and throughput?

Or anything else that would stick out in terms of why you were so much better in the fourth quarter and the flip in 1Q?

Phil, it's Lane.

It's primarily the difference between our turnaround activity from fourth to first quarter.

And our next question comes from the line of Paul Sankey with Wolfe Research.

Back to the dead horse, I'm afraid, Joe.

Can you -- I was just wondering if you could revisit the possibility of paying down debt?

I know there's possibly the argument that it would lower your cost of capital and keep your multiple expanding, which it seems to be doing.

And I guess that follows into the second part of my question, which is where do you think we are relative to mid-cycle.

I kind of think that's the answer on whether or not you should be thinking about doing more debt pay-down and maybe less buyback.

Yes.

Okay, Paul.

So you want to start with the second part of this first?

Yes.

So I think in terms of where we are relative to mid-cycle, when you start the year 30 million barrels below on distillate inventory, the distillate market looks very strong.

And I think, where we've been relative to mid-cycle, we've been below mid-cycle largely because the diesel cracks have been softer.

I think you'll see significant strengthening in the diesel cracks and you'll begin to pull above mid-cycle margins as we move through the year.

And Mike, do you want to talk about debt?

I guess on debt we are at 23% debt to cap, which is the low end of our range.

And so we don't have a lot of maturities upcoming.

None so far in 2018.

And so I guess I just really hadn't thought much about paying debt down at this time.

That's very clear, guys.

Actually not, can I just go back to the mid-cycle thing?

Sorry.

Were you saying that you think we're above mid-cycle right now?

I think we've been below mid-cycle.

But you'll start to transition to a period where we'll be above mid-cycle moving forward.

And our next question comes from the line of Benny Wong with Morgan Stanley.

Quick question for you, I guess this is more on the regulatory front, so this might be for Jason here.

Just in regards to the CAFE standards that are coming up to going through the mid-term review, I think you're expected to have a decision or an outcome in April.

Just wondering if there's any thoughts of anything you guys are looking for coming out of that.

And if you see any efforts, if there are any efforts to roll back efficiencies would that be held up if California doesn't want to get on site?

Okay.

Yes, this is Jason.

Yes, we're, of course, happy that Trump's reopened that mid-term evaluation.

The EPA, I think it's going to meet that April 1 deadline.

The administrator is very firm on meeting his obligation.

So we think there's not going to be delay in it.

We understand they've been having productive conversation with (inaudible) in California.

Everybody would prefer to have 1 national program.

The autos certainly prefer that.

I think the EPA is trying to work as they can.

We did see it looked like the majority of the autos had used credits from past years to meet the EPA standard for 2016.

So that tells you this is something that definitely needs to be looked at.

These ever-increasing numbers perhaps starting to have trouble with '16.

I believe the EPA said that they would have enough credits to keep themselves shoaled until 2021.

So we're hoping this process will end in some leveling off of the standards at a reasonable number, that the market allows you to sell cars the people actually want and is sustainable.

Well, it's encouraging that they're allowing the mid-term review to be completed.

I mean, the previous administration aborted the process kind of in midstream and the fact that you're reassessing it and it shows that the autos are doing a good job of communicating their situation to the EPA and the other regulatory bodies.

So it'll be interesting to see what happens.

And this conversation on CAFE dovetails into the conversation around octane and the comments that Lane made earlier.

So it's an issue that needs to be resolved and it needs to be resolved in a reasonable way, unless we're going to start dictating to U.S. consumers what it is that they can buy.

Great.

I appreciate the color.

And just in regards to the alkylation unit, just wondering how much did the new tax environment impact that decision, if any.

And if there's any projects in your portfolio that maybe weren't that attractive before that may be a little bit more interesting now in the new environment?

So this is Lane.

So the ALKi would be more than likely was on the fence with respect to our hurdle rates.

Again we use hurdle rates primarily as a way to focus the organization on -- we first -- we start with a strategic view and then we look at these projects in the context of our strategic view.

And we use these hurdle rates to kind of give us -- to ensure that we at least minimize our commodity risk involved.

So that's the long answer to say no.

The tax regulation didn't change how we were going to think about the alkylation unit.

And that same answer sort of pertains to how we view strategic investment in general.

So it remains to be seen.

I'm not -- I think again we said time and time again we'll use our free cash flow to go through our asset allocation model, and we'll just see how it all works out.

And our next question comes from the line of Neil Mehta with Goldman Sachs.

Question, I know Joe, I asked you this a couple of weeks ago but I'm still trying to get my head around it is trying to figure out what the new normal is for Brent WTI.

Now obviously, it's fluid number and we'll blow through on the up -- way up and the way down, but we try to frame these things in terms of transportation economics, usually.

So how do you guys think about when you think about the outcomes for like a normalized Brent WTI spread, what are the lags from an economic standpoint that kind of frame what you guys think of as a new normal?

Neil, this is Gary.

The way we look at it is that with incremental production coming online in the Permian and in the Cushing region, you're beginning to push the logistics assets, getting to the Gulf.

And so you're really looking at a spot or walk-up tariff which today is $3 to $3.50 to get to the Gulf.

And then a Cushing barrel or a DSW barrel when it gets to the Gulf generally has about $1 quality differential.

So that moves you from this $3 to $4, $4.50.

And then you have about another $0.50 to get it on the water.

So we kind of view that anywhere it has -- $4.50 to $5 range is kind of what we believe is a sustainable Brent TI spread.

Yes.

We're getting to a similar outcome.

One question we had was around just once you get to the water, are there any limitations around crude export capacity or constraints, just logistically?

Just curious as people who are doing it, whether you see any -- especially if the U.S. continues to grow at this pace over the next couple of years, do we run into the wall at some point?

Well, we may at some point.

I don't think we feel like the logistics are limiting today.

What you do see, even with the arb where it is today, you start to see people charge higher and higher premiums for dock access.

So today that $0.50 number I quoted, is more like $0.90 if you want to get to the water as people see the wide arbs.

And our next question comes from the line of Chi Chow with Tudor, Pickering, Holt.

Regarding product exports, it looks like you guys are still going pretty strong in the fourth quarter there.

But do you see any risk ahead out of the Gulf Coast?

For instance, do you expect the market to change at all with reports of Pemex really progressing on sorting out its own operations?

Chi, this is Gary.

I don't think we see anything that's significantly different in terms of Mexico or South America.

One, we think it's going to take Pemex longer to get the improvement in refinery utilization than the numbers that they're quoting.

But then you're also seeing good demand growth.

So even if refinery utilization improves, we think that demand growth will outweigh that improvement refinery utilization and we'll still see strong export demand into those regions.

Okay, great.

And then on the Mexico strategy, a couple of questions.

What's the term on the agreements you have with IEnova on the 3 terminals?

And also for Ferromex on the rail services?

That's 20 years on the Ferromex.

And it's less than that on the IEnova.

So it's half that.

We have the option to extend those contracts.

Okay.

Great.

And do you see any risk to the momentum on energy reform down there, on what might transpire from the upcoming presidential election?

Yes.

I mean we're watching it pretty carefully.

And we don't know any better than anybody else what might be the potential outcome of their election.

I did read, though, this morning that there hasn't been a direct statement by the opposition party that they would undo the reforms.

And if there was an attempt to try to do that, it would be very difficult to execute.

So Jason, do you have any other color on that?

Yes, no, that's right, Joe.

The elections are coming up July 1. This is a big election in Mexico.

The concern you see voiced most is about Mr. López Obrador's views on energy reforms, the policies in favor of them.

It's -- and we've always been told it's very, very hard to undo these now that they're in place, it would basically change their constitution.

And we think people -- and there's a lot of short-term pain when this first started to getting rolled out, but we're confident people will figure out this is really the best long-term interest of the Mexican economy and that he's going to prevail.

Do you think Lopez's comments -- is it just campaign rhetoric?

Or does he actually believe kind of some of the statements he has put out there?

We don't know.

Hard to tell.

We don't know.

And our next question comes from the line of Kristina Kazarian with Credit Suisse.

A number of the pipeline companies have talked about building pipes from Permian to Corpus.

Could you maybe talk about your thoughts about potentially committing to a long-term capacity on a pipe like this, given your refining footprint in the Gulf Coast?

And maybe even potentially partnering with one of those companies to take an ownership stake in one of those pipes and how you think about something like that?

Sure Kristina, this is Rich.

Currently there's a lot of open season projects going on right now.

Epic and Buckeye and Magellan have got projects going on through the Permian to Corpus or to Houston.

We don't have any binding commitments with anybody.

I mean, you know us.

We're always looking at logistics opportunities that can reduce our secondary cost or provide third-party revenues.

But it's interesting, but we're not committed to anything.

Okay.

And does that mean lack of interest at this point, or just haven't decided on since there's so many options?

There's a lot of options.

And we're just -- we're looking at them.

The good news is, right, that's just going to mean there's more crude coming into Corpus for the Corpus refinery.

So that's always a good thing when there's excess pipeline capacity coming into the markets where we can grow our refining capacity.

Well, there's not a lack of interest on our part.

I mean, it's just you evaluate your options, against the other options and what benefit it brings to not only VLP but also to Valero Energy.

And so we'll continue to look at them.

But I think Rich's point is we're looking at them, but we haven't made any commitments today.

Perfect.

And then a longer-term one maybe on the other side of some of the questions you guys got asked earlier around M&A.

With a lot more capital in the refining space, do you think there's chance that you see other bidders out there in the market that might make you guys think about potentially considering selling some noncore assets if you were to get increased interest across the space?

Well, we don't have any noncore assets, okay?

So that's the first part of that.

I would say you may see more M&A activity as a result of this.

But we also talked earlier about bid-ask spreads being very high.

I would suspect that it wouldn't take long for a seller to figure out that he could extract a premium based on everyone's new situation under tax reform.

And so the prices will adjust.

So we can probably work ourselves into a thesis that said there's going to be a lot more activity.

But buyers and sellers are both aware of the same facts and so I don't know that whole lot is going to change at the end of the day.

And your next question come from the line of Ryan Todd with Deutsche Bank.

Maybe a couple quick specific ones.

Can you share your thoughts on what you think the status is of the biofuel tax credit extension, whether you made any assumption on its inclusion or exclusion and your numbers and whether it would offer upside to the $350 million pro forma tax or theoretical tax savings for 2017?

Jason, you or Mark want to talk about it?

He's just saying would it create upside.

Are we going to get it and it would it create upside?

Yes.

I mean, we do think the legislation that brings up -- would bring the blended tax credit out has just been called up and delayed in the government funding immigration situation.

We do expect it to be passed retroactive for '17 and extended through '18.

At the end of the day, it's just got caught up in all the Washington drama right now.

We don't think it's going to get changed to a producer's tax credit.

That may be something that's revisited going forward.

But everybody involved seems to see with everything going on, they just need to try to keep the current law and get that passed for these 2 years and look at talking about subsequently changing it on out into '19.

So we think it's going to happen, it's just a question of when.

And then its value to us?

Much significant value to us from the JV.

It's $1 a gallon retroactive, right?

So it's $160 million.

So it's significant.

Okay.

And then maybe one other specific one.

There's been quite a bit of recent weakness in fuel oil spreads, particularly on the high sulfur fuel oil spreads recently, even above and beyond, I guess, what we would expect seasonally.

Can you speak as to what you think the driver of this event?

Is it a function of fundamentals?

Is it a front running of the IMO trade or too early for that?

Or any thoughts on that?

And then your potential to capitalize on lower feedstock cost?

Yes, I think it's probably too early for any of the IMO impact we'd be seeing in the market.

I think what you're seeing, though, is globally, countries are beginning to -- they put an infrastructure to be able to import LNG and then they ban the burning of high-sulfur fuel for power generation.

And so you've seen that transpire in a couple of countries.

And as those countries roll off and stop consuming fuel, you see weakness in the markets.

And I think that's what we've seen recently happen in the market.

Okay.

And is it something you can capitalize on within the portfolio?

Or relatively insignificant in the scheme of things?

No, it's very much is.

High-sulfur fuel oil has a significant input -- impact on the heavy sour crude prices.

And so as high-sulfur fuel gets discounted, we don't generally see wider quality discounts, which benefit us greatly.

Thank you.

And that does conclude Q&A for today.

So I'd like to return the call to Mr. John Locke for any closing remarks.

Okay, well, thanks, everyone, for joining us on the call.

If you have any additional questions or didn't get a chance to ask, please just give us a call at the Investor Relations team.

Thank you.

Ladies and gentlemen, thank you for participating in today's conference.

This does conclude the program and you may all disconnect.

Everyone, have a great day.