菲利普斯66 (PSX) 2017 Q4 法說會逐字稿

Welcome to the Fourth Quarter 2017 Phillips 66 Earnings Conference Call.

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

(Operator Instructions) Please note that this conference is being recorded.

I will now turn the call over to Jeff Dietert, Vice President, Investor Relations.

Jeff, you may begin.

Good morning, and welcome to the Phillips 66 Fourth Quarter Earnings Conference Call.

Participants on today's call will include Greg Garland, Chairman and CEO; and Kevin Mitchell, Executive Vice President and CFO.

The presentation material we will be using during the call can be found in the Investor Relations section of the Phillips 66 website, along with supplemental financial and operating information.

Slide 2 contains our safe harbor statement.

It is a reminder that we will be making forward-looking statements during the presentation and our Q&A session.

Actual results may differ materially from today's comments.

Factors that could cause actual results to differ are included here as well as in our SEC filings.

With that, I'll turn the call over to Greg Garland for opening remarks.

Okay.

Thanks, Jeff.

Good morning, everyone, and thank you for joining us today.

Adjusted earnings for the fourth quarter were $548 million, $1.07 per share.

We ended the year with a strong quarter, and our operating performance was at record levels.

Refining ran at 100% capacity utilization, and we continued to operate safely and reliably.

Our Midstream business significantly grew Phillips 66 Partners by completing a $2.4 billion drop-down, our largest transaction to date.

And in Chemicals, CPChem is nearing completion of its U.S. Gulf Coast Petrochemicals Project.

Our fourth quarter cash from operations was $1.9 billion, our highest quarter since 2013.

For the year, operating cash flow was $3.6 billion.

We continue our commitment to shareholder distributions.

This quarter, we returned $816 million through dividends and share repurchases.

This brings our total distribution since inception to $16.4 billion.

During the quarter, we made progress on several of our key projects.

In Midstream, we operated well at our Sweeny Hub in a challenging margin environment.

We averaged 9 cargoes a month at the export facility, and the fractionator operated at 101% utilization.

We completed expansion of the Beaumont Terminal's export capacity to 600,000 barrels per day.

Today, the terminal has over 11 million barrels of crude and product storage capacity.

An additional 3.5 million barrels of fully contracted crude storage is under construction, and that will take the total capacity to 14.6 million barrels by the end of the year.

We announced an open season with Enbridge for the Gray Oak Pipeline project to transport crude oil from the Permian Basin to markets along the Texas Gulf Coast.

The pipeline is expected to have an initial throughput capacity of 385,000 barrels per day and be placed in service during the second half of 2019.

The Bayou Bridge Pipeline, in which PSXP holds a 40% interest, has received all permits for the extension from Lake Charles to St.

James, Louisiana.

Construction is underway.

Commercial operations are expected to begin in the second half of 2018.

Existing segment of the line from our Beaumont Terminal to Lake Charles is operating well is providing crude optionality to our refinery.

DCP Sand Hills pipeline, which transports NGLs from the Permian Basin to the Texas Gulf Coast, has exceeded 300,000 barrels per day of throughput in the fourth quarter and is expected to complete the capacity expansion to 365,000 barrels a day by the end of the quarter.

Further capacity expansion of the line to 450,000 barrels a day is anticipated in the second half of 2018.

Sand Hills is owned 2/3 by DCP and 1/3 by Phillips 66 Partners.

DCP continues to progress construction of 2 gas processing plants in the high-growth DJ basin.

The Mewbourn 3 plant is expected to start up in the third quarter of 2018, and the O'Connor 2 plant is scheduled for completion in mid-2019.

DCP also announced a final investment decision to proceed with joint development of the Gulf Coast Express Pipeline project in which it holds a 25% interest.

The pipeline will provide an outlet for natural gas production in the Permian Basin to markets along the Texas Gulf Coast.

In Chemicals, CPChem is commissioning its new Cedar Bayou ethane cracker, which should start up this quarter and ramp up to full commercial production in the second quarter.

At Old Ocean, CPChem has successfully transitioned the 2 new polyethylene units commercial operations.

In Refining, we continue to focus on high-return, quick-payout projects.

We have multiple yield-enhancing projects that are expected to deliver an additional 25,000 barrels a day of clean products by the end of 2018.

This includes the diesel recovery project, which we completed at our Ponca City Refinery in the fourth quarter.

In addition, we are modernizing FCC units at both our Bayway and Wood River refineries with anticipated completion during the second quarter of 2018.

We also have projects to reduce feedstock costs such as the Lake Charles Refinery, where we're completing modifications to run more domestic crude.

Our 2018 capital budget is $2.3 billion, including $1.4 billion of growth capital and $900 million of sustaining capital.

Our portion of capital spend by CPChem, DCP and WRB is expected to be about $900 million.

As we move into 2018, our strategy for long-term value creation remains unchanged.

This includes capturing growth opportunities in our Midstream and our Chemicals businesses where we see long-term demand growth and enhancing returns in Refining and Marketing.

Also fundamental to our strategy are shareholder distributions consisting of a competitive, secure and growing dividend complemented with share repurchases.

We believe that share repurchases are an important part of shareholder value creation.

And as long as we trade below intrinsic value, we're buyers of our shares.

So with that, I'll turn the call over to Kevin.

Thank you, Greg.

Good morning.

Starting with an overview on Slide 4. Our fourth quarter earnings were $3.2 billion.

We had special items that netted to a gain of $2.7 billion, mainly due to the U.S. tax reform legislation.

This benefit primarily reflects the revaluation of our net U.S. federal deferred tax liability position from 35% to a 21% tax rate and is partially offset by the repatriation transition tax on foreign-sourced earnings.

After excluding special items, adjusted earnings were $548 million or $1.07 per share.

Cash from operations for the quarter was $1.9 billion, which includes a positive working capital impact of $913 million.

Capital spending for the quarter was $537 million with $234 million spent on growth projects.

Distributions to shareholders in the fourth quarter consisted of $353 million in dividends and $463 million in share repurchases.

Slide 5 compares fourth quarter and third quarter adjusted earnings by segment.

Quarter-over-quarter, adjusted earnings decreased by $310 million driven by lower results in Refining, Marketing and Chemicals, partially offset by improvements in Midstream.

New this quarter, our segment reporting is on a net income basis instead of net income attributable to Phillips 66 as previously presented.

Our segment earnings now include earnings that are attributable to noncontrolling interests.

This segment reporting change better aligns with how we manage the business and makes our reporting more comparable with our peers.

Slide 6 shows our Midstream results.

Transportation adjusted net income for the quarter was $108 million, up $10 million from the prior quarter.

The increase was primarily due to higher terminal and pipeline volumes.

In NGL and Other, the $20 million increase from the prior quarter was largely due to the PSXP acquisition of Merey Sweeny.

DCP Midstream had adjusted net income of $14 million in the fourth quarter.

The $13 million increase from the previous quarter was due to the absence of third quarter asset impairments, higher NGL prices and increased volumes.

Turning to Chemicals on Slide 7. Fourth quarter adjusted net income for the segment was $121 million, $32 million lower than the third quarter.

In Olefins and Polyolefins, adjusted net income decreased by $42 million.

This decrease was due to lower sales volumes and higher depreciation and operating costs, partially offset by improved margins.

The increased depreciation and operating costs reflect the start-up of the new polyethylene units at Old Ocean.

Global O&P utilization was 79%, reflecting continued downtime at Cedar Bayou.

The Cedar Bayou facility's hurricane-related repairs continued into the fourth quarter with most major units returning to service by December.

Adjusted net income for SA&S increased by $12 million due to higher margins and lower operating costs.

In Refining, our crude utilization was 100% for the quarter, up from 98% in the third quarter.

Pretax turnaround costs were $99 million, $56 million higher than the third quarter.

Clean product yield was 87%, an increase of 2 percentage points from the prior quarter, primarily due to processing more intermediates from inventory and increased butane blending.

Realized margin was $8.98 per barrel, down from $10.49 per barrel last quarter.

The chart on Slide 8 provides a regional view of the change in adjusted net income.

In total, the Refining segment had adjusted net income of $358 million, a decrease of $190 million from last quarter.

This decrease was driven by a 35% decline in gasoline market cracks and higher turnaround costs, partially offset by improved clean product differentials and increased volumes.

Adjusted net income in the Atlantic Basin was $120 million, down $52 million from the third quarter.

The decrease was primarily due to the lower gasoline market crack, partially offset by increased volumes and improved clean product differentials as European cracks improved relative to the New York Harbor crack.

The Atlantic Basin region ran at 104% utilization in the fourth quarter, the third consecutive quarter at or above full capacity.

The Gulf Coast adjusted net income was $72 million, down $5 million from the third quarter.

The decrease was due to the lower market crack, which was largely offset by higher clean product realizations and increased volumes.

The Gulf Coast capacity utilization was 102%, up from 93% in the third quarter.

Adjusted net income in the Central Corridor was $192 million, down $6 million from the previous quarter.

The decrease was primarily due to turnaround activity at the Ponca City Refinery.

In the West Coast, adjusted net income decreased $127 million from the previous quarter, reflecting the 32% decline in the market crack.

Slide 9 covers market capture.

The 3:2:1 market crack for the quarter was $13.98 per barrel compared to $18.19 per barrel in the third quarter.

Our realized margin for the fourth quarter was $8.98 per barrel, resulting in an overall market capture of 64%, up from 58% in the third quarter.

Market capture is impacted, in part, by the configuration of our refineries.

During the fourth quarter, we made less gasoline and more distillate than premised in the 3:2:1 market crack, and the distillate crack was stronger relative to the gasoline crack.

As a result, the configuration loss of $1.44 per barrel was an improvement from $1.58 per barrel from the prior quarter.

Losses from secondary products of $1.99 per barrel were lower than the previous quarter due to improved NGL prices relative to crude.

Feedstock advantage improved realized margins by $0.82 per barrel.

This was $0.20 better than the prior quarter.

The other category mainly includes costs associated with rents, outgoing freight, product differentials and inventory impacts.

This category reduced realized margins by $2.39 per barrel compared with $3.20 per barrel in the prior quarter.

The improvement was primarily due to clean product price differentials.

Let's move to Marketing and Specialties on Slide 10.

Adjusted fourth quarter net income was $124 million, $87 million lower than the third quarter.

In Marketing and Other, the $76 million decrease in adjusted net income was largely due to lower realized margins and seasonally lower branded volumes.

During the fourth quarter, we exported 236,000 barrels per day of refined products with continued strong demand from Latin America.

Specialties adjusted net income was $37 million, a decrease of $11 million from the prior quarter, mainly due to lower base oil and finished lubricant margins.

On Slide 11, the Corporate and Other segment had adjusted net costs of $140 million this quarter compared to $127 million in the prior quarter.

The $13 million increase in net costs was primarily due to positive tax adjustments in the third quarter.

On Slide 12, we summarize our financial results for the year.

2017 adjusted earnings were $2.3 billion or $4.38 per share.

At the end of the fourth quarter, our net debt-to-capital ratio was 20%.

The adjusted return on capital employed for 2017 was 8%.

Slide 13 shows the change in cash during the year.

We entered the year with $2.7 billion in cash on our balance sheet.

Cash from operations was $3.6 billion with minimal working capital impact, and PSXP raised $1.2 billion in equity proceeds.

We funded $1.8 billion of capital expenditures and investments and distributed $3 billion to shareholders in dividends and share repurchases.

The $400 million in other includes affiliate loan repayments.

We ended the year with 502 million shares outstanding, and our cash balance was $3.1 billion.

This concludes my review of the financial and operational results.

Next, I'll cover a few outlook items.

In the first quarter, in Chemicals, we anticipate the global O&P utilization rate to be in the mid-90s.

In Refining, the first quarter will be a heavy turnaround quarter for us.

We expect the worldwide crude utilization rate to be in the mid-80s and pretax turnaround expenses to be between $230 million and $260 million.

We anticipate Corporate and Other costs to come in between $160 million and $180 million after tax during the first quarter.

For 2018, we plan full year turnaround expenses to be between $520 million and $570 million pretax.

We expect Corporate and Other costs to come in between $640 million and $680 million.

Our after-tax corporate costs are higher due to the lower U.S. tax rate as well as the inclusion of interest expense associated with noncontrolling interests.

We anticipate full year D&A of about $1.4 billion.

And company-wide, we expect the effective income tax rate to be in the low to mid-20% range.

Our effective income tax rate reflects the impact of the new U.S. federal rate, state and foreign tax rates and the impact of income attributable to noncontrolling interests.

The Tax Cuts and Jobs Act should be positive for Phillips 66.

We will benefit from the 21% corporate tax rate and the capital cost recovery provisions.

We also have more flexibility in managing our global cash balances.

With that, we'll now open the line for questions.

(Operator Instructions) Neil Mehta from Goldman Sachs.

A couple of questions here.

The first is just around share repurchases.

With tax reform coming in and the amount of cash flow that you guys should be able to throw off as you go into this harvesting mode with lower capital spending, you should be in a position to be aggressive around share repurchases, especially if you do believe the stock is trading below intrinsic value.

You've come out with this $1 billion to $2 billion range in the past, Greg and team.

Just wanted to see how you're thinking about the potential to even go over that in this type of environment.

Well, Neil, first of all, good morning.

Good to hear from you.

There's a couple things that I think about.

One is we've got new income coming on from all these investments we've been making.

Mid-cycle, that's $1-ish billion to $1.5 billion.

We've got a nice tailwind probably from tax reform as you think about that.

And then we think about the investment opportunity universe, it's really competitive out there.

So I certainly don't see us increasing capital expenditures.

So on balance, if you think '12 to '17, we really hit the 60-40 allocation of reinvestment in the business versus giving cash back to shareholders.

We're going to probably drift more towards a 50-50 number certainly in 2018, 2019 is what it looks like to us.

So we'll certainly be right towards the high end of that range, Neil.

Whether or not we go over it, we'll just see how the year goes.

Appreciate that.

And then a follow-up is just on the Refining macro.

Greg, can you talk about -- and team, talk a little bit about both your view on -- views on the product balances.

We've seen gasoline build.

It feels seasonal.

Distillate has been strong.

And then your thoughts on Brent TI because that's compressed by quite a bit over the last couple of weeks here as we think about the year.

Yes.

You want to take a stab at that, Jeff, and then I'll come in?

Yes.

I think as we look, the global economic indicators are really at multiple year highs, both from a manufacturing and from a consumer confidence and unemployment -- multiyear lows on unemployment.

So the economy looks good globally in all the major regions.

That's positive for the demand outlook.

As we start the year and think back to last year, gasoline and distillate inventories on the days of demand covered last year were above the 5-year range.

And they've shifted to the bottom of the 5-year range this year, so the starting point certainly feels better.

As we think about demand, we're seeing strong demand on the product export side.

We had record exports in the fourth quarter, 236,000 barrels a day.

And then as we look at Canadian production, in particular, continuing to grow with Fort Hills ramping up this year and really no major pipeline start-ups for 2018 and 2019.

The rail's ramped up in the fourth quarter relative to third quarter, but it doesn't appear they have substantial excess capacity.

So that's going to be a positive.

And PSX is the largest importer of Canadian crudes, buying over 0.5 million barrels a day of Canadian crude.

Lower taxes should benefit U.S. refiners, and then we've got the IMO bunker fuel specifications on the horizon.

So we're cautiously optimistic on the outlook for Refining profitability this year.

Doug Terreson from Evercore ISI.

I also wanted to ask a question about your views on some of the likely market impacts of some of these new environmental regulations that are set for the next few years.

Meaning, Jeff just mentioned IMO 2020, and then we've got Tier 3 fuels, too, that I wanted to ask about and also how the company is positioned.

So first, do you sense that the U.S. and global refining industries are investing enough to satisfy some of these rules?

Second, do you envision margins for the key products such as the octane sources, [low] and households for fuels and crude oil spreads?

How do you think that they're going to vary because of these mandates?

And then finally, how is the company positioned for these changes?

Meaning, there's 3 parts to the question.

Is the industry ready in your view?

Two, what do you think are the likely outcome incomes for spreads?

And most importantly, how is Phillips 66 positioned for these new environmental mandates?

Well, let me start to work backwards, and I'll pass it off to Jeff to talk about some of the details.

So the answer to how we're positioned, we're pretty much through the Tier 3 investment period, and that's one reason you see in our sustaining capital come down in Refining, Doug.

In terms of IMO, we're not planning on making significant investments.

There are probably some small things we'll do around the assets in terms of looking at yields and conversions, but we don't view that necessarily as a negative impact on our business.

I think we're constructive on what that does in terms of the distillate price, but we're probably not as optimistic as some of the others out there.

Although Jeff is pretty optimistic on it, so I'll let him talk you through what he thinks the impacts are going to be in terms of margins and maybe some of the other refiners out there.

Yes.

We're -- you're bringing up a source of internal debate that happens on a fairly regular basis.

But as we look at it, the IMO market is about 4 million barrels a day in rough numbers.

You take the scrubbers and probably noncompliance, that might be 1 million barrels a day of it.

There's 1 million barrels a day that might get blended up, and you end up with still about 2 million barrels of incremental diesel demand.

And you compare that to the global demand of 35 million barrels a day, that's about a 6% increase, a meaningful increase upcoming.

On the resid side, it's also 2 million barrels a day of resid that needs to be destroyed, and that compares to global coking capacity market in the 6 million to 8 million barrel a day range.

And a lot of that capacity is already highly utilized.

So the industry is preparing in advance.

The global system has flexibility, but these are meaningful shifts.

As we think about what we're doing in 2017, we had about 15 projects that added 10,000 barrels a day of diesel production capability.

In 2018, we've got about 30 projects that will add 20,000 barrels a day of clean product.

That leans a little bit more towards gasoline, but there's diesel there as well.

And so these are low CapEx but high-return projects.

Blake Fernandez from Scotia Howard Weil.

I wanted to go back on the WCF differentials.

And Jeff, I think you've mentioned you guys have access to over 500,000 barrels a day of Canadian crude.

Can you help remind me, I guess, the actual access to that as far as -- is that pipe?

Is that rail, a combination?

I guess I'm trying to fish around to see how much of this blowout in the differential you're actually going to realize.

Yes.

There is a big pipe component of it.

It's primarily heavy.

And primarily, a vast majority of it is utilized in our own refineries.

We do import some offshore barrels that's a small portion of the total, but we're large buyers across the way.

There's not much moving by rail at this point.

Okay.

So it sounds like you've got pretty direct leverage to the differential move here.

Right.

Okay.

And then second question.

I guess maybe shifting over to the Chemicals piece since we've got the cracker kind of coming online and ramping up into next quarter.

It looks like some of the chain margins have maybe been trending below the $0.30 per pound, which I think is always kind of a mid-cycle proxy you guys use.

I didn't know if you had maybe any thoughts on that and if maybe some of the recent move in gas prices has kind of impacted the margin there.

Yes.

So let me just talk.

So margins in the quarter were up about $0.02.

For the year, they're up about $0.03 in 2017.

You kind of think about Dow came on in the fourth quarter, we had our polyethylene capacity up in the fourth quarter.

So from a market-facing standpoint, we're moving the products in.

And we believe that ExxonMobil actually ran some of their derivative capacity in the fourth quarter also.

So you're starting to see the impact of those products hit the market.

I think that in many ways, the global economy is pretty good.

You think about in U.S., you think about Europe, if you think about Asia and it's really taking these materials without a lot of margin impact.

And to your point, Blake, I think when you look at that full-chain polyethylene margin based on a weighted average feed, it is kind of hovering around the $0.25 level, which is kind of reinvestment -level economics, mid-cycle, if you want to think about it.

If you look at on an ethane basis, that full chain margin is around $0.31, $0.32.

And so those are really healthy margins for us.

And so I think that we kind of look at the Chemicals business is getting its new cracker up, getting the polyethylene into the market.

Maybe there's going to be some margin compression as these other projects do come online in 2018.

But I think you got to remember, higher crude prices are very constructive for us.

And we like high crude, low natural gas prices in the Chemicals business.

That will open up the margins for CPChem.

Paul Sankey from Wolfe Research.

I'll start with a detailed one, if I could.

You said utilization was up at 100% and 98%, respectively, over the past couple of quarters.

It seems a bit lower in Q1.

Could you just talk a little bit about whether that's sort of a lowball number and what the outlook for you guys is in terms of turnarounds over the coming year?

And then I have a follow-up.

Go ahead.

Yes.

We've provided guidance.

You see -- you saw that the first quarter is a relatively heavy lift for us on maintenance.

We're guided to $230 million to $260 million.

First quarter last year was $299 million, and that was the heaviest quarterly maintenance period in the last decade.

So we're below last year but still a meaningful lift for the first quarter.

Is there any big items there, Jeff, that you can talk about?

I think as we look at it, last year was more crude unit heavy.

And some of the downstream units, the conversion units are more impacted in this quarter.

Got it.

Greg, if I can take you to a high level.

You made an interesting comment that is always a debatable one regarding the intrinsic value of the stock relative to your appetite for buyback.

Could you just expand on that a little bit?

Sure.

Well, I'm never going to give you the number, but you can keep asking, Paul, but -- yes.

So the way we think about intrinsic value, we're looking at kind of EBITDA 2 years out.

We're using kind of historical multiples and sum of the parts.

And based on that, obviously it's a higher price than where we're trading today, and that's why we're buying shares today.

Yes.

It's an interesting point.

I mean, I don't think we ever quite get to the answer on when the optimum time.

I think you can read very long academic studies on the optimum times for buying back.

But I guess just to follow up, there's nothing really for you to do on the debt side, is there?

I mean, in terms of maturities or any other outlet for excess cash...

Not in '18.

No.

That's right, Paul.

We -- nothing coming up in the near term.

Justin Jenkins from Raymond James.

Great.

I guess maybe just to start.

Jeff, you made a few comments on the Canadian heavy differentials.

Has there been any thoughts or discussions in terms of the asset profile of Refining?

Are you comfortable with the asset base as it stands or any ownership structure of WRB, something along those lines?

No.

I think, look, we're pretty happy with the portfolio today.

We always look at the portfolio.

Many times a year, we're always looking at it.

But I just think as the portfolio lays today, we like the portfolio where it sits, has been a great partner at WRB, and we've continued to make investments there between the 2 of us.

In fact, we're modernizing the FCC.

It's one of the projects we have for 2018 there.

So I would say the portfolio is in pretty good shape.

Perfect.

And maybe shifting on taxes.

Kevin, you mentioned in your opening remarks.

But anything else to note as it relates to the earnings outside the U.S., whether it's tax payments over time for the new tax law or any plans to repatriate cash?

No, not specifically.

I mean, we -- with the -- in terms of the foreign cash, the new tax law probably gives us access to $1 billion, $1.2 billion of cash that previously was overseas and we didn't have cost-effective access to.

So it gives us a bit more flexibility in managing our overall cash.

In reality, we have plenty of cash anyway.

So it's not like we need to rush out for that, but it just helps the -- from an overall flexibility management cash position.

Doug Leggate from Bank of America Merrill Lynch.

This is Kalei Akamine on for Doug.

I've got a couple of questions, both macro related.

First, I want to see if I can get an update on the performance of the LPG export business.

I know in prior quarters, you guys have talked about the cargo is trending near capacity, and I think you were working on doing some things to optimize the costs there.

But the bigger piece of the EBITDA contribution is really arb related, and that hasn't been there in past quarters.

Wondering if you can talk about whether that's improving against these positive demand trends in oil.

So I'll start on that.

I think that we've demonstrated 25% above-design capacity at the terminal, so I think we're loading like 10 cargoes this month, did 9.6 in the fourth quarter.

So we're running at -- to capacity.

As you know the arb, the fees have been around -- between $0.05 and $0.07, in that range.

And that's substantially below what we had premised when we approved the project.

As we think about what's coming out as -- particularly from the Permian, we see strong NGL growth in 2018.

We think that utilization rates across the docks are going to come up and the opportunity to move those dock fees, and hence, those margins across will improve as we move into the back half in 2018, certainly as we get into 2019.

Yes.

You saw the DOE monthly stats.

October, November NGL production up over 400,000 barrels a day year-on-year.

I don't know if that pace is going to be sustained.

But clearly, we're seeing very strong growth on the NGL front, which is going to need to be exported, and that's going to help fill these pipelines.

Based on DOE stats last year, LPG export facilities ran in the low 80s percentage utilization.

And we think that will move into the high 80s this year, which, by the end of the year, 2019 starts helping margins.

Got it.

Second question, just kind of looking at the WTI Brent spread today, it's narrowing below $4.

What do you think the appropriate range is for the sustainable WTI Brent spread?

And what do you think sets those parameters?

And secondly, do you attribute any of this weakness to seasonality or perhaps staggered refinery maintenance profiles between the Gulf Coast and Mid-Continents post refinery maintenance, did this perhaps start widening out again?

Well, I think if you look at just West Houston versus Brent, it's traded around $1.50, kind of $0.50, plus or minus.

That part of the differential has been relatively stable.

When you look at what's happening between Cushing and Permian and the Gulf Coast, we've seen substantial changes recently with those pipelines being very highly utilized, close to full in the October, November time frame.

Since that time, Valero's Diamond Pipeline has added 200,000 barrels a day out of Cushing.

That's drawing Cushing inventories down pretty rapidly.

And from the Permian, the Midland to Sealy and the expansions of the existing added 700,000 barrels a day.

So we've gone from a period of not enough capacity to too much capacity in the short term.

Permian, it's certainly possible, could grow 700,000 barrels a day this year and be back in the -- to a very tight level by the end of the year, certainly 2019.

So that Cushing to Gulf Coast is going to swing more.

Right now, there's enough capacity, and those rates are tightening.

We'll see some seasonal impacts from maintenance, but I think those are the big drivers.

Phil Gresh from JPMorgan.

So Kevin, you probably knew I was going to start with this one, so I'll get this one out of the way.

But just the deferred tax piece in terms of the tax reform and the impacts and how you think about 2018 with the investments you have, kind of a cash tax versus booked tax rate.

Yes, Phil.

So I think the best way to look at that, I don't want to go down the path of trying to give a cash tax rate because you really need to know what your pretax income is to go there.

But the way to model that is you can assume a deferred tax benefit for 2018, total company, in the order of $400 million is what we're seeing.

And so that predominantly reflects the additional tax depreciation over and above financial depreciation.

So there's about a $400 million benefit on cash flow relative to the financial tax.

Okay, great.

Second question is on Midstream.

If you look at the increased disclosure here in the filings this quarter, the run rate of EBITDA in Midstream on an adjusted basis ex DCP is around $1.2 billion annualized.

And I know the guidance is for longer term to -- I think by the end of '18 to be more like $1.8 billion to $2.0 billion.

So could you talk about that path, the trajectory towards the end of the year?

And what projects do you expect to contribute the bulk of that?

Yes.

So I'll start.

So you're right.

You take kind of the $300-or-so million, $295 million and annualize that, you get to $1.2 billion.

And remember, in that number, the slides that we showed that you've got about $300 million or so of Refining logistics.

So that puts you to about $1.5 billion.

And there's about $300 million of growth in market that we've got laid to the plan this year, and that number is kind of end-of-year run rate number also.

So but obviously, we've got the expansions on Sand Hills.

We got the second segment of Bayou Bridge.

We've got all the work we're doing around the Beaumont Terminal.

There's a lot of -- a multitude of projects in blending at various terminals across the system, and then you've got organic growth at PSXP that's laid into that number.

So that's -- I don't think the $300 million growth or annualized run rate growth is going to be that big of a lift for us in 2018, and I think we'll hit that.

And so are you implying that the $300 million on the Refining side is likely to be dropped in '18 then?

Or is it categorization?

No, no.

That's just trying to highlight potential Midstream income that we have.

It could be droppable.

I suspect that Refining increment is some of the very last stuff we get to, Phil.

Okay.

Just one last question in terms of -- there are some questions already in Canadian heavy.

I was just curious.

You're having some challenges at Wood River being able to get full access to crude off the Keystone.

I know Keystone is still running, I think, at 80% right now.

I'm just curious how your accessibility is to that Canadian crude at Wood River right now.

Yes.

We've still got access.

Keystone is not fully back up, but it's running.

And we've got access there that we need.

Kristina Kazarian from Crédit Suisse.

Shifting back to the Chem segment.

You guys mentioned the new cracker and associated p units would be fully commercial in 2Q.

Can you just remind me, one, what the start-up costs are?

And two, how long it takes me from there to get to kind of full utilization?

And if I use some of the current margins we were talking about earlier in the call, what does that imply versus what we've talked about re: mid-cycle guidance?

Yes.

So I think that the polyethylene came up relatively quickly.

It was running at almost full capacity utilization by the end of the quarter, but I suspect by the end of the second quarter will be at full rate.

And again, remember, the polyethylene is the big pull-on , and it's already out in the market, so just getting the cracker up to supply the ethylene going into the polyethylene.

So I think it'll be a fairly quick ramp-up.

I think it's the kind of the $0.32 margins that we're looking at on ethane margins.

We're in the range of the -- kind of that $1.2-ish billion of EBITDA, certainly $1 billion to $1.2 billion in that range.

As you move back and you think about, that's pretty close to that $0.25 mid-cycle case for the weighted average feed for the industry.

So yes, I think at today's margins, we're kind of there.

You could see a little compression as we come up.

Exxon is going to come up later in the year.

But I still think that given strong fundamental demand in the business and there's not a lot of capacity coming on globally in petchems in 2018 that we're still pretty constructive around margins for the balance of 2018.

And was there a start-up cost number that you guys want to flag for me as well?

No.

Got it.

And I'll move to the pipeline side.

Can you just maybe provide an update around the open season around the Gray Oak Pipeline JV and maybe talk about the benefits from a project like that and how I would be thinking about this project versus some of the other ones announced there?

Would you be maybe willing to merge 2 together?

And just general thoughts there.

Well, we're still in the midst of the open season, so it's probably not to comment -- appropriate to comment.

I would say that high level of interest.

And it was actually -- we were asked by many of the producers in the region to do this project, so there was a lot of interest going into it.

And so yes, there's a lot of pipelines that have been announced.

There's no question.

I think that we have high levels of confidence that we'll get to a good end point on this project for Gray Oak.

Roger Read from Wells Fargo.

Yes.

And maybe just to follow up on a Midstream piece, the target of getting to the $1.8 billion exit rate in '18.

NGL and Other was a nice contributor in the fourth quarter, and I'd imagine higher oil prices are helping that along with the increased volumes.

But as you think about that improvement from kind of those Q4 exit to Q4 of '18, how much are you thinking NGLs improve from here?

Or given the sort of price volatility on that, that's actually a relatively small component of the improvement.

Yes.

I would say that's a relatively small contributing piece to it.

So in other words, if we get a stronger NGL pricing, we can think about easier to make the target or exceeding the target?

Yes.

If oil prices continue to strengthen, that will support our NGL business and make it an easier lift to get to the $1.8 billion.

The difference between the $1.8 billion and $2 billion is really market related, and so I would put it in that category.

Yes.

I think on the $1.8 billion number, we've got about $150 million laid in for the frac and for the export facility.

So we've been pretty conservative in our view of what that project contributes in 2018.

I do think as we come in the back half of the year, we're going to like the dock fees a lot better.

But a lot of that is just growth and organic growth at PSXP, plus some of the expansions we have going on in the pipe.

And so to Jeff's point, a lot of this is more pipeline-type volumes and terminal-type activity versus NGL improvement.

No.

That's helpful.

And then hasn't really been hinted on this call I don't believe, it has come up on the prior ones, potential reform of the RFS.

Do you have any thoughts on it?

I know I could guess what your wish would be.

But just curious if you have any views on the potential for that.

Were they picking up kind of the corn state senators actually talking to the oil state senators instead of holding each other hostage on their appointments?

Yes.

Well, I think you answered the question for me.

Look, I -- we're all in on this.

We think it's the right thing to do.

We think the legislation flawed.

We're adding our voice at Capitol Hill.

I agree with you.

I think that the dialogue quickly from the Senate side with the Texas senators and the corn state senators is constructive and helpful.

You've -- Congressman Walden in the house continues to be very helpful in terms of moving the dialogue forward.

My only concern is there are still a lot on Congress's plate.

I think that making recommendations about what this Congress is or isn't going to get accomplished is fraught with peril, and so we'll just have to see.

I just don't think RFS reform is one of the top parts of their agenda.

And then you move into the back half of year with election year, I think it's harder to get things done.

So if it's not done early in the year, I think it gets pushed.

Spiro Dounis from UBS Securities.

Just want to come back to capital allocation but focus a little more maybe just on the dividend.

I think we're still about a quarter or so out from when you typically announce any change there.

But just kind of looking for a framework on how you're thinking about that in relation to last year's 11% increase.

And obviously, you have a lot of project start-ups this year and then of course any benefits from tax reform.

Well -- so I think growing secure, competitive dividend is what we always -- how we always frame that answer.

We think about it's got to be affordable, it's got to be -- we want to be -- we want to continue to grow the dividend every year.

We look at where we sit versus our refining competitors and the other industry competitors, where we sit versus the yield on the kind of the S&P 100 and you kind of take all that in.

But certainly, you should expect that we will increase the dividend this year.

And I will just leave it at that.

Fair enough.

And then just want to follow up on CPChem.

I think you guys ran down the inventories there in the third quarter, and I don't suspect anybody had a chance to really ramp them back up in fourth quarter with Cedar Bayou down.

But as you head into 1Q now with Cedar Bayou back up, would you expect to sort of refill that inventory?

Just trying to get a sense if 1Q performance is also still going to be weighed down a bit as you sort of refill the inventory?

Well, I think that we're start-up on the new cracker.

And obviously, as you think about the start-up of that cracker, that will certainly impact those balances.

We've pulled down inventories, a, because Cedar was down but, b, because we were running the polyethylene units at Old Ocean also.

So you have that -- kind of that combination going on.

And of course, the hurricane impacted the entire industry there on the Gulf Coast.

But yes, I would say we normalize inventories at CPChem going forward, but there's not a reason to hold a lot of high inventory, in my view, at CPChem or any place in our chains.

We try to manage that working capital really tightly, and we're -- I would say we're constructive demand.

What we see -- so typically, seasonally, first quarter is weak in terms of petrochemical demand.

A lot of that's around the Chinese New Year and what you see going on there, but we've seen continued good buying activity out of Asia.

It really hasn't been impacted this year, so seasonally strong coming into the first quarter.

So we like what we see on the demand side on the pet chem.

Ryan Todd from Deutsche Bank.

Maybe a follow-up on some of the earlier questions on CPChem.

I think previously, you've spoken to $600 million to $800 million a year in distributions.

Can you maybe update on the trajectory of how we should think of that over the course of the year?

Will we see any distributions in the first and second quarter?

Or will that mostly be weighted towards the second half?

Yes.

Ryan, it's Kevin.

I think what you'll see on that is it's probably going to be a little bit weighted towards the second half of the year.

I don't want to infer from that we won't receive any distributions in the second half.

I think first quarter is probably unlikely, just given that we're just getting the cracker.

But that should start coming up during the first quarter and bring that up to full operations.

So you'll probably see it kind of more from second quarter on through the year.

Okay.

And then maybe just any comments you might have on the West Coast?

I mean, the West Coast was problematic during the -- in terms of refining margins during the fourth quarter, high utilization, a number of other things happening.

But can you -- any updates on yourselves, how you see the rest of the first quarter, either from a turnaround activity, switch to summer gasoline and how you expect margins to trend there over the next few months?

Yes.

I think West Coast in December -- December is typically a weak period.

The industry ran well with high utilization rates.

We had some weather influences negatively impact demand.

And so it's a tough time of year, and things got weak.

As you look into the first quarter, there is some maintenance on the West Coast in January that's kind of supported cracks here.

It looks like after the current turnarounds are completed, it looks a little bit light on the West Coast.

Midcontinent looks like, for the industry, a relatively heavy refining maintenance period.

And there's some maintenance relatively large on the -- pad 1 as well.

Internationally, it looks like a relatively heavy or close -- above normal, let's call it, rather than heavy maintenance season this spring with back-end loaded kind of March, April, May time frame.

Craig Shere from Tuohy Brothers.

So on the export -- LPG export terminal, it sounds like ongoing optimism going out to the second half and into '19.

What do you think the prospects are in the coming 12 months, maybe 18 months of expanding the amount of contracted position on that facility?

Depends on where prices are.

You certainly don't want to expand your contracts at the bottom is kind of our view.

Look, hey, I -- sometime in '19, we're probably going to hit limits in terms of industry capacity to clear the barrels.

And you kind of need a $0.10 to $0.12 fee across the dock to justify new investment, and so I think we'll get there.

But a lot of it depends on what's going on in the Permian and how many NGLs are going to be showing up.

But we remain constructive around our views on that.

Do you think that the market will be supportive enough to get longer-term contracting, 5 to 10 years?

Or do you think when it starts settling, it'll be a couple of years at a time?

It'll be a couple of years at a time in this environment.

We'll see.

I'd be surprised if you can write a 5-year paper.

Understood.

And last question on the balance sheet management.

Understand there's not a lot of debt coming due up at C corp for a while.

You do have, if I'm not mistaken, a couple of billion chunk out to 2022.

How do you think about building cash balances and expectation of a large -- managing a large maturity like that?

Would you be willing to hold outsized cash balances for a couple of years?

Yes.

Craig, it's Kevin.

I -- we may build cash simply by virtue of strong operating cash flow and depending on where the overall capital allocation sits, how much -- what we've got going on from a capital expenditure standpoint and then the other side of that with distribution, dividends and buybacks.

But I don't think we would be building cash just for the purpose of holding it to pay down debt 4 years out from this point.

We have a lot of flexibility from a balance sheet debt management standpoint.

And so given the strength of the balance sheet, the credit rating that we've got, we can easily refinance maturities as they come due, if that's what we choose to do.

So I'd look at cash balances more from a broader picture in terms of what it means from a capital allocation standpoint.

Understood.

And then, Kevin while I got you.

That $1 billion to $1.2 billion of foreign cash, is it pretty nominal cost to bring that back if you wanted in the future?

Yes.

That's the point that post tax reform, we now have access to that cash without having to pay any excess U.S. taxes.

Oh, 0?

Okay.

Because we pay the repatriation tax upfront, the deemed repatriation.

Yes.

We paid in advance...

Yes.

Or accrued it.

Brad Heffern from RBC Capital Markets.

I'll start with a sort of a macro question that's kind of tied into the WTI Brent conversation.

Just wondering if you guys have a perspective on crude export capacity in the U.S. I think you said earlier in the call, Permian could grow 700,000 barrels a day.

That's probably pushing us into the -- over 2 million barrels a day of export.

So do we run into a wall at some point on that?

Yes.

It's a good question.

I think with the hurricane back in the fall, we found out that we can export 2 million barrels a day.

We thought that might have been the max we could export at that time and perhaps it was because we hadn't gone materially higher than that.

But I think there is a need for continued infrastructure to get the Permian barrels to the shore and the majority of the increase in production is going to be exported.

And so as you look at oil production growing over 1 million barrels a day here at the end of -- into 2017 with continued improvement in IP rates and drilling efficiency gains, the drilled but uncompleted well count continued to go up during this increase in production.

So it looks to us like there's going to be sustained strong production growth in the U.S. and that more infrastructure will be needed.

Okay.

And I guess switching over to DCP.

Enbridge has labeled that as non-core.

So how do you guys feel about owning half of the GP versus potentially taking out more of it?

I think we're happy with the structure as it is today.

There no question -- I mean, Enbridge is a great company, and we're finding other ways to work together.

Gray Oak is a great example of that.

And so we continue to like DCP.

We like their positions in the Permian, the Eagle Ford, the Midcon, the DJ.

DCP has done a nice job of managing its business through a really tough time, and they're coming out the other end.

And so EBITDA is growing nicely.

They have some great growth profiles in front of them.

So fundamentally, we like the asset, but we'll have to see where it goes with our partner.

We have now reached the time limit available for questions.

I will now turn the call back over to Jeff.

Yes.

Thank you.

Appreciate your interest in Phillips 66.

If there's any follow-up calls, please contact Rosy or me.

Thank you, ladies and gentlemen.

This concludes today's conference.

You may now disconnect.