菲利普斯66 (PSX) 2017 Q3 法說會逐字稿

Welcome to the Third 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.

Welcome to the Phillips 66 Third Quarter Earnings Conference Call.

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

The presentation material we will be using during the call can be found on our Investor Relations section of our 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-and-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, Jeff.

Thank you.

Welcome, everyone, and thank you for joining us today.

During the quarter, the Gulf Coast region was impacted by Hurricane Harvey.

We're very proud of how our employees responded to the challenges caused by this storm.

They did extraordinary things to help their families, friends and neighbors.

And they worked to safeguard our assets and communities.

Through these efforts, we were able to ensure critical energy products were supplied to first responders, businesses and consumers.

For the third quarter, adjusted earnings were $858 million or $1.66 per share.

Our Refining utilization rate was 98% for the quarter.

We operated well across our Refining system.

Utilization for Atlantic Basin and West Coast regions exceeded 100%.

Our Gulf Coast region ran at 93%, reflecting hurricane impacts at Sweeny.

Our Chemicals businesses, on the other hand, was challenged due to extended downtime related to the storm.

In advance of the hurricane, operations were shut in at several of our Gulf Coast facilities where we have refining, chemical and midstream assets.

In early September, we started up many of these assets, including facilities at Sweeny, which were back to full operations by mid-September.

Our Lake Charles and Alliance refineries ran through the storm with minimal operational issues.

Our employees worked through the logistical challenges to get crude in our refineries and ensured products were getting out to market.

Additionally, in Midstream, we took operations down at the Pasadena, Beaumont and Freeport terminals.

These facilities all resumed operations in early September.

Our most significant impact was in Chemicals at the CPChem Cedar Bayou facility in Baytown, Texas.

Cedar Bayou received 60 inches of rain and reported 8 feet of water in various locations within the facility.

The phase start-up of operations is underway with most units expected to be online by the end of November.

We refocused on executing our strategy.

We're committed to operating safely, reliably in an environmentally responsible manner.

We demonstrated this commitment during the storm and the aftermath.

We've also made progress this quarter advancing key growth and return projects.

In Midstream, we continue to invest in the Beaumont Terminal to increase our storage and export capabilities.

We're building an additional 3.5 million barrels of crude storage, which is expected to be in service by the end of 2018.

We're also expanding the terminal's export facilities from 400,000 barrels a day to 600,000 barrels a day.

This is scheduled to be completed in the first quarter of 2018.

Earlier this month, we contributed in Merey Sweeny and our 25% increase in Bakken pipeline to Phillips 66 Partners in a $2.4 billion transaction.

This is the largest acquisition to date for PSXP.

PSXP is well positioned to achieve its goal of $1.1 billion run rate adjusted EBITDA by the end of 2018.

DCP Midstream is increasing the Sand Hills NGL pipeline capacity from 280,000 barrels a day to 365,000 barrels a day and is expected to be in service by the end of the year.

DCP plans to further expand the capacity to 450,000 barrels a day in the second half of 2018.

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

Also, DCP continues to focus on expansions in high-growth basins.

The Mewbourn 3 gas processing plant is being constructed in the DJ Basin and is expected to start up in the fourth quarter of 2018.

Also in the DJ, the O'Connor 2 gas processing plant is scheduled to be complete in 2019.

In the Permian Basin, DCP plans to jointly develop the Gulf Coast Express Pipeline to link natural gas production to markets along the Texas Gulf Coast.

In chemicals, CPChem started up 2 new 1.1 billion pound per year polyethylene units.

Due to the impacts of Hurricane Harvey, we now expect commissioning of the new Cedar Bayou ethane cracker to begin in the first quarter of 2018.

Together, these assets will increase CPChem's global ethylene and polyethylene capacity by approximately 1/3.

In Refining, we're progressing return projects to include -- improve clean yields, a diesel recovery project in the Ponca City Refinery is on track to start up in the fourth quarter.

We're modernizing FCC units at both the Bayway and Wood River refineries.

We expect these projects to be completed in the first half of 2018.

Financial discipline with an emphasis on returns and prudent capital allocation is fundamental to our strategy.

We're further lowering our 2017 capital expenditures guidance to about $2 billion.

During the quarter, we returned over $800 million to shareholders through dividends and share repurchases.

Early in October, our board approved a new $3 billion share repurchase program.

The new program increases the company's total share repurchase authorization to $12 billion since 2012.

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

Thank you, Greg.

Let's start with an overview on Slide 4. Third quarter earnings were $823 million.

We had special items that netted to a loss of $35 million, the largest of which was $44 million of after-tax hurricane-related costs.

After excluding these items, adjusted earnings were $858 million or $1.66 per share.

Excluding a negative working capital impact of $195 million, cash from operations was $596 million.

This also reflected the impact of a $390 million discretionary contribution to the pension plan in the quarter.

Capital spending for the quarter was $367 million, with $209 million spent on growth projects.

Distributions to shareholders in the third quarter consisted of $356 million in dividends and $461 million in share repurchases.

We finished the quarter with a net debt-to-capital ratio of 27%.

Our adjusted effective income tax rate was 33%.

Annualized adjusted year-to-date return on capital employed was 8%.

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

Quarter-over-quarter, adjusted earnings increased by $289 million, driven by improvements in refining, partially offset by lower Chemicals results.

Slide 6 shows our Midstream results.

Transportation adjusted net income for the quarter was $98 million, up $24 million from the prior quarter.

The increase was due to a full quarter of commercial operations on the Bakken pipeline.

In addition, we have higher crude oil throughput volumes due to high utilization at refineries integrated with our Midstream assets.

In NGL, the $14 million decrease from the prior quarter was largely due to hurricane impacts on the fractionation and export volumes.

DCP Midstream had adjusted net income of $1 million in the third quarter.

The $12 million decrease from the second quarter was due to the impact of rising NGL prices on forward hedges as well as $6 million of asset impairments.

After removing noncontrolling interests of $32 million, Midstream's third-quarter adjusted earnings were $67 million, $3 million higher than the second quarter.

Turning to Chemicals on Slide 7. Third quarter adjusted earnings for the segment were $153 million, $43 million lower than the second quarter.

In olefins and polyolefins, adjusted earnings decreased by $42 million, primarily due to lower margins and volumes from hurricane-related downtime, which resulted in 83% utilization.

The earnings impact from low utilization was somewhat mitigated by inventory drawdown during the quarter.

Adjusted earnings for SA&S increased by $1 million as higher equity earnings resulting from less unplanned downtime was mostly offset by lower margins.

In Refining, crude utilization was 98% for the quarter, consistent with the second quarter.

Pretax turnaround costs were $43 million, $111 million lower than the second quarter.

Clean product yield was 85%, consistent with the prior quarter.

Realized margin was $10.49 per barrel, up from $8.44 per barrel last quarter.

The chart on Slide 8 provides a reasonable view of the change in adjusted earnings.

In total, the Refining segment had adjusted earnings of $548 million, a $315 million improvement from last quarter.

This increase was driven by improved margins in all regions and lower turnaround costs.

Adjusted earnings in the Atlantic Basin were $172 million, up $63 million from the second quarter.

The increase was primarily driven by a 25% improvement in the market crack during the third quarter.

The Gulf Coast adjusted earnings improved $21 million during the quarter due to the higher market crack, partially offset by lower clean product realizations and lower volumes.

The lower utilizations resulted from the rise in prices relative to the timing of pipeline shipments and Sweeny refinery downtime during the highest-margin period of the quarter.

Adjusted earnings in the Central Corridor were $198 million, up $169 million from the previous quarter.

The increase was driven by a 42% improvement in the market crack as well as lower turnaround costs and higher volumes as the Billings Refinery completed the turnaround in the second quarter.

In the West Coast, adjusted earnings improved $62 million over the previous quarter.

The increase was primarily due to the higher distillate crack.

Slide 9 covers market capture.

The 3:2:1 market crack for the quarter was $18.19 per barrel compared to $14.06 per barrel in the first quarter.

Our realized margin for the third quarter was $10.49 per barrel, resulting in an overall market capture of 58%, down slightly from 60% in the prior quarter.

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

During the third quarter, we made less gasoline and slightly more distillate than premised in the 3:2:1 market crack.

Losses from secondary products of $2.10 per barrel were lower than the previous quarter due to improved NGL and fuel prices relative to crude.

Feedstock advantage improved realized margins by $0.62 per barrel, which was consistent with the prior quarter.

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

This category reduced realized margins by $3.20 per barrel compared with $1.30 per barrel in the prior quarter mainly due to Gulf Coast clean product realizations and higher RINs costs.

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

Adjusted third-quarter earnings were $211 million, $7 million lower than the second quarter.

In Marketing and Other, the $22 million decrease in adjusted earnings was largely due to lower realized margins.

We continue to see volume uplift from our reimaging program with a 3% year-over-year improvement in gasoline sales at our reimaged sites.

Specialties adjusted earnings were

$15 million, earnings from the Excel adjusted earnings were $48 million, an increase of $15 million over the prior quarter, mainly due to higher equity earnings from the Excel Paralubes joint venture driven by higher utilization.

On Slide 11, the Corporate and Other segment had adjusted after-tax net costs of $121 million this quarter compared to $142 million in the prior quarter.

The $21 million decrease in net costs was primarily due to tax adjustments.

Slide 12 shows the change in cash during the year.

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

Excluding working capital impacts, cash from operations for the first 3 quarters was about $2.6 billion.

Working capital changes decreased cash flow by about $900 million, primarily due to inventory builds.

Year-to-date, we funded approximately $1.3 billion of capital expenditures and investments and distributed $2.2 billion to shareholders in dividends and share repurchases.

We ended the quarter with 507 million shares outstanding, and our cash balance was $1.5 billion.

This concludes my review of the financial and operational results.

Next, I'll cover a few outlook items.

In the fourth quarter in Chemicals, we expect the global O&P utilization rate to be in the high 70s due to continued downtime at CPChem Cedar Bayou facility.

We expect most of the units to be online by the end of November.

In Refining, we expect the worldwide crude utilization rate to be in the mid-90s and pretax turnaround expenses to be between $100 million and $130 million.

We expect Corporate and Other costs to come in between $125 million and $140 million after tax.

In December, we will provide further details in our 2018 capital program.

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

(Operator Instructions) Neil Mehta from Goldman Sachs.

Greg and Kevin, I want to start on the $2 billion to $3 billion capital spending range for 2018.

Very wide range, kind of in line with our expectations.

But given the fact that you've lowered 2017 capital spend, is it fair to assume that we should think that you're going to be erring on the lower end of that range and recognizing that you can provide more color here in a couple of weeks.

Yes.

I mean, Neil, thanks for the question.

So someone said that's why, if you could drive a truck through it.

But it's very -- been very consistent with the last couple of years.

We've been saying, $1 billion of spending capital and $1 billion to $2 billion of growth capital, and $1 billion to $2 billion of share repurchase.

So we go to the board in early December on our capital budget.

And I certainly don't want to front run that.

But what I would tell you in terms of capital, we don't expect we're going to be on the high end of that range.

And in terms of share repurchase, we don't expect we're going to be on the low end of that range.

Understood.

Understood.

On Chemicals, can you talk about Cedar Bayou?

Just in terms of the project and service, I think you said by the end of November.

And what's left to be done mechanically there?

And then again, can you reiterate the targets for the end of the first quarter for the new chemical capacity to come online for next year?

Neil, it's Tim Taylor.

On -- in terms of the operating units at Cedar Bayou, we've gotten our first unit back up in operation mid-October.

It's the 1-hexene unit, which is a very critical component for polyethylene manufacturing globally.

And we've done that.

We're getting utilities back up as we speak.

And we would anticipate that the cracker should be up by mid-November.

And then there're a couple of polyethylene units that will come up maybe in early December.

So essentially, by mid-November, we expect to have most of that complex back up.

And it's really around making sure the instrumentation that was wet is functional, replacing that -- motors.

Those kinds of things tend to be more, a lot more electrical work in terms of the repair of the facility and, as you might guess, bringing back electrical power substations and switchgear for that.

A similar story around the crackers.

Two things going on in the new cracker at Cedar Bayou.

One, there was a need to repair some of the instruments and the motors that are associated with the new cracker.

That's ongoing as well.

But in conjunction with that, we continue to work on completing the mechanical part of that, and that's gone well as well.

So we've been able to pull the progress forward like we had hoped on both of those.

And so the mechanical completion in the first quarter were -- on the startup looks -- in terms of feed-in, we're still confident that we can hit that date.

And that really puts us, I think, into full commercial operation of the new cracker in the second quarter.

So more to come as we go through that, but we've been pleased with the progress that everyone on the team out there has made in terms of their commitment to the organization and getting it done and getting that unit back in operation.

Paul Sankey from Wolfe Research.

Greg, there're more positive dynamics in many ways in Refining.

Are you cheering up about it at all?

I know you've been pretty resolutely determined not to increase any spending.

Firstly, I was wondering, is there's any potential may be on the strength for you to think harder about leaving California, which you might have talked about in the past?

And then secondly, can you see a structurally better argument for the industry right now?

Yes.

So Paul, I would tell you, we're more constructive in Refining for 2018.

Certainly, if you think back to 2016 coming into 2017, we were pretty negative.

But we've seen the inventory clear out with the hurricanes.

Fundamentally, demand is pretty good.

We're in the turnaround season now and in the first quarter.

So I think we're -- our view is we're starting to be at mid-cycle or better in terms of cracks in 2018, and so we're pretty positive around that environment.

The other thing I would just say is, across the portfolio, we're pretty happy with the portfolio.

You get frustrated from time to time with California and what goes on, on there, but still reasonably good assets, well positioned, generating good cash for us.

And So I don't think you'll see us doing anything with the California assets in the near term.

And then finally, I think about '18 for us, we're coming off of kind of peak capital spending.

We've got the new assets coming on.

So we really are hitting a pivot point in terms of free cash flow generation for us, with new cash coming from the -- assets coming on and reduced capital expenditures.

So I think I'm pretty constructive about 2018.

And I guess, are you guys still relatively long distillate?

I think that's always been the historic case.

I wondered if all those have kind of caught up with you.

So I think that's true.

I think that when you look at our portfolio, how we're configured, we're -- we do like distillate because we make a lot of it.

Yes.

And then could I just follow up?

Did you just -- forgive me if I missed this.

Did you just address -- actually, I tell you what, I'll ask it a different way.

One of the things that's happening with CapEx is that it's coming down on costs.

And we've heard, actually, ConocoPhillips say that one of the issues was that people have kind of tapped the brakes in U.S. E&P, and I can understand how that would temper costs.

But it's not clear to me, with relatively tight labor markets and ongoing expansions in chemicals, how the costs have come down so successfully given the scale of labor as part of the overall budgets there.

Could you just talk a little bit about where the benefits and the cost benefits are coming for you guys?

Well, I think that in terms of costs and construction costs, I'm not sure we've seen a big decrease yet.

I think as the E&Ps tap the breaks, that will free up some capacity.

But there's still a ton of petrochemical construction going on, on the U.S. Gulf Coast.

And that -- so that, obviously, plays into that, but I like what I see.

My understanding was that your CapEx could come down again.

And I guess, it's got a very wide range because of that cost uncertainty.

Is that fair?

Because of the (inaudible) the lower cost of the segment?

Yes.

No, Paul.

So I would say, I -- so the CapEx coming down is a function of a couple of things.

One is, we're kind of through that big push in terms of the big projects that we've been doing.

And then led by you and others, I think there's an important conversation going on, and growth and returns in the upstream business.

And -- as we look at what's going on out there, we see a lot of return-challenged projects.

And part of our reduction in capital this year has been around the delay of the frack decision, but it's also around some projects that we've just chosen not to proceed with that we had in the plan because they didn't meet our return hurdle requirements.

So I think you have that dynamic going on, too.

And then everyone's looking at the Permian.

In a $40, $60 world, it seems to make sense.

But everyone sees the opportunity, and so there's a lot of people chasing the volumes coming out of the Permian.

And you just look at those returns, and those are tough returns, particularly in the Midstream space.

Doug Leggate with Bank of America Merrill Lynch.

Greg, I wonder if you could give us an update on the -- thoughts on CPChem going to cracker 2?

Obviously, we're seeing some swings and what the dividend distribution looks like.

I'm just curious if the appetite on both partners is the same to move forward, and when you might you expect to hear about it.

So I would tell you that -- I mean, we are advancing the next project.

We're doing engineering work on it.

We haven't agreed on a date for the FID for that project.

But I'm guessing it's sometime late '19, '20 would be the appropriate time on that, Doug.

And then just to be clear, that would funded at the CPChem level.

In other words, that would obviously impact distributions.

Correct.

It depends -- Doug, it depends a bit on the capital structure.

They have the ability clearly -- great credit rating, and they have the ability to help finance these projects.

And so I think that's the other variable to the distribution policy.

But I think both owners want to see distributions continue, yet we have to do that in the most capital-efficient way.

The only other comment I'd add that, too, is that CPChem continues to look outside the U.S. for opportunities as well.

And so I think there's a number of things that they're looking at beyond just a U.S. Gulf Coast cracker for the second project.

Okay.

I appreciate that, Tim.

My follow-up, Greg, is kind of a bit of a convoluted question, I guess.

When -- before we had the export ban lifted on crude oil, the whole industry seemed to pivot to take advantage of what seemed to be something of a thoughtful crude spread.

I realize it's 0 now, but I don't think -- I guess there's a debate over how wide that remains.

But my point is -- or my question is rather, that some -- do you see pricing exports really bump up in the U.S. from the Gulf Coast?

Pricing in Gulf Coast crude seems -- lately seems to have been linking more to Brent than to WTI, let's say.

So I'm just curious, does that change the dynamics of your crude slate?

Do you see more challenged pricing coming from that shift towards lighter sweet crude?

Or do you think it just kind of washes out?

I'm just curious on your perception.

And I'll leave it there.

I'll let Tim take it.

Yes.

Doug, as we think -- but you're right.

The Gulf Coast is much more linked to Brent because, yes, you've got the opportunity for imports as well as exports.

What's interesting right now is the pull on WTI and more the inland crudes to make it there to the export market.

And so we've actually seen some infrastructure bottlenecks that probably get alleviated, but probably speak to a wider WTI Brent, a little wider than we would have expected probably over the last year.

In terms of crude slate, I think from our perspective, it's certainly -- the Mid-Con WTI is advantaged versus Brent.

That's a positive for that.

I think on the coastal regions, it just increases your optionality if you're looking at light crude to import or to use U.S. crude.

So I think the world is just kind of rebalancing about what's the optimum crude on the light side.

We haven't seen much of an economic incentive to really change between light and heavy.

And so it takes a lot more differential to drive that.

So I think it's really been more about crude choices.

And I think the world's sorting out where's the best destination for the different crude types that become available.

But the coastal regions are just much more competitive on that from that basis.

Tim, can you offer a perspective on what's keeping TI Brent so wide as it stands today?

I think it -- to us, it -- a, the hurricane caused some disruptions in terms of export capability.

We've seen strong exports out of the U.S. And with that disconnect, there's a need to try and move that WTI, particularly from Cushing and other areas down into the export market.

And that space has just really become more valuable.

So I think the response has been that the transportation costs to get it there has gone up, and that's led to a wider differential.

That probably comes in over time as that gets debottlenecked.

But it looks structurally -- as we think about the demand export pull, we think that leads to a bit wider WTI-Brent, but probably not in the range that we're seeing today.

It should be tighter.

So TI has been weaker, but Brent's been stronger.

Yes.

I think that's part of the formula, too.

And I think -- and we think about the fourth quarter turnarounds, et cetera, we're probably $4 to $6 on that spread.

But I don't think that's sustainable long term.

I think as you get into '18, and some of the infrastructure, you get normalization in the markets.

We're still thinking long term that that spread is something under $4.

Yes.

Phil Gresh from JPMorgan.

First question is as you kind of have this more muted capital spending outlook on a go-forward basis, do you think that there're opportunities out there from an M&A perspective, from a capital allocation standpoint?

Or as you look at the returns on M&A, is it equally as challenging as what you're talking about with some of the organic opportunities?

Valuations still look high to us.

So I do think that -- particularly if you look at that midstream space, you have a lot of folks that are highly levered, high yield, high cost of capital, trying to compete out there.

So I do think there's going to be some consolidation coming in the midstream space.

So I -- we'll see how that plays out.

But when you look at some of the assets that have changed hands at 20x.

It's just hard to see how you create value doing that for your shareholders.

Sure, okay.

Second question for Kevin, just on the cash flow statement.

There're some moving pieces this quarter, lower deferred taxes, some headwinds from equity affiliates.

If you could just maybe elaborate on those and talk about your outlook?

And especially on deferred tax since it was such a high number in the first half of the year.

Yes, Phil.

So on deferred taxes, a lot of that benefit that we had been recognizing reflected the assets going into service this year and the impact of bonus depreciation, which, for this year, is 50%, year 1 depreciation.

With the start-up of the cracker being pushed into the first quarter of 2018, we have backed off of that, recognizing that benefit in 2017.

And so what you saw in the third quarter was a reversal of what we had recognized year-to-date on -- for depreciation on the cracker.

And so I think when you get to the fourth quarter, you'll still -- you'll see some deferred tax tailwind again.

In the third quarter, it was essentially 0, as the reversal offset the other positive impacts there.

And then on a go-forward basis, you would normally expect, given the couple of billion dollars of capital expenditures and the profile of the tax depreciation, you'd normally expect some degree of benefit from a deferred tax standpoint.

And just as a reminder, bonus depreciation, 2018 assets placed in service, that first year depreciation is 40%.

It drops from 50% to 40%.

In 2019, it drops to 30%.

And then you have the normal makers depreciation on top of that.

So expect to see some -- a resumption to a more normal level of deferred tax benefit in future periods.

Okay.

Very helpful.

And then just on working capital.

You've had a pretty big usage year-to-date.

Is that something you expect some reversal, normalization from the storms or anything like that in the fourth quarter?

Yes, you will.

And the big piece of the drag year-to-date on working capital has been associated with inventory build.

And so you can expect to see some of that come back in the fourth quarter, as is usually the case.

Typically, you don't see the full cash benefit of that in the fourth quarter because some of it carries over into the first quarter.

But I would expect to see some of that come back in the fourth quarter.

The other item, I'm just thinking back to your original question, was around distributions.

And so lower distributions from equity affiliates in the third quarter, the big impact there was CPChem.

So we had good distributions in the second quarter, nothing in the third quarter, and we're not expecting anything in the fourth quarter given that their focus is on bringing the Cedar Bayou back up and the new cracker.

And so anticipating slightly less distributions than we would have for the year.

But as you look forward into 2018, you would think with CPChem, with the CapEx coming down, the incremental cash flow from the new project.

So I'd expect CPChem distributions to be $600 million to $800 million for the year, somewhere in that range to us.

And then you've got DCP distributions coming at a -- they're not as significant, but a reasonable rate, probably $100 million to $150 million, a little bit out of WRB.

So I think that undistributed equity earnings on the cash statement will come down a little bit in 2018 relative to where it's been in -- this year and prior years.

Yes.

That's very helpful.

And did you mention something about Colonial pipeline timing in your opening remarks in the Gulf Coast for refining?

Yes, I did.

And that was in the context of price realization, actual price realizations, relative to the sort of marker -- benchmark price, in terms of the way that pricing mechanism works relative to the timing of when volumes go into the pipeline.

So that's a phenomena we often see in the Gulf Coast.

It's all just timing effects.

Paul Cheng from Barclays.

Several questions.

On the hurricane, once that the -- well, first of all then, can you quantify for us how big is the total cost and opportunity cost in the third quarter and what that may look like in the fourth quarter?

Is there any estimate that you can provide?

Yes.

Paul, this is Kevin.

I mean, we broke out the actual costs associated with the hurricane.

We haven't given a specific margin impact.

I mean, you can kind of get there from the utilization and the volume variances that we've given.

As you look forward into the fourth quarter in Chemicals, the way we see this, so you've got close to 2 months of downtime and repair activity in the fourth quarter compared to a month in the third quarter.

So the cost element of that is going to be higher.

So pretax, our share of the CPChem costs was $53 million in the third quarter.

It's going to be north of that.

It could be double that in the fourth quarter.

But consistent with the third quarter, we'll special item treat that.

So from an underlying basis, that won't impact the noise.

And then the other element is going to be on volumes and chemicals.

So we guided to high 70% utilization.

And one way to kind of think about that and rationalize it, Cedar Bayou is about 1/3 of domestic O&P production for CPChem.

So you've got 1/3 of that production offline for 2/3 of the quarter, and you get to that kind of 20% impact on utilization.

And Tim, once the -- you think cracker startup, how long will it take before you'd ramp to the full production?

What sort of expectation should we used?

Yes.

I think if you, let's say, ethane in -- at the end of the first quarter, and you're still on the commissioning piece of that, normally, borrowing equipment and things, 30 to 60 days really would be kind of the expectation to shake down and make sure that all the instrumentation and the controls are tuned.

And so you should see a ramp-up over the quarter.

But by the -- by midyear, if we do that, you would expect it to run at design capacity.

So I'll just point out, the new polyethylene capacity at Sweeny is already running.

Yes.

Right.

And so just think about the total balance in the system.

So we get the polyethylene back up at Cedar, I think -- we plan to get up pretty quick and we plan to be running at capacity for the new project.

Great.

Tim, is there any turnaround activities because half is being pushed into 2018?

No.

We've -- pockets of these are in a turnaround right now.

We really haven't pushed turnarounds.

We're sticking with our schedule.

So we gave some guidance on that, but nothing unusual as a response to Harvey.

And 2 final questions.

One is on the NGL.

The business, I mean, even after we adjust for the special items and all that, is still pretty disappointing from a financial performance standpoint.

Other than, say, the commodity market becoming better, is there anything internally that the company can do in turn in order to get it much better?

Or that really is waiting for the commodity market to turn?

And then the final question, just curious that with the IMO 2020, is there any large or reasonably large refining kind of big project that you guys have in mind?

Okay.

So I'll take the LPG, Paul.

So you're right.

There's the market and it's a tight market, propane very dear in the U.S., and that's the market fundamental.

I think that's just something that we're working through.

In terms of what we've done is we've actually gotten the frac rate now up to the 100,000 design rate.

We're loading the capability now to do 10 cargoes a month.

And so I think you work on the volume side.

That's clearly not sufficient.

And then we continue to work on how to improve the cost, right, the logistics cost for all the products that we do.

And so we're making progress on that.

So I think we look at that and say, let's work the commercial terms.

Let's work the cost side, and let's just make sure that we run it efficiently.

And then we'll keep whittling away at the market piece.

But that's really the focus, both -- particularly on the commercial side in terms of the contracting side and how we go about that.

So I think that's what we do in this case.

And we look out and we look at our NGL pipes.

They're doing quite well.

We're going to expand those.

So we see that extra NGL supply coming and I think those exports are going to continue to grow.

And that's the market change that you're waiting to see.

But in the interim, you have to continue to work on trying to improve those results with the things that you can control.

Tim, how big is the opportunity do you see or that you guys are just hoping to get in terms of improving the margins or in (inaudible) the cost?

Well, maybe one way to think about that is $0.05 a gallon for us on that is -- on the terminal is about $100 million.

And I think, realistically, you're looking for something in that range of $0.05, maybe slightly less, to try and drive that improvement on a short-term basis.

Okay.

And in terms of the IMO 2020, any kind of capital investment that you guys have in mind on the refining side related to that?

Yes, Paul.

So we kind of look at that.

And I know there's a lot of exuberance in the industry around the spec change.

And I think it's probably constructive in terms of diesel cracks, but I don't think it's going to be enough that it would incent us to make an investment.

So right now, we have no plans to really invest anything around our assets in terms of that.

And we look at the spec change and how it might impact our facilities.

A little bit of impact at Ferndale, Wood River and Bayway.

And through adjusting the crude slate and just destroying it in the cokers, we can manage that.

And then on the upside on -- so it's 3.5 million barrels a day in a 35 million-barrel market, it should be constructive.

But I think shipowners are going to have options on how they impact that.

And so I don't think we're just ascribing a lot of upside value yet to the IMO spec change in terms of the cracks.

Blake Fernandez from Scotia Howard Weil.

Kevin, I wanted to go back to the cash flow statement, if I could.

I just wanted to clarify, for one, that the discretionary pension contribution, is that embedded in the other line item up in cash provided from operating activities?

Yes, Blake.

It is.

It's in that other -- on the cash flow statement.

That's right.

Okay.

Because when I looked last year, it looks like you had a similar hit in 3Q.

I'm not sure if that was the driver.

But I guess my question is, is this something that kind of typically occurs on an annual basis?

Or does this kind of contribution defer that kind of payment for some period of time?

I think you can view what we've done this year as meeting our needs for a period of time in terms of any sort of sizable contributions into the pension plan.

We did do a payment in the third quarter of last year, but it was not as big as this one.

I think -- it was not big enough.

I don't think we even called it out in our discussion on cash flow.

I think it was something on the order of half of the magnitude.

But with this one, we should be good for a little while.

I mean, there're still other elements of contribution, including the nondiscretionary, but this will take care of most of that for a little while.

Got it.

Okay.

And the second question, I'm going to show my ignorance here in the Chemicals business.

But I was curious to see the chain margins kind of come down in 3Q.

It looks like it's actually lower than where we were the first half of the year.

I guess I thought or was anticipating a similar impact to what you see in Refining when you have a hurricane hit and margins expand due to industry downtime.

Is there just kind of a lag impact?

Or can you give us any sense of where margins are shaking out currently in 4Q?

Blake, just a real quick comment on the margin.

The margins in the market is still fairly consistent.

I think what you're seeing is the impact of the extra costs and the downtime in terms of the CPChem cash cost.

And so the indicative margin for the markets are actually -- have slightly improved over the quarter, but fairly consistent in that, if you look at IHS data, roughly in that $0.30 per pound range on the cracking side.

So we haven't seen -- we've seen strength in the polyethylene, but we just haven't seen a huge spike with that.

But it has been constructive from a market standpoint.

And Tim, just to clarify.

I would assume that that cost component would obviously normalize lower as the facility comes online, right?

Absolutely.

Roger Read from Wells Fargo.

I guess just a follow-up, really, on the Midstream side.

I know you're going to be a little bit hesitant with the CapEx for '18 still ahead here in the near term.

But you mentioned valuations.

You wouldn't really want to buy anything right here.

CapEx, maybe, that stays modest.

You don't really want to build, but you see the NGL market continuing to grow in terms of volumes.

Maybe without going -- getting too specific on crack 2, just how are you looking at the best growth opportunities down the line here as we think about '18 and '19 in the Midstream area?

Well, certainly, exports on the crude.

So we're continuing to bottleneck on Beaumont, for instance, at our terminal internal storage around that, looking at our refining system on clean products.

As we think about the system, we look at ways to increase options on both the products and the crude side.

Those are typically smaller projects.

On the bigger projects side, I'd say there's a lot of activity, a lot of interest.

But what we're seeing is that our customers are -- kind of defer their decisions about commitments on pipes as well as this thing as they look at all the opportunities out there.

And I think that was -- that's a piece of the lower CapEx.

But clearly, the Midstream opportunity is going to follow the upstream, and so we still see that.

But I think we're in a period of a couple of years so that that still shakes out from the upstream side as well.

And so I think we're matching the rhythm in terms of the upstream resource.

And then we're shifting more to what do we do around our system and continue to do with those projects and those things that support that integrated network.

So would sound like an environment where margins should get better if the infrastructure starts to get tighter.

Is that kind of a reasonable takeaway there?

Well, that would be -- yes, I think 2 things.

As Greg pointed out, a lot of competition for infrastructure right now, particularly out of the Permian.

But yes, I think you're seeing that today out of the mid-con, and you're seeing responses as well.

So all those things come together to create the opportunity.

But in the end, you need commitments from producers to make those things happen.

I think that's the segment where it's most dynamic around the opportunity.

So I think we'll continue to look at that from a return standpoint and opportunity standpoint.

We still see the opportunity.

The question is, are there returns there right now that make sense.

Okay.

And then changing gears slightly to CPChem.

If you ran inventories down this quarter, presumably either -- I'm sorry, in this quarter -- in the third quarter, we would expect probably an inventory build in the first half of next year to make up for that.

And then specific to the cost that will be borne in the fourth quarter here, is that going to be treated as they were in the third quarter as kind of a called out special item, not part of the recurring?

That's a little bit nitty pick -- nitty gritty, but I'm just curious how that's going to roll through.

Yes.

Roger, it's Kevin.

So I think the answer is yes to both.

So on -- in terms of inventory, you will see, as everything comes back online, some rebuild of inventory.

So although the utilization will be up, the sales volumes won't quite match because of the inventory build.

And then yes on the repair costs.

Those will be special item treated again as we did in the third quarter.

Brad Heffern from RBC Capital Markets.

Greg, I guess a question on repurchases.

There's been a lot of talk on the call about how equity income should improve as the new cracker comes online and so forth.

Does that make you feel any differently about the sort of $1 billion to $2 billion range of annual repurchases that you've talked about historically?

Well, I think without question, we're going to generate more free cash flow.

Long term, we're still comfortable with our 60-40 allocation methodology.

And so -- although this year, we're -- it'll be closer to 50-50 probably when you look at it.

And we'll flex as we need to around that.

But long term, I still think the 60-40 is good guidance and appropriate of what -- how we'd like to allocate capital.

Okay.

Got it.

And then switching to PSXP.

I think in the past, you've talked about how you don't see you need to do anything with the IDRs in the near future.

But obviously, some of your peers -- or more of your peers have now made that switch.

So any updated thoughts there?

Well, I think that we did a very successful financing in -- here close in October.

So I think it showed that we still had access to capital market.

But I think long-term, you've got to have the right optimal capital structure.

So I think there's a time and a place to address that, but we haven't seen that as a significant issue for us yet.

But I think it's certainly a very topical discussion and something that we think about that in terms of how you deliver the optimum value for both the general partner and the LP.

And so I think you've always got to keep that in mind as you think about IDRs and your capital structure at the MLP.

Spiro Dounis from UBS.

Just wanted to follow up 2 prior comments.

First one, Greg, you mentioned that 20x valuation multiple, which is actually something one of your peers mentioned yesterday as well.

I guess I'm trying to figure out, it seems like if you look at the midstream MLP public equities, they're a bit challenged right now, and yet we hear about deals being done at these elevated levels.

And I'm just wondering what you think is driving that dislocation between public equity and maybe just these one-off asset deals?

I just -- I think the Permian feels a little frothy to me right now.

And we'll see where does it shake out.

There are a lot of folks chasing those volumes.

And so I think they're just out there.

We're not going to do a 20x deal.

It's pretty simple.

I mean, we looked at those deals and we passed on those deals.

It's just hard to create value when you pay 20x and trade it down to 12 to 15.

So we're not just going to do that.

I do think that what this is telling you, though, is returns have to come up in the midstream space.

And so I think we're just on that cusp of -- I think you're going to see people start partnering in midstream to do projects.

That's kind of the first step.

And you'll see people thinking about acquisitions or mergers in that space.

And so I think that's kind of the logical order of what we're going to see play out over the next, call it, 15 to 18 months in that midstream space.

We still think that there're good opportunities in the Permian.

We think the volumes are going to flow.

I tell you, we haven't said it, but we're still constructive on an additional frac capacity at Sweeny.

And whether we get that done late this year or early next year, I think we still feel pretty good about the ability to get that done.

You think about kind of DCP through the 66 type of assets and offerings that we can offer producers there, I still have good confidence in that.

But yes, it's going to -- we're in a state of flux right now in MLP land, if you want to think about it that way.

And a lot of people are going to be challenged.

Tim?

Yes.

I'd just say that at a 20x multiple you've got to have significant volume growth.

So I think people are really thinking that there's going to be large volume growth or they've got deeper synergies with their existing partner systems.

But that's the only way that we could see that you could do that.

And it's -- from our perspective, there is risk when we look at that.

Yes.

Yes.

That makes sense.

I appreciate those comments.

Second one, staying with the midstream theme here.

Just on PSXP hitting that $1.1 billion run rate.

I'm trying to figure out which sort of camp you guys fit in going forward to achieve that target?

And I guess one way, Greg, as you mentioned, you're sort of within striking distance of it now.

But one way to look at it is you're going to blow right past it and crush it.

Or maybe the other way to look at it is you don't want to create an equity issuance overhang on PSXP equity again, so maybe you just have sort of a nice glide path to that run rate.

Which way is maybe closer to how you're looking at it?

I think we've been pretty consistent.

We're going to be at $1.1 billion run-rate EBITDA at the end of 2018.

And certainly, I think we have assets, the portfolio.

We could blow past -- through that if we wanted to.

But I don't think you'll see us do that.

We'll be consistent with the guidance.

And as you think about post-2018, I think the market's going to tell us how fast to grow, what top quartile really looks like in that.

But the thing we want to emphasize is that we have the portfolio of assets that we can grow at that necessary rate to build value for the unitholders and for the shareholders of PSX.

Faisel Khan from Citigroup.

Tim, I just wanted to go back to one of the -- a couple of comments you made.

On the LPG side, the $0.05 to $100 million sort of number you threw out there, was that just on the LPG loading of sort of the uncontracted capacity?

Or how are you sort of talking about that number?

Well, what we think about it is; a, are there things on the shipping rate, are there things on the loading contract.

And then there's acquisition costs.

We buy on the outside, the propane.

So logistics cost around that, thinking about our product logistics.

And so we've made success on reducing those costs.

So it's a combination of all of the above that you work on.

And then of course, there's always the operating cost of the unit.

But I think what we're really focused on is how do we work on the product realizations and the purchase realization and then also the commercial contract side as a way to drive that.

But that's only -- that's what you have to keep working in trying to increase your spreads in this market.

Okay.

So that was like a blended number on the entire integrated complex (inaudible)

Yes.

That's -- I'm just saying that when you look at the LPG terminal and you look at the volume and you -- $0.05 a gallon is about $100 million, and that's a target we'd like to put out there.

But it's going to take -- it takes a lot of work.

And there are -- but that's where we'd like to see that go.

Okay.

Got you.

And then just on the bottlenecks, you sort of described around Brent TI.

Are you seeing, right now, existing pipeline bottlenecks?

I understand all of the stuff that's left over from the hurricane and from tropical storm Nate.

But is there some sort of existing bottleneck that you're seeing or pointing towards that's telling you that the -- that this is derived for a reason?

I think if you tried to pick up space on one of the pipes today out of Cushing to the Gulf, you would find that the spot rates are higher.

And I think that speaks, too, that there's just a lot of demand for that movement.

And so it's kind of created a market dislocation as a result of that.

When you get new pipes, just in this C league -- I mean, the C league connection sets with enterprise, some of those will begin to alleviate that.

The new pipe order in Memphis will probably start to pull on WTI as well.

But I still think given the export pricing that we're seeing with the strong Brent, you're going to want to move that SA&S.

So it's going to be interesting to watch over time just how valuable that pipeline space continues to be.

Got you.

And then just on the last -- this last financing and drop to PSXP.

I mean, this looks like it solves your run rate of growth to $1.1 billion or pretty close to it by the end of next year.

So do you actually need to do another deal at all between now and the end of next year and to PSXP?

So we do have both organic projects that are maturing to help add to that EBITDA to the $1.1 billion total.

And then we have the capability to supplement that with drop-downs.

And so we anticipate, from an equity standpoint, that anything we need, we could access through the ATM.

But I think this is a market where you try to minimize your access to that to create the most value.

So it's a pretty small gap compared to what we had.

And so we think it's very achievable at a good accretive return back to the LP.

Got you.

And then just last question for me.

The year-to-date, the 8% sort of return on capital employed, I mean, can you just remind us again what your guys' targets are over the long run and where you want to see that number get to?

Especially all the -- with all the projects that are sort of coming to an end here?

Faisal, this is Kevin.

Well, at a minimum, we want to see our return on capital above our cost of capital.

But as you look -- if you look back, historically, would be, and across the entire portfolio, 11%, 12% kind of level.

And that's where we would really expect to see the overall portfolio of assets generating a blended return that gets you back to that range.

Obviously, we'll always stay higher.

And you see different -- the different segments are generating different returns across there.

But I think you're targeting getting back north of 10% as being a reasonable level to be at.

Justin Jenkins from Raymond James.

Okay.

I think we covered most of what I had, but maybe a quick follow-up on the Midstream side.

Greg, you mentioned some frothy deal valuations in the Permian.

But any update out of that area on the organic side with the Rodeo project?

On the Rodeo project -- this is Tim.

I'll just respond.

On that one, still working.

I think it goes back to my comment that we're seeing the customers and producers just kind of deferring decisions until, I think, they sort through options in the energy market.

So I think it's one we just continue to develop a lot of interest out there on both the NGL as well as the crude side.

And of course, DCP just did something on the gas side.

So I think you just have to be thoughtful about where does it fit, and can you drive maximum value to make that accretive.

But the organic piece, if you can put it together, is certainly more accretive, I think than an inorganic acquisition.

Perfect.

I appreciate that, Tim.

And then maybe real quick on the heavier crude differentials side.

I apologize if we've covered this already.

But it seems like a lot of anecdotes on quality issues from Venezuela.

And I think you've shifted away from those barrels.

But any issues with sourcing overall?

And maybe your views towards heavier diffs in 2018.

No.

I -- we would agree on the quality issues out of Venezuela.

Clearly, the OPEC cuts have impacted pretty heavily the heavy grades.

So you're seeing that light -- medium, light heavy differential come in.

But the Canadian crude has filled a lot of that gap.

And so I think there's still -- we've not seen any impact in our system about which crudes and the availability to buy.

But where we buy has shifted significantly around as we look through options for supplies.

So I haven't really seen a limitation on that.

But we would expect that will continue as long as OPEC cuts continue to keep that narrower than what you've seen in the last couple of years on the light heavy spread.

Thank you.

We have now reached the time limit available for questions.

I will now turn the call back over to Jeff.

Thanks, Julie, and thank all of you for your interest in Phillips 66.

If you have additional questions, please call Rosy, CW or me.

Thank you.

Thank you, ladies and gentlemen.

This concludes today's conference.

You may now disconnect.