菲利普斯66 (PSX) 2018 Q3 法說會逐字稿

Welcome to the Third Quarter 2018 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 Third 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 on 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 filing.

Before I turn the call over to Greg, I'd like to point out a change in our question-and-answer session.

Based on investor feedback on how to improve our call and to avoid everyone -- and to allow everyone the opportunity to ask a question, we are asking that you limit yourself to one question and a follow-up.

If you have additional questions, we ask you rejoin the queue.

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

Thanks, Jeff.

Good morning, everyone, and thanks for joining us today.

Third quarter adjusted earnings were $1.5 billion, a record $3.10 per share.

This quarter, we demonstrated the value of our integrated portfolio, contributing strong earnings.

In the Central Corridor, our Refining and Midstream assets ran at record levels, capturing strong margins.

We continued to benefit from advantaged feedstocks as the industry's largest purchaser of heavy Canadian crude.

We achieved record Midstream earnings.

And in marketing, we realized solid margins on refined product sales.

We've repurchased or exchanged nearly 30% of our initial shares outstanding over the last 6 years, contributing to a record adjusted earnings per share this quarter.

We continue our commitment to distributions by returning $775 million through dividends and share repurchases in the third quarter and $5.2 billion for the year.

Strong shareholder distributions remained fundamental to our disciplined capital allocation approach.

We're investing on robust portfolio of projects with attractive returns to create shareholder value and drive future growth.

During the third quarter, Phillips 66 Partners once again achieved record adjusted EBITDA.

PSXP has grown at a rapid pace during its first 5 years.

With its scale and financial strength, PSXP is well positioned to fund and sustain a significant organic capital program to drive future EBITDA growth.

Phillips 66 Partners is the operator and largest owner in the Gray Oak Pipeline project.

Gray Oak will provide crude oil transportation from the Permian and the Eagle Ford to Texas Gulf Coast destinations, including our Sweeny refinery.

Supported by shipper commitments, the capacity of the pipeline will be 900,000 barrels per day and is on schedule to be in service by the end of 2019.

At the Sweeny Hub, we're building 2 150,000 barrel per day NGL fractionators and adding 6 million barrels of storage at Phillips 66 Partners Clemens Caverns.

We have agreements in place with multiple parties, including DCP Midstream, to supply Y-grade to the new fractionators.

The hub will have 400,000 barrels per day of fractionation capacity and 15 million barrels of storage when the expansion is completed in late 2020.

Our Sweeny Hub is strategically located on the Texas Gulf Coast and directly accessible from the Permian.

Gulf Coast fractionation capacity remains tight, and there is strong interest from customers and future expansion projects.

At the Beaumont Terminal, we recently placed 900,000 barrels of fully contracted new crude oil storage into service.

We have an additional crude tanks under construction that will increase the terminal's total capacity to 14.6 million barrels by the end of this year.

During the third quarter, we had about 200,000 barrels per day of exports across our dock.

The continued growth in domestic crude production is expected to result in the need for higher Gulf Coast exports, and we're making investments to capitalize on this opportunity.

At Beaumont, we recently approved a new project to further increase crude storage by 2.2 million barrels with completion anticipated in early 2020.

PSXP also has a 25% interest in the South Texas Gateway Terminal under development in Corpus Christi.

The terminal is connected to Gray Oak Pipeline and will provide 3.4 million barrels of crude storage upon completion in late 2019.

DCP Midstream continues to expand the Sand Hills Pipeline to meet the demand for growing NGL production in the Permian Basin.

DCP increased the pipeline's capacity to 440,000 barrels per day at the end of the third quarter, and further expansion to 485,000 barrels per day is expected by the end of this year.

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

In the high-growth DJ Basin, DCP's Mewbourn 3 gas processing plant started up in the third quarter, and the O'Connor 2 plant is expected to begin operations in the second quarter of 2019.

In Chemicals, CPChem has a leading position in polyethylenes to supply the world's growing demand for polymers.

CPChem's portfolio cost advantage assets are strategically located in the U.S. and the Middle East.

Abundant ethane supplies remain the cost advantage feedstock for U.S. Gulf petrochemicals growth.

CPChem continues to optimize its new U.S. Gulf Coast petrochemicals assets and is developing a second U.S. Gulf Coast project that would include ethylene and derivative capacity.

CPChem is also evaluating additional capacity across multiple product lines through debottlenecks on existing units.

In Refining, we continue to focus on high-return projects to improve margins.

We have an FCC optimization project underway at the Sweeny refinery that will increase the production of high-value petrochemical products and higher-octane gasoline.

This project should complete in mid-2020.

At our Lake Charles Refinery, Phillips 66 Partners is constructing a 25,000 barrel per day isomerization unit.

This new unit will increase production of higher-octane gasoline blend components when completed in the third quarter of 2019.

We're optimistic about future growth opportunities across our businesses.

With growing hydrocarbon production in the shale plays, we see opportunities for further Midstream infrastructure build-out, including pipelines, export facilities and NGL fractionation.

Our Refining system is well positioned to capture low-cost inland crude feedstock, and we see good opportunities for future Chemicals expansion.

We will remain a disciplined allocator of capital.

We'll continue to invest in growth projects with attractive returns that are aligned with our long-term strategy, and we'll continue to provide a strong, competitive, growing dividend and will be a buyer of our shares when they trade below intrinsic value.

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

Thank you, Greg.

Hello, everyone.

Starting with an overview on Slide 4. Third quarter earnings were $1.5 billion.

After excluding special items, adjusted earnings per share was $3.10.

The third quarter adjusted effective tax rate was 23%.

Our year-to-date after-tax return on capital employed was 14%.

Operating cash flow, excluding working capital, was $2.1 billion.

Working capital impacts reduced cash flow by $1.5 billion.

Distributions from equity affiliates were $910 million.

Capital spending for the quarter was $779 million with $537 million spent on growth projects.

We ended the quarter with 461 million shares outstanding.

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

Quarter-over-quarter adjusted earnings increased $134 million driven by higher earnings in Marketing, Midstream and Refining, partially offset by lower Chemicals results.

Slide 6 shows our Midstream adjusted net income, which was a record $261 million in the third quarter.

Transportation adjusted net income for the quarter was $175 million, up $38 million from the previous quarter.

The increase was due to higher volumes, increased pipeline tariffs and storage rates and lower operating costs.

Our operating pipelines in the Central Corridor benefited from strong utilization at our refineries.

In addition, the Bakken pipeline

third quarter throughput averaged more than 500,000 barrels per day.

NGL and Other adjusted net income was $64 million, an increase of $14 million, reflecting increased Sand Hills and Southern Hills pipeline volumes and propane and butane trading activity.

Sand Hills pipeline throughput during the third quarter was a record 421,000 barrels per day.

We continue to run well at the Sweeny Hub.

During the quarter, the export facility averaged 10 cargoes a month, and the fractionator averaged 110% utilization.

DCP Midstream adjusted net income of $22 million in the third quarter is up $7 million from the previous quarter due to increased pipeline volumes, higher NGL prices and improved hedging results.

Turning to Chemicals on Slide 7. Third quarter adjusted net income for the segment was $210 million, $52 million lower than the second quarter.

Olefins and Polyolefins adjusted net income decreased $70 million due to low margins from higher ethane feedstock costs.

This was partially offset by higher polyethylene sales volumes as CPChem operated at 96% domestic polyethylene utilization and also drew from inventory.

Global O&P utilization was 91% in the third quarter, reflecting planned turnaround activities and unplanned downtime from a third-party power outage that impacted the Cedar Bayou facility.

Adjusted net income for SA&S increased $9 million from improved margins.

The $9 million increase in Other mainly reflects the gain on an asset sale.

During the third quarter, we received $325 million of cash distributions from CPChem.

Next, on Slide 8, we will cover Refining.

Crude utilization was 93% compared with 100% in the second quarter.

Our third quarter clean product yield was 84%, and realized margin was $13.36 per barrel.

Pretax turnaround costs were $55 million, a decrease of $5 million from the previous quarter.

The chart on Slide 8 provides a regional view of the change in Refining's adjusted net income, which increased $48 million in the third quarter.

In the Atlantic Basin, adjusted net income increased as the Humber Refinery returned to normal operations following a second quarter turnaround.

This was partially offset by third quarter unplanned downtime at the Bayway Refinery.

Gulf Coast adjusted net income decreased due to narrowing heavy crude differentials and unplanned downtime at the Alliance Refinery.

Adjusted net income in the Central Corridor was $633 million, an increase of $241 million, reflecting improved heavy Canadian and Permian crude differentials and higher volumes.

Third quarter capacity utilization was 108%.

In the West Coast, the decrease was mainly due to a 25% decline in the gasoline market crack.

Slide 9 covers market capture.

The 3:2:1 market crack for the third quarter was $14.21 per barrel compared with $14.86 in the second quarter.

Our realized margin for the third quarter was $13.36 per barrel, resulting in an overall market capture of 94%, up from 83% in the second quarter.

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

We made less gasoline and more distillate than premised in the 3:2:1 market crack.

Losses from secondary products of $1.62 per barrel were lower than the previous quarter by $1.19 per barrel, primarily due to improved NGL and coke prices relative to crude oil.

Feedstock improved realized margins by $2.50 per barrel, a decline of $0.65 from the prior quarter due to narrowing Gulf Coast heavy crude differentials, partially offset by improvements in the Central Corridor.

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

This category improved realized margins by $0.26 per barrel.

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

Adjusted third quarter net income was $290 million, $95 million higher than the second quarter.

Marketing and Other increased $98 million due to higher realized margins in the U.S. and Europe, reflecting seasonally stronger market conditions.

U.S. Branded Marketing volumes increased 2% sequentially.

We reimaged 384 domestic marketing sites during the third quarter, bringing the total to over 2,100 since the start of our program.

Refined product exports in the third quarter were 190,000 barrels per day.

Specialties adjusted net income decreased $3 million during the quarter from lower base oil margins.

On Slide 11, the Corporate and Other segment had adjusted net cost of $187 million, up slightly from the prior quarter.

Lower interest expense was due to a second quarter debt repayment and higher capitalized interest.

Corporate overhead increased primarily from employee severance costs and taxes.

Slide 12 highlights the year-to-date change in cash.

We entered the year with $3.1 billion in cash on our balance sheet.

Cash from operations, excluding the impact of working capital, was $5 billion.

Working capital changes reduced cash flow by $1.6 billion.

This reflects a $1.5 billion use in the third quarter due to an inventory build which included the impact of unplanned downtime at Bayway and Alliance, as well as the timing of crude cargo receipts and payments.

We received $1.2 billion from the first quarter issuance of debt, net of second quarter debt payments.

During the year, we funded $1.6 billion of capital expenditures and investments, and we returned $5.2 billion to shareholders through the repurchase of shares and payment of dividends.

Our ending cash balance was $924 million.

This concludes my review of the financial and operational results.

Next, I'll cover a few outlook items for the fourth quarter.

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

In Refining, we expect the worldwide crude utilization rate to be in the mid-90s and pretax turnaround expenses to be between $110 million and $130 million.

We anticipate Corporate and Other costs to come in between $170 million and $190 million after tax.

In closing, next quarter, we are changing our segment reporting to be on a pretax basis.

Income taxes will only be reflected at the consolidated company level.

This change will make our segment reporting more comparable to our peers.

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

(Operator Instructions) Doug Terreson from Evercore ISI.

Greg, you guys have been a leader in the whole energy industry and pledging to balance your spending and distributions.

And while it's worked very well for shareholders, it obviously starts with disciplined capital spending.

And so on this point, while you may not have your specific guidance yet, I wanted to see if you could provide some color or maybe philosophy that you might have on capital spending for 2019 and beyond.

Yes.

Well, I'd start from the guidance we've given.

Long term, we want to reinvest 60% of cash from all sources back in the business, and 40% goes back to our shareholders through strong dividend and share repurchasing.

And obviously, it's deviating from that, Doug, over the longer term.

Any given year, we could bounce around a little bit.

This year is going to be hard to hit.

We'll hit 60-40, but it's going to be the other way given we're already at $5.2 billion of share repurchases for the year.

But there's no question, I think.

We're working the capital budget for 2019 now.

We go to our board in December for approval, so I don't want to get too far out ahead of that.

So we got Gray Oak and the fracs.

And of course, Gray Oak, even though it's a PSXP, it gets consolidated up in the PSX.

So at the consolidated level, we're probably looking at something between $2 billion and $2.5 billion in '19.

But we'll tell you what the number is when we get to the board in December.

Neil Mehta from Goldman Sachs.

I had 2 quarter-specific questions but also then wanted to see if we could extrapolate them forward.

And so if I think about where the driver -- in fact, one of the big drivers of outperformance versus our model, it was in the Midcon and your Central Corridor business.

So can you talk about how you see that outlook going into the fourth quarter and into 2019 as well?

And there are a lot of components to that question, so your views on Brent-WTI, Western Canadian crude and also just gasoline margins in the region.

And then I have a follow-up.

Okay.

That was 5 questions packed into 1, Neil, but we'll try to deal with it.

So let me just start at the high level, and I'll have Jeff step in and kind of give our views.

So I think, first of all, no question, large differentials on WCS.

But also, WTS differentials were strong in the quarter.

We're able to capture that at Borger and, to some degree, into Ponca.

And we ran really well, so 108% capacity utilization.

So where we needed to run really well, we ran well and we're able to capture that opportunity.

And I'll let Jeff comment on our future views in terms of WCS spreads.

Yes.

So PSX is the largest importer of Canadian crudes, and we benefit from these wider discounts.

Production growth is continuing to exceed infrastructure development, production up roughly 300,000 barrels a day, both in 2017 and '18, with further growth coming in 2019 as well.

The pipelines are full.

Enbridge Line 3 is the next one lined up for year-end.

Next year, it's only 370,000 barrels a day incrementally.

And then Keystone and Trans Mountain are kind of 2022-plus.

For the time being, the rails are full as well.

When you look at the DOE stat for Canadian imports, we've imported right at 200,000 barrels a day for the last 4 months.

That looks to be about what we can do at this point as an industry.

There are some long-term contracts that have been signed, and we expect the rail capacity to increase later this year, and really, more so next year.

Canadian storage is at record high levels, and it typically rises during the fourth quarter.

So things continue to be tight with Canadian differentials.

And then the other area was Marketing.

The -- you guys put up very strong results.

I guess there's a seasonality element to that, but it seems like gasoline wholesale margins held in as well.

So just talk about your view for the Marketing and Specialties business.

And can we carry some of the strength forward?

Yes.

So there is seasonal strength there.

The third quarter's got July and August, 2 summer months, with the Fourth of July and Labor Day weekend in there as well versus only 1 month, summer month in the second quarter.

And so there's a big seasonal component there.

When you look at wholesale gasoline prices, they were relatively flat in the third quarter versus more volatility in the second quarter.

And it's easier to push through the margins in a more stable price environment.

We had strong margins in Europe as well, and so really strong performance overall for the Marketing segment.

Neil, this is Kevin.

As you look into 4Q, you would normally expect to see the demand will come off seasonally as it typically does.

And so you would expect weaker results from that segment as you go into the fourth quarter from the third.

Roger Read from Wells Fargo.

Yes.

Just to dive in here, maybe a little bit of a follow-up on Neil's question.

As we think about capture in the Central Corridor and throughputs, so should we generally think about it as it's a Hardisty price adjusted for transportation?

Or is there a component of WCS you get south of the border, doesn't have a price.

I'm just trying to think about it in margin capture potential over the next few quarters until accrued by rail as an opportunity to maybe narrow the differentials up.

So Roger, I think the easiest way to look at this is just on a quarter-on-quarter change in the Canadian heavy discount, 2Q versus 3Q in this case.

And as we go into 4Q, just compare the difference in the discount at Hardisty and factor that in.

We do see about a 30-day lag, and so I think it makes sense to lag that a little bit as well.

But the easiest way to look at that is just sequential changes.

The other thing I'd add is, Roger, we have invested in infrastructure that allows us to capture that.

So we have things at Hardisty.

We've got commitments on pipes coming south, and so I think we're really well positioned to capture that arb when it's there.

Great.

And then the unrelated follow-up.

PSXP, obviously there's been some pressure on Refining MLPs across the space.

You're structured differently in terms of assets and the size of the business.

Just wondering, are you seeing issues where you may ultimately roll PSXP up or that you need to do something about the IDRs?

Just wondering how you're evaluating that business time, a little bit of change maybe overall in the sector.

Yes.

So I'd just point out, we're just -- we're in a different spot than some of the ones that have rolled up.

It's a $1 billion plus EBITDA.

We've grown it at 30% compound annual growth rate.

The distributions on our call later this afternoon for PSXP, we're going to lay out a great organic portfolio of projects that's investable.

We kind of made the pivot from a drop-down story to organic growth story.

PSXP, on its own, has substantial capacity to invest, and so we just look at it as a vehicle to help us grow our Midstream business.

And so we like that component.

We think PSXP is a strong entity and a valuable part of our portfolio.

Now IDRs, this is certainly a topical question, and I don't think we'd go to a meeting that we don't get asked about IDRs and what are we going to do with IDRs.

I would say that we don't think that there's a constraint on growth created by the IDRs today, although we do acknowledge that there's a life cycle to MLPs.

We certainly understand that.

I would say that the path to how you deal with IDRs is a well-worn path and well understood by most people.

And the only guide rails that we would put is we're certainly willing to deal with the IDRs at the appropriate time, but it's going to have to be in a manner that is fair to LP unitholders but also to the PSX shareholders.

So we'll get the IDRs at some point.

Phil Gresh from JPMorgan.

Yes.

First question would just be on Chemicals, Greg.

Obviously, there's been some tightness here on the feedstock cost, and there's been a little bit of pressure on the margin, on the product margin side as well.

Maybe you can just talk about how you're viewing those fundamentals in 2019, how long it will take to resolve some of the fractionation issues.

Obviously, you're going to help contribute to that recovery, but just any thoughts you have.

Yes.

Well, I think 2 in the quarter.

Ethane kind of had a wild ride in the high 30s, more than double, went back down to the high 30s.

And it's below that today.

And I think the industry just had a hard time keeping up with that, so it did cause some margin compression.

And frankly, we always thought with the new units that have come on, 3 so far, that there would be some compression in margins as these materials started hitting the market.

I think the thing that we all missed was how quickly the frac capacity filled up, and it was really that frac capacity filling up that drove ethane prices so quickly and rapidly.

I think the chems did a great job of adjusting their feedstock slates and obviously by cracking more propane and then putting pressure on ethane, and you saw the results on the ethane prices.

But I think we're going to be at this tension point until we can get some more frac capacity on, we'll see some coming on in '19.

There's 2 or 3 fracs coming on in '19 and a couple more fracs, including our frac 2, frac 3, another 300,000 a day in '20.

So I think as we move into '19 and '20, we'd start to resolve that issue around feedstock.

So in the interim, what'll happen is I think the export price of propane sets the ceiling, if you will, in ethane price.

And of course, fuel value is always a 4 on ethane price.

Our view is there's still 600,000 or more a day in rejection across the U.S. So where there's plenty of ethane, we just need the frac capacity, get it out.

And then finally, I'll just say, as we look into '19, we're still constructive in terms of the margin outlook.

Globally, we'd see good demand growth, really globally, but in the U.S., Europe and Asia.

And we just like the supply/demand fundamentals that we see looking out to '19 and '20.

Okay.

Great.

Second question.

I guess this one will be for Kevin since you mentioned it in your prepared remarks.

You talked about as secondary products, that coke, I presume that maybe that's needle coke was the contributor to that margin improvement.

If I look in the Atlantic Basin, your secondary margins were really strong there.

So maybe you can just elaborate on the contribution that you're getting there.

Yes.

So it's a combination.

It's not -- you've got an NGL impact, the strong NGL prices, and you had improved pricing across all grades of coke.

So petroleum coke, anode coke, the needle coke, so a strong pricing across the board, and so that all contributes to that secondary products impact.

Okay.

And do you feel that's sustainable?

Well, that depends on where the markets go.

I mean, that category is -- if you look back over time, that moves around.

It can move around quite a bit in terms of the overall impact on capture, so it will move as market conditions do so.

Bayway was also down during that period of time, and so that probably impacted the amount of deposit direction on secondary products.

Look, I think the coke market globally has improved.

There's no question around that.

We have 2 refineries, certainly Lake Charles and Humber.

They're probably most impacted and influenced, particularly by the specialty-grade cokes.

Over the last 2, 3 years, we've been working to develop new markets for specialty-grade cokes.

One of those is the anodes and lithium ion batteries, and we've made good progress there in developing a new high-valued market for us.

A lot of the other specialty coke goes into art furnace production, and that's tied with the global economy.

And so to answer the question, is it sustainable or not, if the economy continues to do well, I think this business will continue to do well for us.

But it's a relatively small component in the overall mix for Phillips 66.

It was completely overshadowed by the margin improvement we saw in the Central Corridor around -- you think about billings, you think about Wood River and Ponca City and Borger and capturing a $25 spread there.

Phil, I think it's important to note that we have multiple grades of needle coke for many different applications.

And depending on the grade, the quality, the makeup of the needle coke, they trade at different prices.

In addition, for commercial reasons, we don't disclose the duration of our sales contracts which can influence the prices that we capture.

Paul Sankey from Mizuho Securities.

Can we talk a little bit more about Chemicals?

I thought that they would actually be a bit weaker than the results that you achieved.

Could you just give us an outlook for both volumes and margins, your best guess?

That would be great.

Well, specifically to the third quarter, we had a turnaround at Port Arthur on the ethylene side, but we're selling out of inventory.

Ethylene inventories are still relatively high, and that's also leading to some of the margin compression we're seeing in ethylene.

I know in CPChem's case, we actually built inventory to cover the derivative startup from last fall till the new cracker came on.

And the new cracker came on better, quicker and ran higher rates than we expected.

And so we've been adjusting inventories at CPChem to bring ethylene inventories down.

So then you come back and you think about, "Okay.

What's happening going into next year?" The sales volumes are still strong.

Polyethylene sales volumes were up quarter-over-quarter.

We're seeing strong demand growth in really across all regions, Paul.

So I would say we're constructive on the outlook for margins going into 2019.

Are you hitting maximum volumes now, Greg, in terms of your sales?

I think the -- certainly, the Middle East assets are running at capacity.

We had a global O&P rate of 91%, but that was influenced by the Port Arthur turnaround.

Then we had a power outage at our Cedar Bayou facility which took down the new cracker and the old cracker at Cedar Bayou, so that really impacted O&P rates.

But I would -- we've given guidance kind of mid-90s for the fourth quarter, and I think we feel pretty comfortable with that guidance.

Great.

And then the follow-up is just on gasoline.

Again, the Marketing exceeded our expectations, which is I find it a little bit counterintuitive if we're in generally in a rising price environment.

And don't know if there's anything to add on that.

But if additionally you could talk a little bit about what looks like very weak gasoline market at the moment and whether that's a transitory effect or really what's going on there?

Yes.

I think as you look at New York Harbor gasoline trading at $8 a barrel crack, that's the weakest in 2 years.

New York Harbor distillate is trading at $29 a barrel.

That's a 7-year high, so we're definitely seeing that split.

Seasonality is a big factor with the RVP change.

Butane is coming into the blending pool.

Gasoline inventories are high, even relative to seasonal norms.

What we're seeing is more pressure in the Atlantic Basin, especially on the European side of the Atlantic.

Simple refining margins in Europe are negative, and we are starting to see economic run-cuts in Europe.

We are, in the U.S., starting to see gasoline imports slow.

Earlier this year, they were running about 800,000 barrels a day, I think falling to 500,000 barrels a day, and recently, only 300,000 barrels a day.

In addition, gasoline exports to South America are improving.

You look at October of 2017 was 700,000 barrels a day.

We're up over 1 million barrels a day this year, so the other side of that equation with strong distillate is encouraging runs on the distillate side.

But really, the U.S. is well positioned relative to the international markets when you think about attractive crude discounts, strong diesel demand in cracks, low fuel and operating costs and competitive taxes that we enjoy here.

And as you look into 2019, 2020, we expect high complexity refining capacity to benefit from the IMO environment and higher runs for high complexity, lower runs for low complexity refining.

Doug Leggate from Bank of America Merrill Lynch.

I actually going to do my questions in reverse given Paul just asked that one.

So I'm going to do a follow-up, Jeff, if I may, and this is probably for you towards this gasoline situation has been an accident waiting to happen given the strength of runs in the U.S. But my question is when you think about export of light sweet crude with Gray Oak and capacity expanding on the Gulf Coast, along with the IMO impact for European refiners, in other words, higher runs.

That combination seems to us to be another threat to gasoline in 2019, the higher runs, lighter yields.

I'm just curious if you can offer your thoughts on how you see the gasoline market improving in an IMO world next year or going into 2020, I guess?

Well, I think the gasoline market is going to be challenged through the winter months.

I think as we shift into next year, there's going to be a focus on emphasizing distillate yields in an effort to improve distillate yields with confidence that, that's a longer-term event with IMO coming as opposed to the U.S. that really tries to maximize gasoline yield in the summer months.

It's certainly possible that we could have maximizing diesel yields year-round for the next number of years, and so we're looking at those yields shifting as IMO approaches.

Feedstock -- FCC feedstock is a good marine blending component which could have the impact of reducing FCC runs as well.

And shifting more product yield into distillate and out of gasoline, I think that's how we get out of this.

But gasoline is probably going to be soft through the winter months.

I appreciate that.

I'll maybe take the rest of that one offline.

But my follow-up is for Greg.

And Greg, you're going to hate this because I ask it every couple of quarters, I guess, and it's really the split between the dividend and the buyback.

And I want to be very specific.

And we agree with you that your stock is undervalued, but you never tell us what your number is.

We, unfortunately, have to publish a number, so we're kind of out there and exposed, so to speak.

But the point is that you're not immune to the seasonality, the weakness, the market weakness and all the rest of it.

So my question is are your buybacks -- are you committed to ratable buybacks?

Are you a bit more discerning on when you execute your buyback program?

And in this environment, why wouldn't you swing the benefit of your diversified portfolio back towards more of a dividend cut than a buyback cut in terms of the cash?

And I'll leave it there.

Well, so we've never contemplated cutting the dividend.

So as...

No, no, no.

what I mean is the split.

When I say cut, I mean, like which way it cuts in favor of dividend versus in favor of buybacks.

Bad choice of phrase, sorry.

It was the Scottish definition of cut that got me.

Okay.

So look, I think we've consistently kind of guided to $1 billion to $2 billion of share repurchase a year the past couple of years.

Obviously, this year we had an opportunity in February to take a big swing with Berkshire and we did.

But I think that guidance is still a pretty good guidance going forward.

Look, we look at the spot price every quarter.

We have a grid.

We reset that grid every quarter, Doug.

So in the past 2 weeks, we've been buying a lot more stock than we would normally buy as the share price fell, and I think you'd want us to do that.

But we look at that every quarter.

And as I think out into 2019 kind of that $1 billion to $2 billion consistent range of share repurchases would be the guidance that we'll give for '19 also.

Yes.

I guess that's what I was looking for.

The discernibility is what I was looking for.

Prashant Rao from Citigroup.

I wanted to circle back on cash flows and particularly cash flow from operations.

One of the step-ups that we saw Q-on-Q in the equity affiliate distributions and seems to become -- being a more material part of CFFO.

Wanted to get a sense, and I don't want to front-run anything here to say on the PSXP call but maybe just sort of to get a sense of where that cadence could move as we sort of model cash flows going forward and think about how much that could be an offset to maybe CapEx needs coming up, both in the Midstream and then maybe further on in Chemicals.

Yes.

This is Kevin.

I mean, fundamentally, the way that -- what drives the distributions from the equity affiliates are the operating cash flows within the equity affiliates, less in the case of CPChem, WRB, less the capital spending that they're undertaking at the -- at that level, at the JV level.

In the Midstream, it's a little bit different because most of those affiliates are distributing most of their operating cash flow, if not all.

And then the growth capital, the expansion capital is being funded by contributions back into those entities.

So you've seen a robust distribution so far this year, so just over $900 million in the third quarter.

The year-to-date through the third quarter is just over $2 billion of distributions coming out.

And so you think about WRB, which both refineries have benefited very well from the sort of overall crude differential environment that we're sitting in, and WRB will essentially distribute most of its cash.

There's no incentive.

Neither owner is incentivized to have the partnership sit on more cash than it needs to fund its ongoing operations, so that's part of it.

As WRB does well and so the cash distribution is coming back, we'll do so.

With CPChem, some of this has been a function of the capital spend has come off significantly with a big project complete.

That's all behind us now.

And so that capital spending program, this year, is quite a bit lower than it had been.

And so they're in a position to continue with pretty healthy distributions.

We had guided to -- for CPChem, $600 million to $800 million of distributions for the year.

We've done $725 million through the third quarter, and it's certainly possible.

It could be another distribution coming in the fourth quarter, so pretty healthy outlook from that standpoint.

And then just a quick follow-up.

Kevin, I apologize if you did detail this in your prepared remarks.

But the working capital swing that we saw in the quarter, should we expect most of that to reverse out next quarter?

And so for the full year, we sort of end up breakeven on that volatility.

Or if there is something -- anything that sort of might be residual that we should be mindful of?

No.

I think that's reasonable assumption.

It's always hard to get forecast working capital with too much precision given the amount of moving parts that are all within that.

But high level, we would expect that to reverse.

And so the full year working capital is something reasonably close to breakeven.

Paul Cheng from Barclays.

Two quick questions.

First, on the needle coke, is there any capability for you guys in the short term, say, within the next 6 months or so be able to increase the production on that?

And also then on the medium term, do you have any plan to increase the capacity?

The Refining -- the coke businesses within the Humber Refinery and the Lake Charles Refinery, so it shows up in our Refining portfolio, our Refining segment.

In that segment, we highlight the most important capital projects every year.

And you've seen us with Wood River and Bayway, FCCs, with now the Sweeny FCC.

We highlight all the large capital projects.

And so the fact that we haven't highlighted a large capital project it's probably a reasonable assumption that there's not one.

Right.

I think needle coke is a function of that.

What type of oil that you choose and going into the coking -- into the coker.

So maybe I got it wrong that if the coker, its area, it actually need to be especially designed because I don't think it is.

But maybe then you guys can help me understand maybe better.

Well, we do have industry-leading technology associated with needle coke production.

It is a different process, and so we are very unique in that regard.

Brad Heffern from RBC Capital Markets.

Switching back to Chemicals.

I was wondering, you guys were a little more candid this quarter talking about progressing a second U.S. Gulf Coast project.

Can you give a sense of the time line there, when it could potentially see FID and so on?

Well, as a joint decision with our partner, I think that timing, we've kind of guided to kind of a late '19, early 2020-type FID.

We are progressing work around the site location, the permits required, initial designs around that facility, but I still think that it's late '19 or early 2020 in terms of FID for that facility.

Okay, got it.

And then I guess on the frac capacity side, I was wondering if you could just talk about sort of the path forward for NGL production in the U.S. over the next 6, 9 months when there isn't incremental frac capacity in Mont Belvieu.

Do you guys see Y-grade just getting produced in the tanks?

Or does it get rerouted to Conway or Appalachia?

Or how do you see that playing out?

Yes.

I think it's going to be interesting to see how we move forward.

We'll probably see rejection maintained at high levels at the gas plants as people attempt to shift and fractionate the heavier barrels, so I think that rejection will stay relatively high.

I think this will encourage additional NGL pipeline capacity and additional fractionator capacity because supply is likely to continue to grow as we go forward, drilling activities continuing in the Permian.

We're drilling 600 wells a month and only completing 400 wells a month, so the dock inventory is growing by 200 every month.

Once the infrastructure comes online, then those completions will accelerate and fill the infrastructure.

So I think we're going to add supply, then add infrastructure, then add more supply.

We're kind of in that cycle.

Matthew Blair from Tudor, Pickering, Holt.

I was intrigued by the comments of debottlenecking existing chems units.

Could you give a sense of just the general capacity that you'd be talking about here as well as the timing?

And also, would some of these debottlenecks occur at your brand-new cracker and PE units?

The answer is yes.

I think we probably have room to debottleneck the new cracker.

But we -- across the platform, I would say we have opportunities in some of the older assets of 2 to do some additional debottlenecking.

So we're not going to give a number today in terms of the volumes on that, but I think that CPChem has a great portfolio of opportunities, kind of internal to the existing asset portfolio where they can get some more value out of those assets.

As you know, the debottlenecks are the easiest ones to do, highest-returning projects typically in the portfolio.

So we'll prosecute those.

Right, right.

And then over in Refining, what were your Bakken rail volumes to Bayway, if any, in the quarter?

And how would you expect this to potentially ramp going forward?

Do you see the debottleneck as just a lack of the 117J rail cars?

Yes.

We benefit from Bakken differentials as an owner and shipper on the Bakken pipeline.

We do rail volumes to both the East Coast and the West Coast.

We haven't disclosed those specifically.

We really don't talk about specific refinery feedstock procurement, but we are seeing an acceleration in growth in the Bakken.

Oil production is up over 200,000 barrels a day year-on-year, but it's actually accelerating.

It's up 75,000 barrels a day quarter-on-quarter.

The pipelines are largely full.

The rail logistics are tight.

I think you're right with the new compliant rail cars being a bottleneck there.

We have had some heavy refining maintenance in the Midcontinent this quarter, which will let up as we get into later in November and December.

But we do expect the Bakken differentials to remain wide.

Manav Gupta from Crédit Suisse.

So PSX is one of the global leaders in coking capacity.

Given IMO indicating no chance of a delay, ignoring the administration, would PSX be open to investing in any resid disruption or resid upgrade projects?

I mean, when you look at the Sweeny refinery location, it's right next to Johns Creek.

So you can source a lot more WCS there.

So this could be a good candidate to burn the coker, so just wanted your views on it.

Yes, yes.

So we are the global leader in coking capacity, and we really achieved this through a number of previous investments.

And we are well positioned with our portfolio, higher diesel yields relative to our peers and significant hydrotreating capacity.

So our portfolio is really well positioned without significant future capital investment requirements for the IMO environment.

Okay.

And a quick follow-up.

In the Midcon, besides WCS, did you actually increase an uptake on the Permian crude that helped drive that big delta up?

So PSX benefits from discounts on Permian barrels at its Borger Refinery as well as transporting volume into the Midcontinent in the U.S. Gulf Coast refineries as well.

We also benefit at PSXP from the ownership and the 900,000 barrel at Gray Oak pipeline in the South Texas Gateway facility.

So those were the primary beneficiaries of the wide Permian dis during the quarter.

And we also ran our first train out of the Permian this year around to -- or this quarter around to...

Beaumont.

The Beaumont.

So I think we're doing everything we can around the portfolio to create great value out of these opportunities.

Craig Shere from Tuohy Brothers.

Picking up on Roger's PXP question a bit.

Kind of apart from collapsing the MLP structure or worrying about the IDRs at this point, it seems a lot of industry peers have either gone one direction or the other in terms of to the extent they still have an MLP, putting all their Midstream down there, and then of course, the opposite, which is just consolidating it all back to the parent.

You still have substantial existing assets and major growth projects at the C corp in the Midstream space.

Are you just comfortable having this kind of dual-pronged summit PSXP, summit PCX approach?

Or do you envision a longer-term kind of simplification around how to think about Midstream?

Well, first of all, you're right.

We probably have $700 million to $900 million of EBITDA at the PSX level.

That's MLP-qualifying EBITDA out of $300 million or so that resides in our Refining business today.

We just don't see the need to do that.

We have such a strong portfolio of organic opportunities investable at PSXP, and it has the balance sheet and the capability to execute those projects, that I suspect that it will be a long time before we get to the need to do any drops.

It gives us comfort that we have them there if we need them, but I would just say we're comfortable with the structure.

We think about PSXP as a vehicle to help grow our Midstream business.

I think we said many times we'd be very comfortable if all the investments we were making in Midstream could be executed to PSXP level.

And indeed, we've grown from almost 0 capital budget to $750 million this year.

And this afternoon, we're going to tell you a budget over $1 billion for PSXP over 2019.

So you can see the strategy, it's evolving.

And so it's doing what we need it to do in terms of helping us to grow our Midstream business, and we're comfortable with it.

Fair enough.

And my second question: can you all update a little bit on how the market is looking for incremental LPG export contracting opportunities?

Well, so I would say that our export terminal, which was 150,000 barrel a day design.

We've demonstrated kind of 200,000 barrels a day.

We're running at about 180,000 barrels a day.

Our view -- we're constructive on the export market growth for LPGs.

And indeed, when we look at all the NGLs coming at us out of the Permian, Eagle Ford and the other basins, we're going to need to export LPGs to clear the U.S. markets because the U.S. demand is just not going to grow fast enough to absorb that.

So I think we're comfortable with the growth profile we see out there.

I think a lot of people have questions around tariffs and what tariffs are doing.

What we're seeing is the markets pivoting around the tariffs today.

So we have Chinese buyers that aren't necessarily shipping to China today and then maybe trading out for [Air Gulf Cargo].

But the market is working, in our view, at this point in time.

And I just think, longer term, we will certainly solve the tariff issue.

So I don't think we're concerned about that on a medium to a long-term basis.

So we like the profile we see.

I think the issue is that the asset from our view is still underperforming our expectations, even at kind of this 180,000 to 200,000 barrels a day given where dock fees are.

We think dock utilizations in the U.S. are still around 83%, 84%, let's say.

As we move into '19, we see those utilizations improving, and we think the opportunity to earn fees will improve.

But in this market today, I don't think we would be interested in taking a long-term contract at 6 cents.

From a demand perspective, we see continuing growth in the residential and commercial side for LPGs internationally, especially in Asia, as well as for chemical feedstocks.

And just in summary, would you think that a multiyear economic contracting market could begin to return by second half '19?

Yes.

As utilization of the existing LPG export capability moves from the 80s to the over 90%, we expect that those margins will start to widen out across the dock.

And there will eventually be a need for additional capacity, which will push those margins up and offer some opportunity for contracting.

Chris Sighinolfi from Jefferies.

I just want to quickly circle back on CPChem.

It was really helpful color on the inventory sales in the third quarter and some of the outages' power-related complications you had encountered.

But I guess as we look into future periods, I'm just curious with regard to the inventories you mentioned and as they get normalized, how that might shape the sales profile.

I guess, simplistically, what I'm asking is how much of that excess inventory that you talked about having built up remains to be liquidated and how might that shape what we should think about 4Q?

I think from an industry's perspective, the excess inventory is really an ethylene part, not the derivative part of the chain.

So it's really people making adjustments on the ethylene production side to bring the ethylene inventories back into line.

And I mean, when you look at -- we look at the full chain margin.

And so what you're seeing is the margins really shifted into the derivatives over the last couple of quarters.

And I mean, that's a value being totally integrated from that perspective.

But I suspect that as ethylene inventories kind of come back to more normal, some of that margin shifts back into the ethylene side.

But from a CPChem perspective, they're kind of agnostic because they capture that full value through the chain.

And so managing the inventory is just part of good blocking and tackling and capital discipline around working capital.

So I think that what we fundamentally look at, we look at the Middle East.

Are the assets running?

Is inventory stacking up at the docks?

It's not.

China continues to be a strong buyer, and inventory seemed to be clearing through that system.

And of course, demand in the U.S. appears very good to us fundamentally.

So I just -- we're constructive in our outlook in '19, '20 and '21.

And from a fundamental supply and demand balance issue, we see increasing operating rates, which I think is constructive towards margins as we move forward in that business.

And so I think the comments around inventory are really specific around kind of the third and fourth quarter.

I think as you get into '19, they'll start to clear out in terms of the ethylene side.

Okay.

That's really helpful.

I guess real quickly, just switching gears.

And I don't want to run -- front-run the PSXP call.

But 2 questions, if I could, on Gray Oak.

One is the upsize of initially targeted capacity of 900,000 from 800,000, is that purely just based on additional contract volumes secured?

Or was there something else influencing it?

And then second is, just as Enbridge provided any early indication view as to what it will do with its option, I guess I'm asking the context of your earlier comments regarding capital budgeting, discussions with the board at this point or entering 4Q about what '19 looks like.

Yes.

So I would say there's multiple parties involved in the uplift to 900,000 barrels a day.

The line -- we're building a 30-inch line regardless, and so -- but it was nice to be able to firm up those commitments.

And then certainly Enbridge has an option to come in.

That option expires in November, I think.

And so I think by the fourth quarter, you'll have visibility.

And whether they decide to exercise that option or not, I hope they do.

They're a great partner.

If they don't, we're willing to keep their share.

It's a great project.

So you'll have some more insight into that.

In fact, all the other people that have options to come in to Gray Oak have to do so by November.

If I was going to bet you money on it, I think our ownership is going to be 42.25%.

So I think these people will exercise their options and come into the line.

I know I would.

Thank you for your interest in Phillips 66.

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

Thank you.

Thank you, ladies and gentlemen.

This concludes today's conference.

You may now disconnect.