菲利普斯66 (PSX) 2019 Q1 法說會逐字稿

Welcome to the First Quarter 2019 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 Phillips 66 First 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 filings.

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

Thanks, Jeff.

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

Adjusted earnings for the first quarter were $187 million or $0.40 per share.

Our diversified portfolio delivered positive earnings in a weak market environment.

Depressed gasoline margins and narrow heavy crude differentials significantly impacted our refining results.

Refining operated at 84% capacity utilization, reflecting turnarounds at 5 refineries.

We were also impacted by higher-than-normal unplanned downtime.

During the quarter, we distributed $708 million to our shareholders.

Disciplined capital allocation is fundamental to our strategy, and we'll continue to return capital to our shareholders.

We expect to deliver another double-digit dividend increase this year.

We continue to buy back shares when they trade below intrinsic value; we're buying today.

During the quarter, we advanced our robust portfolio of attractive projects across our businesses.

At PSXP, we made progress on the Gray Oak Pipeline.

This 900,000 barrel per day pipeline will transport crude oil from the Permian and Eagle Ford to Texas Gulf Coast destinations.

Construction continues on the 850 miles of pipeline and the 17 facilities.

We are experiencing cost pressures from higher steel prices, labor rates and right-of-way.

The total cost of the project is now expected to be approximately $2.7 billion.

We have received all the Army Corps of Engineers permits.

We're on track to start up in the fourth quarter of this year.

Phillips 66 Partners owns a 42.25% interest in the pipeline.

Rails will connect with multiple terminals in Corpus Christi, including the South Texas Gateway Terminal in which PSXP has a 25% ownership.

The marine terminal will have 2 deepwater docks with initial storage capacity of about 7 million barrels and up to 800,000 barrels per day of throughput capacity.

The project is expected to start up by mid-2020.

We had strong operations across our NGL value chain.

Our Sweeny Hub achieved record operating performance in the first quarter at both the fractionator and the LPG export facility.

With Freeport Terminal's advantages, including fewer port delays, the hub is a well-positioned LPG export facility with a global customer base.

We're expanding the Sweeny Hub with 2 150,000 barrel a day NGL fractionators and 6 million barrels of additional storage at Phillips 66 Partners Clemens Caverns.

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

Beyond these ongoing projects, there's strong customer interest to support investment in additional fractionation capacity.

The Sand Hills pipeline, owned 2/3 by DCP and 1/3 by Phillips 66 Partners, supplies feedstock to the fractionators at the Sweeny Hub.

During the quarter, the pipeline achieved record volumes of 494,000 barrels per day following its fourth quarter expansion.

We're making investments at our Beaumont Terminal to capitalize on the continued growth in Gulf Coast crude exports.

Construction is underway to increase crude storage by 2.2 million barrels.

Upon completion in early 2020, the terminal will have a total of 16.8 million barrels of crude and product storage capability.

In chemicals, CPChem increased the capacity of its new ethane cracker to 1.7 million tons per year, which is 15% above design.

A second Gulf Coast project that would add ethylene and derivative capacity is under development.

CPChem is also evaluating additional low-cost high-return debottleneck opportunities.

In refining, we have an FCC upgrade project underway at Sweeny that will increase production of higher-value petrochemical products and higher-octane gasoline.

This project is planned to be complete in the second quarter of 2020.

At our Lake Charles refinery, Phillips 66 Partners is constructing a 25,000 barrel per day isomerization unit to increase production of higher-octane gasoline blend components.

This unit is expected to be complete in the third quarter of this year.

We have a portfolio of renewable projects under development that leverage our existing infrastructure, supply network and capabilities.

Waste fats, recycled cooking oils and other renewable feedstocks will be used for diesel production.

We have a project underway at our Humber Refinery and we're developing a project at our Ferndale Refinery.

In Nevada, we have supply and offtake agreements with third-party facilities.

We're also evaluating renewable fuel opportunities at our California refineries.

In closing, we're honored that 6 of our refineries were recently recognized by the AFPM for their 2018 safety performance.

The Ponca City Refinery received the Distinguished Safety Award.

This is the highest annual safety award in our industry and the third year in a row that one of our refineries has received this honor.

Ferndale, Los Angeles, Billings, Borger and Santa Maria sites were also recognized for their top-tier safety excellence.

In chemicals, AFPM recognized 5 CPChem facilities for industry-leading safety performance.

In midstream, Phillips 66 and DCP Midstream received first-place awards in their respective divisions from the Gas Processors Association for outstanding performance in 2018.

We're very proud of our employees' commitment to safety and we'd like to congratulate them on a job well done.

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. We summarize our first quarter financial results.

Adjusted earnings were $187 million and adjusted earnings per share was $0.40.

Operating cash flow, excluding working capital, was $923 million.

Adjusted capital spending for the quarter was $675 million, including $463 million on growth projects.

We returned $708 million to shareholders through $364 million of dividends and $344 million of share repurchases.

We ended the quarter with 454 million shares outstanding.

Moving to Slide 5. This slide highlights the change in pretax income by segment from the fourth quarter to the first quarter.

Quarter-over-quarter adjusted earnings decreased $2.1 billion driven by lower results in refining and marketing.

The first quarter adjusted effective tax rate was 21%.

Slide 6 shows our midstream results.

First quarter adjusted pretax income was $316 million, a decrease of $93 million from the previous quarter.

Transportation adjusted pretax income was $203 million, down $31 million from the previous quarter due to lower pipeline and terminal volumes driven by lower refinery utilization.

NGL and Other adjusted pretax income decreased $32 million from fourth quarter inventory impacts, partially offset by higher Sweeny Hub results.

We continue to run well at the Sweeny Hub.

During the quarter, the Freeport LPG Export facility loaded a record 11 cargoes per month on average, and the Sweeny fractionator achieved record utilization of 120%.

DCP Midstream adjusted pretax income of $23 million in the first quarter is down $30 million from the previous quarter due to fourth quarter hedging results, partially offset by a decrease in operating costs.

Turning to chemicals on Slide 7. First quarter adjusted pretax income for the segment was $227 million, $75 million higher than the fourth quarter.

Olefins and Polyolefins adjusted pretax income was $219 million, up $61 million from the previous quarter.

The increase reflects lower operating costs driven by fourth quarter turnaround and maintenance activity and higher polyethylene sales volumes, partially offset by lower margins.

Global O&P utilization was 98%.

Adjusted pretax income for SA&S increased $10 million driven by higher earnings from international equity affiliates.

During the fourth quarter, we received $200 million of cash distributions from CPChem.

Next on Slide 8, we will cover refining.

Crude utilization was 84% compared with 99% in the fourth quarter.

During the first quarter, we had turnarounds at our Sweeny, Ponca City, Lake Charles, Borger, and Humber Refineries.

In addition, there was unplanned downtime at the Bayway, Wood River and Los Angeles refineries.

These facilities are now back online.

The clean product yield was 85% and pretax turnaround costs were $148 million.

The chart on Slide 8 provides a regional view of the change in adjusted pretax income, which decreased $2.2 billion with lower results in all regions.

The decrease is due to lower realized margins and volumes.

Realized margins were down 56% to $7.23 per barrel in the first quarter driven by narrowing inland crude differentials and lower clean product realizations in a rising price environment.

Slide 9 covers market capture.

The 3:2:1 market crack for the first quarter was $9.77 per barrel compared to $9.11 per barrel in the fourth quarter.

Our realized margin was $7.23 per barrel and resulted in an overall market capture of 74%.

Market capture was impacted 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 $0.63 per barrel increased by $0.34 per barrel from the previous quarter due to declining NGL prices relative to crude.

Advantaged feedstock improved realized margins by $2.08 per barrel, which was $1.71 per barrel lower than the prior quarter due to narrowing Canadian crude differentials.

The other category reduced realized margins by $3.73 per barrel in the first quarter due to clean product realizations, freight and RINs.

Moving to Marketing and Specialties on Slide 10.

Adjusted first quarter pretax income was $205 million, $387 million lower than the fourth quarter.

Marketing and Other decreased $390 million from lower domestic and international margins associated with sharply rising spot prices during the quarter.

Fourth quarter results benefited from favorable international market conditions and falling spot prices.

Refined product exports in the first quarter were 200,000 barrels per day.

We reimaged over 300 domestic branded sites during the first quarter, bringing the total to approximately 2,900 since the start of our program.

Slide 11 shows the change in cash during the quarter.

We entered the quarter with $3 billion in cash on our balance sheet.

Cash from operations, excluding the impact of working capital, was $923 million.

Working capital reduced cash flow by $1.4 billion primarily due to inventory builds.

During the quarter, we funded $675 million of adjusted capital spending and returned $708 million to shareholders through dividends and share repurchases.

Our ending cash balance was $1.3 billion.

This concludes my review of the financial and operating results.

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

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

In refining, we expect the second quarter crude utilization rate to be in the mid-90s and pretax turnaround expenses to be between $70 million and $90 million.

We anticipate second quarter corporate and other costs to come in between $210 million and $240 million pretax.

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

(Operator Instructions) Doug Terreson from Evercore ISI, please go ahead.

I have a fundamental question.

Specifically, looks like high sulfur fuel oil traded a couple of standard deviations extensive to Brent since 1998 this quarter due to a variety of factors.

But it also seems like as we transition storage and demand declines really down by 2020 after the middle of the year, that we should see better spreads for this feedstock.

So my question regards how you expect the market for heavy sour products to evolve in the next couple of quarters.

And then also, how are you finding availability or access of heavy crude supply given the reductions that we've seen from Iran, Venezuela, Canada, OPEC cuts, et cetera?

How are you guys managing that?

Yes.

Thanks, Doug.

We are continuing to have access to the heavy crudes and the overall crude slate that we need to operate.

As you know, we have not been buying Venezuelan crudes since 2017 and the Iranian crudes really go to Asia.

And so we're continuing to see availability there.

As we look at high sulfur fuel oil, you're right.

With the OPEC cuts, much of which was heavy and medium sour crudes with the Venezuelan barrels off the market and the Iranian barrels off the market due to sanctions, we've seen a tightening of the forward curve for high sulfur fuel oil.

If you look back to that 6 to 9 months ago, the forward curve for 2020 was trading about $12 a barrel wider than the 10-year historical discount.

Today, it's closer to a $5 additional discount.

We do expect, as we move into the back part of the year, we're expecting to start converting tanks to compliant fuel in September and October.

A number of the shipping companies have talked about starting to buy compliant fuel and testing it in the fourth quarter.

So we expect those differentials to widen as we hit some of those points in the year.

Neil Mehta from Goldman Sachs, please go ahead.

So the back half of 2018 was really an exceptional period for operational performance.

The same can't be said for the first quarter.

A lot of planned but a lot of unplanned outages, so just wanted to get your temperature on operational excellence and how you feel about the go forward from here.

Yes.

Well, no, I think that -- I mean, first of all, we ran lights out in the fourth quarter but I think we've run kind of rugged in the first quarter.

Obviously, we had 8% kind of planned maintenance turnaround activity that was factored in the plan.

And we had about 6% give or take of kind of unplanned downtime, which is uncharacteristic for us.

We would normally target about 2% unplanned downtime during a quarter.

I think as Kevin mentioned in his remarks, it's really around 3 facilities.

Wood River, we're coming up from a turnaround and had an issue restarting the crude unit lineup issue, we had a pump failure at Los Angeles.

Both resulted in substantial downtime at both those facilities.

And in Bayway, we upgraded the FCC.

We brought that on, the new unit online last year.

It's kind of met the yield structure that we're looking for in terms of a design basis.

We've gotten a throughput through it.

We've never really experienced the resiliency that we expected out of that unit.

We had it up and down a couple times in the third quarter.

I think we've got a technical fix; the unit's up and running now.

But you're right, so circa probably $150-ish million of lost profit opportunities for us during the quarter.

Okay, that's helpful.

And the follow-up is on the Midstream side.

PSXP is one of the few MLPs that still has that IDR structure and just your thoughts on if and when the right time is to sort of clean up that structure given that it's certainly been a big focus from a corporate governance perspective for MLP investors.

Not an unusual question, Neil.

I think we get that a lot.

In fact, someone pointed out to me there's like 3 MLPs that have IDRs and we have 2 of them apparently.

So I think that -- look, I think for PSXP, we understand that MLPs and IDRs have a life cycle.

We also understand that from an investor perspective, they would prefer us to do something with the IDRs.

I think that as we kind of think it through, and we've always kind of used the guardrails are, we have to do something that's -- it's accretive to unitholders and we don't really step on the unitholders, punish them, and we also do something that recognizes the value of the IDR to the PSX shareholder.

So I think we'll thread that needle.

One of the issues we've had is it's been a high-growth MLP.

You think about the cost of capital where we sit today, it really hasn't impeded the growth of PSXP or our executing of $1.2 billion capital program at PSXP this year.

So it really hasn't impeded on the ability to grow the MLP.

But we'll get to it, Neil.

We'll get there at PSXP.

Phil Gresh from JPMorgan.

First question just on chemicals, some of your peers have -- it sounds like they're getting more cautious on the fundamental picture here in 2019, even into 2020 in some cases.

Curious what your latest thoughts are on chemical market fundamentals and how that may or may not impact your thoughts around the second cracker.

Yes.

So I'll take a stab and Jeff or Kevin can come in and fill in.

So you look at 2018, first half year really strong growth, slowing growth in the back half of '18.

As we came into '19, we're expecting to grow albeit probably at a slower rate than what we experienced in 2018.

Against a backdrop of 3 large cracker start-ups kind of in the U.S. in 2018 with the Dow cracker, the CPChem cracker and the ExxonMobil cracker.

As we look at where we sit today, I think we're constructive of the economy for 2019 but certainly, the first quarter GDP results look good to us for the U.S. Europe is showing signs of life.

I think the stimulus is working in Asia, albeit we need to resolve the tariff issue, which we think is sometime early this summer with China.

But having said all that, we've got 2 more big crackers coming at us late this year into early next year.

So I would say that maybe some more margin compression as we get in the back half of this year.

But as you think out between now and 2023, there's more demand growth premise than there is supply additions coming on so we're constructive in terms of the margin outlook.

So I would say good demand fundamentals in the petrochemicals business against a backdrop of some capacity coming on.

And we continue to like the CPChem position of advantaged feedstocks in the Middle East and the U.S. Gulf Coast.

So I don't know, Jeff or Kevin, you guys want to fill in on that, but...

No, I think fundamentally, it doesn't change our view on the next major capital project of CPChem as you think about that being a -- you're building those assets for a multi-year investment and return and that still is very attractive to us.

Yes, I know that some of our peers have had a less-than-rosy outlook, let's say.

Their portfolios are different.

They have more exposure in Europe and Asia than CPChem does.

And so I still think CPChem is really well positioned from a portfolio standpoint.

If you look at the benefits of U.S. ethane and we've got production continuing to grow rapidly, NGL is up over 500,000 barrels a day year-on-year and ethane is about half of that, we've had additional industry pipeline capacity added from the Permian to the Gulf Coast with more to come later this year and 2 additional fractionators coming online.

So the supply advantages for ethane continue to look strong.

Just shifting gears to your comments there, Jeff, around the NGL pipelines.

Seeing a lot of buildup in propane on the Gulf Coast, propane inventories, and you guys have been running pretty well at the LPG export facility, 11 cargoes per month.

How are you viewing the fundamental picture on propane exports and margins given your exposure to that arb as we look here in the second half of the year?

Is this sustainable in your view?

Yes, I think there are reasons for optimism there.

We're continuing to see strong Asian demand.

As you know, we market to other parts of the world as well.

Export facilities -- LPG export facilities are running at pretty high utilization, which is helping margins.

We've seen the robust LPG production growth in the U.S. We did have some impact in the first quarter from Houston ship channel fog, but it looks to us the U.S. supply is -- for LPG is just going to be very robust and that should support LPG exports.

Roger Read from Wells Fargo.

Just maybe if we could hit a little bit, the one other refiner that's reported so far mentioned that they were no longer in a max diesel mode, and I was wondering, as you're looking at the summer and a better balance between gasoline and diesel margins, how you're set up for the near term here?

Yes, we ran in max diesel mode in the fourth quarter and the first quarter given the strength in diesel cracks relative to gasoline.

It's really a factor of looking at our linear programs which we run across the portfolio, each refinery can run differently.

We are seeing strength in gasoline cracks especially in the West Coast.

And so we've increased gasoline focus there but we'll really be driven by the LPs and max feedstocks and yields as the year unfolds.

In February, it looked like the industry was going to need to be in max diesel mode year-round and now we're seeing some exceptions to that.

So we'll move with the market and make adjustments as necessary.

Yes, yes, gasoline was going to be a by-product, I remember.

One other thing is slightly different from path -- from just the refining yield side.

Crude exports and all the crude pipelines coming to the coast, obviously, I know and we've talked before, there's been discussions about, from an infrastructure standpoint, being involved in crude exports not just at the port facilities but these potential loadings of the VLCCs.

I was just wondering, any update on that?

Anything you see there that's interesting or any thoughts on timing of when one of those VLCC loading ports might be available?

As you know, we're involved at Beaumont with crude and product exports.

We're participating at Corpus Christi in the South Texas Gateway facility that will serve the Gray Oak Pipeline.

We're continuing to look at VLCC opportunities but we don't have anything to announce at this point.

Blake Fernandez from Simmons Energy.

First question, this probably goes to Kevin but the cash flow was fairly strong in the quarter at least compared to our expectations if you strip out the working capital changes.

And it looks like part of that is due to some deferred income tax benefit, which is higher than normal.

I didn't know if you could elaborate a little bit on how we should think about that going forward.

Yes, Blake, you're right.

The deferred income tax benefit, I think, was a $179 million benefit on the cash flow statement this quarter.

We think about that normally as being about $100 million a quarter of benefit.

And so you extrapolate that out, that would say $400 million for the year.

And I would say that $400 million for the year is still where we would be.

So we had a couple of sort of nonstandard items, nonrepeating running through in the first quarter.

So as you think about the rest of the year, I think you'd still assume we get to that $400 million level for the full year.

Got it, that's helpful.

Jeff, just going back to Doug's initial question on the heavies.

I can appreciate that things are hopefully going to get better into 4Q and then next year.

But over the next quarter or 2, it seems like the heavy market continues to be challenged.

WCS is obviously fairly compressed.

And given the lagged impact of pricing, I didn't know if you could talk a little bit about do you have alternative to shift away from WCS?

Or is it just fair to think that, that's going to present a bit of a challenge from a capture rate standpoint in the near term?

Well, we do have alternatives to veer away from WCS.

WCS continues to work in many parts of our portfolio.

I think as you -- look, we're probably in the peak of the Canadian production maintenance season right now.

There are a number of production facilities that are down.

We believe some of those have been accelerated into the second quarter because of the mandated cuts.

And we think that's going to peak this quarter.

And as we go into the second and third quarter, we'll have more production in the market.

We expect we'll probably be close to pipeline economics in the second quarter and move towards rail economics in the back half of the year.

When you look at the forward curve, it kind of reflects that expectation.

And so we think it's -- there are some temporary impacts and we'll see them wider in the fall.

Doug Leggate from Bank of America Merrill Lynch.

Appreciate you getting me on this morning.

I've got one macro and one specific on capital, if I may.

And I guess, let me start off, anyone who wants to take this, but let me start off with the macro bit.

Gasoline obviously has staged a little bit of a recovery here but last quarter, yourself and pretty much all your peers were talking about remaining in max diesel mode as we kind of go through the summer.

Now I realize IMO is part of this, but it seems to us that with the somewhat semi-permanent uplift in gasoline yield that, that should be a kind of normal MO going forward, which frankly we see is quite constructive for gasoline.

So I'm just curious how you guys are thinking about this.

And if I could layer onto that, your expectations for industry utilization given that we no longer have those windfall crude spreads and I've got a follow-up on CapEx, please.

Yes.

So I think if you look back to February, and this speaks to the accuracy of the forward curve, but if you look in February, gasoline cracks through the summer were in the $6 to $7 a barrel range in the forward curve whereas today, they're $12 to $13 a barrel.

So there's been a substantial increase with the drawdown in inventories that have been experienced.

Gasoline inventories were at an all-time high in late January and now they're back down below the 5-year average.

So we'll adjust with those changes.

We talked briefly about this but we are seeing an increase in gasoline yield in California as gasoline cracks there have strengthened.

And does that answer your question?

Yes.

I think what I'm really getting at is that last quarter, gasoline was so bad obviously coming into the year, and the expectation obviously is I think some -- there's been some egregious assumptions out there obviously but the expectation is diesel is going to be supported by the shift to IMO.

So I'm just wondering if that means a deliberate bias away from gasoline to the support of the gasoline market is really what I was getting at.

But I take your point in the West Coast.

I guess I'm really thinking more about your industry outlook.

Yes.

So the industry outlook, I think as we see an increase in demand for diesel associated with IMO, that's going to shift refiners into a max diesel mode year-round, which may have been what you were referring to.

I think that may be more common going forward.

I think the other thing is, is we were in max diesel mode, I think, as an industry in the fourth quarter and the first quarter yet diesel yields were only 0.5% higher than previous.

And so as we look at that 2 million to 2.5 million barrels a day of incremental marine fuel demand, I'm not sure how much of that is going to be diesel.

I think a year ago, we thought most of that was going to be diesel.

Now we may be required as an industry to pull some barrels out of the FCC in order to meet that marine fuel market.

The FCCs have a 5% to 10% yield improvement across which reducing FCC utilization would reduce gasoline supply and diesel supply as well.

We don't see that happening in our portfolio.

Our FCCs tend to be larger and more efficient but there may be some in the world that see a lower FCC utilization rate, which could support both the gasoline market and the diesel market, frankly.

Jeff, I've got a quick follow-up on CapEx but I'm delighted you brought that up because that's been our whole thesis on IMO getting a little ahead of itself so I appreciate that.

The -- my follow-up is really just on CapEx.

I realize you addressed rail on your remarks but things are running a little ahead of schedule for this year in terms of the spending cadence, and obviously, you had the big working capital situation.

So I'm just wondering if you could give us a steer as to how you see the net spending profile and the unwind of the working capital playing out through the balance of the year because obviously, a big part of your story remains a cash return.

So we just want to see how resilient the outlook is through the balance of 2019, and I'll leave it there.

Yes.

Doug, it's Kevin.

Really 2 elements to that around the CapEx and the working capital.

Let me hit on the working capital one first.

The large working capital use of cash this quarter in the first quarter is pretty normal for us as we look at the timing of our inventory activity and it's -- we're usually building inventories in the first quarter.

And then over the course of the year and especially in the fourth quarter, you'll see that coming back down.

So for the year as a whole, we still think of working capital being about flat and so you'd expect to recover that $1.4 billion over the remaining quarters of the year, keeping that flat.

On CapEx, I don't know if you picked up on it but on an adjusted basis, which is really the way to think about that is our net cash outlay, we were $675 million for the quarter.

So if you extrapolate that out, that is very much in line with our consolidated budget of $2.9 billion.

Greg talked about the increased cost on Gray Oak.

But when you factor in our net share of that and what actually flows through into this year's spend, we don't think that's going to have a material impact at all on that $2.9 billion.

So at this point, at the PSX level, we're not moving guidance on our capital.

We're comfortable with where we are.

Manav Gupta from Crédit Suisse.

Hey, guys, I have a IMO-related question.

Yesterday, 5 Republican senators led by Bill Cassidy, sent a letter to the President urging him to implement IMO 2020.

There were a couple of lines in the letter which kind of stood out.

The first one was Senators selling the President timely implementation of IMO 2020.

Sand Hills will bring tremendous advantage to our country.

The second line was any attempt by the U.S. to reverse course on IMO 2020 could create market uncertainty, cause harm to the U.S. energy industry.

What I'm trying to understand is why was this letter actually sent.

Is it because these Senators are building support for IMO 2020 because they see the benefits?

Or is it because they're a little worried that the President actually might reverse the course here?

You guys are very close to the ground.

What are you seeing?

Will we see a smooth implementation or do you think there's a possibility of some political risk here?

Well, I think as you look at the different participants in the industry, the IMO itself, insurance companies, banks, the port announcement by the U.S. Coast Guard which you highlighted previously, the courts in China and Singapore are all expressing intentions to strictly enforce IMO on its current timetable.

So I think the participants have been pretty consistent across the board.

I think it's important to the IMO, the benefits to the environment that are associated with the IMO.

When you look at marine fuel, it's about 4% of global demand yet it's about 90% of sulfur emissions.

And so improving the environmental emissions is critical to the IMO.

And I think all signs are that we're moving forward with timely implementation here.

One other thing I would mention, the IMO has its main meeting coming up and the agenda items are really focused on implementation.

Prashant Rao from Citigroup.

I want to ask a question on M&S.

Appreciate that a lot of the headwind Q-on-Q was really timing due to the crude prices whipping around and product inventory builds and all of that.

I kind of wanted to get a sense of maybe how much of that now sort of reverses out as we go forward, assuming crude prices are stable?

And maybe related to that when we look to the fuel margins into the Q-on-Q progression, I feel like international was a more steep stepdown, and wondering if there's anything in there versus domestic to really call out.

And sort of whether that also sort of normalizes now this quarter and as we go through sort of the rest of the year?

Yes.

I think that's a good question.

If you look at oil prices at the beginning of the fourth quarter and compare it to the end of the fourth quarter, oil prices fell by 40%.

That's the largest drop in a quarter in the last 5 years.

So there was a strong tailwind in marketing margins in the fourth quarter.

As you move into the first quarter going from Jan 1 to March 31, there was a 45% increase in crude prices and gasoline cracks widened during that period as well.

And so those were strong headwinds for marketing during the first quarter.

You're right on the international margins.

In the fourth quarter, there was refinery maintenance in the Rhine River.

Levels were low, which limited logistics.

Our marketing group was very successful maintaining their logistics and serving markets and benefited from wider margins during that period of time.

As you look at the first quarter, it was somewhat similar to first quarter of '18 and first quarter of '17, except that it did have a bigger headwind on crude price rise relative to the first quarters of the previous years.

So Prashant, this is -- yes.

I was just going to add that as you look at where we sit in the second quarter on the face of it, we should be back to a sort of more, I would say, normal level with -- avoid the dramatic movement and flat price environment.

And as you head into May and you start hitting the summer driving season, you'd expect to see the more normal seasonal patterns kick in.

Matthew Blair from Tudor, Pickering, Holt.

I wanted to circle back to the cost increase at Gray Oak.

I think you highlighted steel and labor moving higher.

Obviously, Phillips has a pretty robust organic growth slate.

So could you talk about the potential for cost inflation at some of your other projects like the fracs and your other pipes and I guess, potentially even in your Refining and Chems projects, too?

Yes, I'll start and then Jeff and Kevin can help me out.

I think in Gray Oak, first of all, I mean, there's at least 3 pipelines kind of executing in that same window.

And so that has caused some of the escalations we've seen around right-of-way acquisition, certainly the competition for labor and that execution window was also pretty intense around that.

We purchased -- prepurchased most of the pipe itself.

And then on the facilities, we had some exposure on the facilities.

And then I think as you look at the complexity of the project and the execution of that project around the facilities itself and the routing of where they need to be, we probably underestimated some of the facility costs in that original cost estimate.

When we move and we look at the fracs, they're on schedule, they're within budget.

And so we're just -- we're not seeing those same cost pressures around our refining or other Midstream projects.

It seems to be just right around the Permian asset.

Great.

Great.

And then, over on the chem side, so year-to-date, we've obviously seen a pretty big increase in crude prices, but looking at like PE spot export prices, they've hardly changed.

And maybe you could attribute that to high PE inventories or weak demand.

But my question is are you expecting a catch-up on PE prices relative to crude?

Or has something, in your view, structurally changed on this historical link between PE and crude?

No, I think we're probably, in our estimation, maybe running a little bit behind in terms of moving prices globally.

I think there's a lot of factors in there.

I think the Chinese tariffs are definitely a weight on that.

There's consultants out there who say if we get the tariffs resolved, there's probably $0.05 of uplift involved in that.

When you think about China and some of the stimulus they've done, they reduced the VAT tax.

And so a lot of the Chinese buyers just waited until that kicked in so we've seen some reduced activity around that.

And then frankly, they're very astute buyers.

As long as we're in a falling crude price environment, they're waiting for it to bottom and apparently it's bottomed and we're heading back up.

So I would say that as we sit here today, we're constructive about margins over the next couple quarters.

And then you add on layer on top of that potential start-ups in the fourth quarter this year or first quarter of next year, which could put a little kind of headwind in our face in terms of moving pricing.

But I think we're constructive over the next couple months in margins.

Justin Jenkins from Raymond James.

I want to start with a follow-up to Phil's question from earlier on the NGL side.

Got a couple of new fracs coming late next year, maybe another one after that.

I just want to see how you think about the expansion potential at Freeport or even another export terminal beyond that.

Well, on the frac side, we've got 2, 3 well into construction.

We're in discussions about Frac 4 with customers.

And as I indicated in my opening comments, I'd say there's quite a bit of interest around that.

We actually have air permits in hand to build a Frac 4 and if we can nail down the customers on the supply of the frac, which I think we'll probably get to this year, we'll probably FID a fourth frac there.

Now on LPG export, I think that's probably a more challenging one for us.

We've underperformed our own expectations on the LPG export.

We've seen the dock fees come up as utilizations across the industry have come up and we've kind of been expecting that.

And we're probably up, I don't know, 15%, 20% on the fee.

Spot fees are up at around $0.10 today across the dock.

So we've kind of, on a spot basis, broken into double digits.

And I think at $0.10, you can justify a new investment.

One of the issues we've got is we need to build out frac capacity to fill up that export facility.

Today, we're running about 120 a day across the Frac 1, we're yielding maybe 40 a day of propane.

So if we're running 200 a day across the dock, we're bringing the balance out of Mont Belvieu.

That's not efficient so we'd want to match additional LPG export facility with frac capacity in the future.

So we have no plans today other than we're looking at what it would take to debottleneck this facility.

There's nothing firm in our plan today around an expansion of LPG export.

Jason Gabelman from Cowen and Company.

I just had a couple questions.

First, on CPChem.

I wanted to get a better understanding of maybe what the mid-cycle value was of the asset.

It looks like that operations were pretty strong for the quarter despite the weaker margins.

And I'm just wondering using the sensitivity you guys have provided what type of mid-cycle ethylene chain margin we could apply to kind of get an idea of what this thing could generate in cash mid-cycle?

Yes.

So if you look historically at CPChem since the spin, average EBITDA has been about $1.6 billion over that period of time.

When you look at the -- now most of that was prior to the new U.S. Gulf Coast project coming online, which is roughly around $600 million mid-cycle environment.

So I think that would be incremental.

That would be during a period where the polyethylene full chain margins were a little bit higher than where they are today.

So I think you can use the sensitivities to adjust to where you think mid-cycle is, somewhere mid-20s, mid- to high 20s on an ethane to polyethylene full chain margin.

Jeff's EBITDA numbers were our share of CPChem's EBITDA, though.

And I've always thought, give or take, $0.25 is a pretty good number for ethane to polyethylene full chain margin.

Got it.

And if I could just shift to the Refining side of things.

It seems like the industry is going to have elevated maintenance in the second quarter.

And based on your guidance, seems like you guys aren't really participating in that.

So just wondering if you could comment on that, both your operations and what you're seeing industry-wide, and I'll leave it there.

Yes.

I think as Greg and Kevin said early on, our assets are back up and running.

Maintenance is relatively light for us this quarter.

Turnaround expense, $70 million to $90 million for the second quarter, which is relatively light for us.

I would agree there's still a lot of maintenance ongoing, especially in the Midcontinent industry-wide, in the California market as well as the U.S. Gulf Coast.

So there are a number of outages that are planned through at least mid-March in those areas.

Brad Heffern from RBC Capital Markets.

I wanted to go back to Roger's question from a while back.

There's been a lot of discussion about bottlenecks emerging once these long-haul Permian pipes come online like Gray Oak and sort of the time lag between when the pipes come online and when the ultimate export solutions come online.

So I just wanted to get your updated viewpoint on how you see that progressing and do you see a widening Gulf Coast spread environment versus Brent as these pipes come online?

Yes.

I think there's a lot in the mix there.

First, the pipelines are being built often by an operator that's different than the operators of the export facilities.

And so we are seeing, in our own portfolio with Gray Oak scheduled to come on by the end of the year and our South Texas Gateway really not fully up until mid-year 2020.

Now Gray Oak Pipeline does have access to other export facilities at Corpus Christi.

And so there'll be other alternatives there as well as to our Sweeny refinery.

As -- the pace of production growth will determine how full those pipes are, which I think is another part of the equation, is how rapidly do these pipes ramp up.

And then finally, the last leg is export facilities, which appear to be pretty optimally designed but there's, I think, opportunity that there could be mismatches between pipeline availability and export availability.

Longer term -- yes, longer term, I think we'll have sufficient export facility over time.

Okay.

And then I guess I wanted to talk a little bit about renewables.

You guys had that in the press release for the first time, I think.

So I was just wondering if you could talk about maybe the scale of capital that you're devoting to renewable diesel.

And then also talk about sort of your comfort level with investing in something that largely depends on sort of regulatory support.

Yes, that's a great point, Brad.

Yes.

So at the Humber Refinery, we've got a project underway that will add 6,000 barrels a day of renewable diesel through coke processing of used cooking oil.

At Ferndale, we've got a project under development with Renewable Energy Group that's got the potential for 18,000 barrels a day of renewable diesel.

And then finally, we've got an agreement with Rise to provide the feedstock and offtake for up to about 11,000 barrels a day of renewable diesel from plants that are starting up in Nevada later this year and early next year.

So those are the things that are on the immediate front burner.

As you look at our California Refining capacity, it's roughly 350,000 barrels a day, that's total West Coast.

At 40% diesel, that's kind of 130,000, 140,000 barrels a day.

So we're offsetting some of that risk with renewable diesel into the West Coast.

But the CapEx exposure for us is a couple hundred million dollars at this point in time.

And you ask a great question about how much CapEx everyone put at risk into a business that requires essentially a government mandate.

And so I think we're -- you'll see us be kind of careful about that.

Given the way things are structured now, the returns on these projects are very, very attractive.

And so we think putting a couple hundred million dollars to work in this area is certainly appropriate given our portfolio and particularly given our exposure of 300,000-plus barrels a day capacity on the West Coast of the U.S.

Craig Shere from Tuohy Brothers.

Two quick questions.

One, piggybacking on Phil and Justin's LPG export question.

I understand you're not looking at expanding your own export capacity at this point.

But can you talk about prospects for de-risking margins with renewed multi-year contracting?

And the second question is can you update us on your outlook for Latin America product export prospects with all your efforts there?

Yes.

So on exports to Latin America, we're continuing to see Latin American refining utilization at very low levels and we're expecting those to continue.

So Latin America is proving to be a good export market both on the diesel side and the gasoline side.

Some of the Mexico imports have been recovered but not all compared to some of the pipeline outages that we saw earlier in the year, but some of that market has come back.

A lot of that market has come back but not all.

On the LPG export question, we have a combination of long-term and short-term agreements, and our commercial people are constantly in the market trying to optimize the delivery of the volumes that we have in place.

You recall, we started with 150,000 barrel a day expectations.

That LPG export facility has operated much better than that, operating at 180,000 to 200,000 barrels a day of capacity recently.

And so we'll be in the market looking for solid contracts.

Yes, I would say a window is probably starting to open.

When you kind of had spots around $0.06, we obviously didn't want a contract during that period of time.

But as you start to push into double digits, I think that, that optimum window will open for us.

We've had great success in moving the volumes out of the export facility and now we've got to work on the margin side.

We have now reached the time limit available for questions.

I will now turn the call back over to Jeff.

Yes.

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

Please contact Brent or me if you have any questions.

Thank you.

Thank you.

Ladies and gentlemen, this concludes today's conference.

You may now disconnect.