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. At this time, all participants are in a listen only mode. Later, we will conduct a question and answer session. 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's Q1 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 and A session.
Actual results may differ materially from today's comments. Factors that could cause actual results to differ are included here as well as in our SEC filings. In order to allow everyone the opportunity to ask a question, we ask that you limit yourself to one 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 Q1 were $187,000,000 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 84% capacity utilization, reflecting turnarounds at 5 refineries. We're also impacted by higher than normal unplanned downtime. During the quarter, we distributed $708,000,000 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 $2,700,000,000 We have received all the Army Corps of Engineers permits. We're on track to start up in the Q4 of this year. Phillips 66 Partners owns a 42.25 percent interest in the pipeline.
Gray Oak 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 7,000,000 barrels and up to 800,000 barrels per day of throughput capacity. The project is expected to start up by mid-twenty 20. We had strong operations across our NGL value chain. Our Sweeny Hub achieved record operating performance in the Q1 at both the fractionator and the LPG export facility.
With Freeport Terminal's advantages, including pure port delays, the hub is a well positioned LPG export facility
with a global customer base.
We're expanding the Sween hub with 200 and 50,000 barrel a day NGL fractionators and 6,000,000 barrels of additional storage at Global 66 Partners' Clement and Catharine's. The hub will have 400,000 barrels per day of fractionation capacity and 15,000,000 barrels of storage when the expansion is completed in the Q4 of 2020. Beyond these ongoing projects, there's strong customer interest to support investment and additional fractionation capacity. The Sand Hills pipeline owned 2 thirds by DCP and 1 third 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 Q4 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 2,200,000 barrels. Upon completion in early 2020, the terminal will have a total of 16,800,000 barrels of crude and product storage capability. In chemicals, CPChem increased the capacity of its new ethane cracker to 1,700,000 tons per year, which is 15% above design. A second Gulf Coast project that would add ethylene to driven capacity is under development.
CPChem is also evaluating additional low cost, high return to bottleneck 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 Q2 of 2020. At our Lake Charles Refinery, Phillips 66 Partners is constructing a 25,000 barrel per day octane gasoline wind components. This unit is expected to be completed in the Q3 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 3rd 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 3rd 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 1st 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 Q1 financial results. Adjusted earnings were $187,000,000 and adjusted earnings per share was $0.40 Operating cash flow excluding working capital was $923,000,000 Adjusted capital spending for the quarter was $675,000,000 including $463,000,000 on growth projects. We returned $708,000,000 to shareholders through $364,000,000 of dividends and $344,000,000 of share repurchases.
We ended the quarter with 454,000,000 shares outstanding. Moving to Slide 5, This slide highlights the change in pre tax income by segment from the Q4 to the Q1. Quarter over quarter adjusted earnings decreased $2,100,000,000 driven by lower results in refining and marketing. The Q1 adjusted effective tax rate was 21%. Slide 6 shows our midstream results.
1st quarter adjusted pretax income was $316,000,000 a decrease of $93,000,000 from the previous quarter. Transportation adjusted pre tax income was $203,000,000 down $31,000,000 from the previous quarter due to lower pipeline and terminal volumes driven by lower refinery utilization. NGL and other adjusted pre tax income decreased $32,000,000 from 4th 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 carloads per month on average and the swing fractionator achieved record utilization of 120%.
DCP Midstream adjusted pretax income of $23,000,000 in the quarter is down $30,000,000 from the previous quarter due to 4th quarter hedging results, partially offset by a decrease in operating costs. Turning to chemicals on Slide 7. 1st quarter adjusted pre tax income for the segment was $227,000,000 75,000,000 higher than the 4th quarter. Dolphins and polyolefins adjusted pre tax income was $219,000,000 up $61,000,000 from the previous quarter. The increase reflects lower operating costs driven by 4th quarter turnarounds and maintenance activity and higher polyethylene sales volumes partially offset by lower margins.
Global O and P utilization was 98%. Adjusted pre tax income for SA and S increased $10,000,000 driven by higher earnings from international equity affiliates. During the Q4, we received $200,000,000 of cash distributions from CPChem. Next on Slide 8, we will cover refining. Crude utilization was 84% compared with 99% in the 4th quarter.
During the Q1, 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 $148,000,000 The chart on Slide 8 provides a regional view of the change in adjusted pre tax income, which decreased $2,200,000,000 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 Q1, driven by narrowing inland crude differentials and lower clean product realizations in a rising price environment. Slide 9 covers market capture. The 3.21 market crack for the Q1 was $9.77 per barrel compared to $9.11 per barrel in the 4th 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 make 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. Advantage Feedstock improved real life 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 1st quarter due to clean product realizations, freight and RINs. Moving to Marketing and Specialties on Slide 10.
Adjusted Q1 pre tax income was $205,000,000 $387,000,000 lower than the 4th quarter. Marketing and other decreased $390,000,000 from lower domestic and international margins associated with sharply rising spot prices during the quarter. 4th quarter results benefited from favorable international market conditions and falling spot prices. Refined product exports in the Q1 were 200,000 barrels per day. We re imaged over 300 domestic branded sites during the Q1, 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 $3,000,000,000 in cash on our balance sheet. Cash from operations excluding the impact of working capital was $923,000,000 Working capital reduced cash flow by $1,400,000,000 primarily due to inventory builds. During the quarter, we funded $675,000,000 of adjusted capital spending and returned $708,000,000 to shareholders through dividends and share repurchases. Our ending cash balance was $1,300,000,000 This concludes my review of the financial and operating results.
Next, I'll cover a few outlook items for the Q2. In chemicals, we expect the Q2 global O and P utilization rate to be in the mid-90s. In refining, we expect the Q2 crude utilization rate to be in the mid-90s and pre tax turnaround expenses to be between $70,000,000 $90,000,000 We anticipate 2nd quarter corporate and other costs to come in between $210,000,000 $240,000,000 pretax. With that, we'll now open the line for questions.
Thank you. We will now begin the question and answer session. As we open the call for questions, as a courtesy to all participants, please limit yourself to one question and a follow-up. Doug Terreson from Evercore ISI. Please go ahead.
Your line is open.
Good morning, everybody.
Good morning, Doug. Good morning.
I have a fundamental question. Specifically, looks like kind of sulfur fuel oil traded a couple of standard deviations expensive to Brent since 1998 this quarter due to a variety of factors. But it also seems like as the 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 in Moran, Venezuela, Canada OPEC cuts, etcetera?
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 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 October.
A number of the shipping companies have talked about starting to buy compliant fuel and testing it in the 4th 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. Your line is open.
Good morning, team. So the back half of 2018 was really an exceptional period for operational performance. The same can't be said for the Q1, a lot of planned, but a lot of unplanned outages. So I 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 first of all, we ran lights out in the 4th quarter, but I think we've run kind of rugged in the Q1. Obviously, we had 8% kind of planned maintenance turnaround activity. It was factored in the plan. And we have about 6%, give or take, of kind of unplanned downtime, which is uncharacteristic for us.
We would normally target about 2% unplanned downtime during the quarter. I think as Kevin mentioned in his remarks, it's really around 3 facilities. Wood River, we're coming up from a turnaround, had an issue restarting the crude unit lineup issue, had a pump failure at Los Angeles, both resulted in substantial downtime at both those facilities. And then 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 the design basis. We've gotten the 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 of times in the Q3. I think we've got a technical facility units up and running now.
But you're right. So circa probably $150 ish million of loss profit opportunities for us during the quarter.
Okay. That's helpful. And then 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 lifecycle. 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, we've always kind of used the guardrails are we have to do something that'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. And 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, executing a $1,200,000,000 capital program at PSXP this year.
So it really hasn't impeded on the ability to grow MLP, but we'll get to it now. We'll get there at PSXP.
Appreciate it, guys. Thanks, Ian.
Bill 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 2nd 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 twenty eighteen. As we came into twenty nineteen, we're expecting to grow, albeit probably at a slower rate than what we experienced in 2018 against the backdrop of 3 large cracker startups kind of in the U. S.
In 2018 with the Dow cracker, the CPM cracker and the ExxonMobil cracker. As we look at where we sit today, I think we're constructive of the economy for 2019. Certainly, the Q1 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 was 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 permits and 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 the 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 with CPK. And as you think about that being a, you're building those assets for a multiyear investment in return, and that still is very attractive to 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.
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.
Thanks for the answers. Just shifting gears to your comments there, Jeff, around the NGL pipelines. We've seen 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 cartos 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 it 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.
And we've seen the robust LPG production growth in the U. S. We did have some impact in the Q1 from Houston Ship Channel Fog, but it looks to us the U. S. Supply for LPGs is going to be very robust, and that should support LPG exports.
Roger Read from Wells Fargo. Please go ahead. Your line is open.
Yes. Thank you. Good morning. Good morning, Isaac. I guess 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 the 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 4th quarter and the Q1 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 around, and now we're seeing some exceptions to that. So we'll move with the market and make adjustments if necessary.
Yes, yes. Gasoline was going to
be a byproduct, 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 when 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. Please go ahead. Your line is open.
Hey, guys. Good morning. 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. 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 frozen tax income tax net, I think, was a $179,000,000 benefit on the cash flow statement this quarter. We think about that normally as being about $100,000,000 a quarter of benefit. And so you extrapolate that out, I would say $400,000,000 for the year.
And I would say that $400,000,000 for the year is still where we would be. So we had a couple of sort of non standard items, non routine running through in the Q1. So as you think about the rest of the year, I think you'd still assume we get to that $400,000,000 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 in the 4Q and the 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 don't know if you could talk a little bit about do you have alternatives 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? Thanks.
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 Q2 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's some temporary impacts, and we'll see them wider in the fall.
Thank you.
Doug Leggate from Bank of America Merrill Lynch. Please go ahead. Your line is open.
Good morning, Doug.
Thank you. Good morning, everybody. Good morning, Jeff. Good morning, everyone. Appreciate you getting me on this morning.
I've got one macro and one specific on capital, if I may. And I guess, I'm going to start off, I don't know who wants to take this, but
let me start off with
the macro. 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 as quite constructive for gas needs. So I'm just curious how you guys are thinking about this.
And if I can layer on to that your expectations for industry utilization, given that you no longer have those windfall crude spreads? 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. 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, we were in max diesel mode, I think as an industry in the Q4 and the Q1, yet diesel yields were only 0.5% higher than previous. And so as we look at that 2,000,000 to 2,500,000 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.
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. My follow-up is really just on CapEx. I realize you addressed Gray Oak on your remarks, but the 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 the cash returns. We just want to see how resilient that through the balance of 2019. I'll leave it there. Yes. Doug, it's Karen.
Really two elements to that around the CapEx and the working capital. Let me get on the working capital one first. The large working capital use of cash this quarter, in the Q1, 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 Q1. And then over the course of the year and especially in Q4, 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 $1,400,000,000 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 $675,000,000 for the quarter. So if you extrapolate that out, that is very much in line with our consolidated budget $2,900,000,000 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 $2,900,000,000 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 Credit Suisse. Please go ahead. Your line is open.
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 Senator selling the President timely implementation of IMO 2020, Sanders 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 the 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 ports 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 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. Please go ahead. Your line is open.
Hi. Thanks for taking the question.
Good morning. Good morning.
I wanted to ask the question on M and S. Appreciate that a lot of the headwinds year on Q was really timing and due to the crude prices whipping around and product 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 as you know crude prices are stable? And maybe related to that when we look to the fuel margins, the Q on Q progression, feel like international was a more steep step down. And wondering if there's anything in there versus domestic to really call out and sort of whether or not 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, Mitch. If you look at oil prices at the beginning of the 4th quarter and compare it to the end of the 4th 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 4th quarter.
As you move into the Q1, 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 Q1. You're right on the international margins. In the Q4, there was refinery maintenance in Orion River. Levels were low, which limited logistics.
Our marketing group was very successful maintaining their logistics in serving markets and benefited from wider margins during that period of time. As you look at the Q1, it was somewhat similar to Q1 of 'eighteen and Q1 of 'seventeen, except that it did have a bigger headwind on crude price rise relative to the 1st 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'd say, normal level with avoided the dramatic movement in the flat price environment. And as we head into May and you start hitting the summer driving season, you'd expect to see the more normal seasonal kick
in.
Matthew Blair from Tudor, Pickering, Holt. Please go ahead. Your line is open.
Hey, good morning, Greg, Kevin and Jeff. I want 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, chemistry projects too?
Yes. I'll start and then Jeff and Kevin can help me out. I think and 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 in that execution window is also pretty intense around that.
We purchased repurchased 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, 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?
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 await on that. There's consultants out there who said if we get the tariffs resolved, there's probably a nickel 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 wait 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 out. So I would say that as we sit here today, we're constructive about margins over the next couple of quarters.
And then you add on layer on top of that potential startups in the Q4 of this year or Q1 of next year, which could put a little kind of headwind in our face in terms of moving pricing. But we're I think we're constructive over the next couple of months in margins. Great. Thank you. You bet.
Justin Jenkins from Raymond James. Please go ahead. Your line is open.
Great. Thanks. Good morning, everyone. 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. 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 for. 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 4th frac there.
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. 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 spot basis broken into double digits. I think at $0.10 you can justify new investment. One of the issues we've got is we need to build out frac capacity to fill up that export facility. But today, we're running about 120 a day across the frac run. 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 Mount Bellevue. That's not efficient. So we 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 plans today around the expansion of LPG export.
Got it. Thanks. I think that's what
I was looking for. Appreciate it. You
bet. Jason Gabelman from Cowen and Company. Please go ahead.
I just had a couple of 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 can 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 $1,600,000,000 over that period of time. When you look at the most of that was prior to the new U. S. Gulf Coast project coming online, which is roughly around $600,000,000 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 ethane to polyethylene full chain margin.
Jeff's EBITDA numbers were our share of CPChem's EBITDA, though. Right. And I've always thought, give or take, dollars 0.25 is a pretty good number for ethane to polyethylene full chain margin.
Got it. Thanks. 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 Q2. And based on your guidance, it seems like you guys aren't really participating in that.
So I was 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 it's as Greg and Kevin said early on, our assets are back up and running. Maintenance is relatively light for us this quarter. Turnaround expense $70,000,000 to $90,000,000 for the 2nd quarter, which is relatively light for us. I would agree there's still a lot of maintenance ongoing, especially in the Mid Continent industry wide and 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. Please go ahead. Your line is open.
Hey, everyone. 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 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 pipe lines 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 will 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 types 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, I think, yes, longer term, I think we'll have sufficient export facility over time.
Okay. Thanks for that, Jeff. 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 co 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 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 of $100,000,000 at this point in time. And you asked a great question about how much CapEx are, 1, put at risk and, 2, a business that requires essentially a government mandate. And so I think 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 of $100,000,000 to work in this area it's 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.
Thanks. Appreciate the answers.
You bet.
Frank Shere from Tuohy Brothers. Please go ahead. Your line is open.
Hello. Thanks for letting me in.
Hi, Craig.
Two quick questions. 1 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 derisking margins with renewed multiyear 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 100 and 50,000 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 that it's you start to push into double digits. I think that, that often 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.
Thank you. We have now reached the time limit available for questions. I will now turn the call back over to Jack.
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.