Welcome to the Second Quarter 2018 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 Peters, Vice President, Investor Relations. Jeff, you may begin.
Good morning, and welcome to Phillips 66's Q2 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 materials we will be using during the call today 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. With that, I'll turn the call over to Greg Garland for opening remarks.
Okay. Thanks, Jeff. Good morning, everyone, and thank you for joining us today. Our diversified businesses operated well and delivered strong earnings and cash flows. Adjusted earnings were $1,300,000,000 or $2.80 per share.
Refining had one of its best quarters and ran at 100% capacity utilization capturing strong margins. Our refining system has industry leading coking capacity, which allowed us to benefit from continued favorable heavy crude differentials. We generated $2,400,000,000 of cash from operations during the quarter, which is the highest since 2012. We rewarded our shareholders by returning $602,000,000 through dividends and share repurchases, which brings our total distributions for the year to $4,400,000,000 A secure, competitive and growing dividend is fundamental to our strategy. During the Q2, we increased the dividend 14% resulting in a 27% compound annual growth rate since 2012.
We're executing our long term strategy to capture growth opportunities and enhance returns. Our midstream organization is moving forward with 2 major growth projects, construction of the Gray Oak pipeline and expansion of the Sweeny Hub. Phillips 66 Partners recently completed expansion open season for the Gray Oak pipeline. Gray Oak will provide crude oil transportation from the Permian and Eagle Ford to Texas Gulf Coast destinations, including our Sweeny Refinery. The pipeline will have an initial capacity of 800,000 barrels per day based upon shipper commitments of 700,000 barrels per day and a reservation of walk up capacity for shippers.
Gray Oak is expandable to approximately 1,000,000 barrels per day and is expected to be in service by the end of 2019. Total cost for the project is anticipated to be approximately $2,000,000,000 Phillips 66 Partners will be the largest equity owner in this joint venture project. At Sweeny, we're building 2 150,000 barrel per day NGL fractionators and adding 6,000,000 barrels of storage at Phillips 66 Partners, Clemens Caverns. We have agreements in place with multiple parties, including DCP Midstream to supply the new fractionators. The hub will have 400,000 barrels a day of fractionation capacity and access to 15,000,000 barrels of storage when expansion is completed in late 2020.
We expect robust NGL value chain fundamentals, including continued production growth in the Permian and other shale plays. Our Sweeny hub is strategically located on the Texas Gulf Coast. The hub includes NGL fractionation and storage capacity with access to local petrochemicals on fuel markets and 200,000 barrels a day of LPG export capacity. Both the Freeport Export Terminal and our Sweeny fractionator continue to exceed design rates. At our Beaumont Terminal, we recently placed 1,300,000 barrels of fully contracted crude storage into service, bringing the terminal's total crude and product storage capacity to 12,400,000 barrels.
Additional crude oil tanks are under construction that will increase the terminals capacity to 14,600,000 barrels by the end of the year. We expect the continued growth in domestic crude production will result in higher Gulf Coast exports and our Beaumont terminal is well positioned to capitalize on this growth. DCP Midstream continues to expand the Sand Hills pipeline to meet the demand from the growing NGL production in the Permian Basin. During the Q2, DCP increased the pipeline's capacity to 425,000 barrels per day with further growth 485,000 barrels per day by the end of this year. Our new Sweeny fractionators will be supplied by Sand Hills.
This pipeline is owned 2 thirds by DCP and 1 third by Phillips 66 Partners. Also in the Permian Basin, DCP Midstream has a 25 percent interest in the Gulf Coast Express Pipeline project, which will transport 2,000,000,000 cubic feet per day of natural gas to Gulf Coast markets. Completion of the pipeline is anticipated in the Q4 of 2019. In the high growth DJ Basin, DCP's Mewbourn 3 gas processing plant is expected to start up in the Q3 of 2018 and the O'Connor 2 plant in the Q2 of 2019. In chemicals, CPChem had strong operations from its new Gulf Coast petrochemicals assets, which contributed to solid earnings growth during the quarter.
Bethane crackers demonstrated £3,500,000,000 per year of capacity, which is 6% above the original design rates. In refining, we've approved an FCC optimization project at our Sweeny refinery that will increase production of higher valued petrochemical products as well as higher octane gasoline. This project is anticipated to complete in mid-twenty 20. We've completed FCC modernization projects at the Bayway and Wood River refineries. At both facilities, we upgraded FCC Reactor with state of the art technology.
The units are performing as expected and are yielding higher value clean products. So with that, I'll turn the call over to Kevin to review the financials.
Thank you, Greg. Good morning. Starting with an overview on Slide 4, 2nd quarter earnings were $1,300,000,000 We have special items that netted to a gain of $17,000,000 After excluding special items, adjusted earnings were $1,300,000,000 or $2.80 per share. The 2nd quarter adjusted effective tax rate was 22%. Operating cash flow was $2,400,000,000 This included distributions from equity affiliates of $610,000,000 and positive working capital impacts.
Capital spending for the quarter was $538,000,000 with $348,000,000 spent on growth projects. 2nd quarter distributions to shareholders consisted of $372,000,000 in dividends and $230,000,000 in share repurchases. We ended the quarter with 464,000,000 shares outstanding. Slide 5 compares 2nd quarter and 1st quarter adjusted earnings by segment. Quarter over quarter adjusted earnings increased over $800,000,000 mainly driven by refining.
Slide 6 shows our midstream results. Transportation adjusted net income for the quarter was $137,000,000 in line with the previous quarter. Increased volumes following the completion of 1st quarter refinery turnarounds and higher back end pipeline equity earnings were offset by asset impairments and seasonal maintenance. NGL and other adjusted net income was $50,000,000 down $23,000,000 reflecting positive inventory impacts in the Q1 of about $20,000,000 We continue to run well at the Sweeny Hub. During the quarter, the export facility averaged 10.5 cargoes a month and the fractionator averaged 109% utilization.
While improved, U. S. Gulf Coast to Asia LPG export margins remain challenged. DCP Midstream had adjusted net income of $15,000,000 in the 2nd quarter, a $9,000,000 decrease from the previous quarter. The Q1 included a $9,000,000 benefit due to timing of incentive distributions.
The impact from increased volumes during the quarter was offset by seasonal operating and maintenance costs. Turning to Chemicals on Slide 7. 2nd quarter adjusted net income for the segment was $262,000,000 $30,000,000 higher than the Q1. In Olefins and Polyolefins, adjusted net income increased $23,000,000 from the ramp up of the new ethane cracker and polyethylene units. Global O and P utilization was 95% in the 2nd quarter.
Adjusted net income for SA and S increased $14,000,000 from the completion of Q1 turnarounds. CPChem's other adjusted net costs increased due to lower capitalized interest following completion of the U. S. Gulf Coast Petrochemicals project. Next on Slide 8, we'll cover refining.
Crude utilization was 100% compared with 89% in the Q1. Our 2nd quarter clean product yield was 84%. Pre tax turnaround costs were $60,000,000 a decrease of $185,000,000 from the previous quarter. Refining 2nd quarter adjusted net income was $911,000,000 up $822,000,000 from last quarter. Across our regions, the increased earnings were due to higher realized margins as well as higher volumes and lower costs following the completion of 1st quarter turnarounds.
WRB equity earnings also increased this quarter due to the completion of turnarounds at the Wood River and Borger refineries. The market crack increased 13% during the quarter. Our realized margin improved 32% to $12.28 per barrel, up from $9.29 per barrel last quarter. The increased margin capture was primarily due to the widening Brent WTI spread, discounts on U. S.
Inland crudes and improved heavy crude differentials. Capitalizing on our integrated infrastructure and supply network, we sourced more advantaged crudes into our refining system in response to widening differentials. Slide 9 covers market capture. The 3.2.1 market crack for the 2nd quarter was $14.86 per barrel compared to $13.12 per barrel in the 1st quarter. Our realized margin for the 2nd quarter was $12.28 per barrel, resulting in an overall market capture of 83%, up from 71% in the 1st quarter.
Market capture was impacted in part by the configuration of our refineries. We made less gasoline and more distillate than premised in the 3.21 market crack. Losses from secondary products of $2.81 per barrel were higher than the previous quarter by $1.34 primarily due to rising crude prices. Feedstock improved realized margins by $3.15 per barrel, which was $1.52 per barrel better than the prior quarter due to improved crude differentials. The other category mainly includes costs associated with product differentials, RINs, outgoing freight and inventory impacts.
This category reduced realized margins by $0.75 per barrel compared with $2.08 per barrel in the prior quarter. The improvement was driven by lower RIN costs and improved clean product realizations. Let's move to Marketing and Specialties on Slide 10. Adjusted second quarter net income was $195,000,000 $21,000,000 higher than the 1st quarter. In Marketing and Other, seasonally higher volumes and improved West Coast and Central region margins contributed to increased earnings.
We re imaged over 250 domestic marketing sites during the quarter, bringing the total to over 1700 since the start of the program. We continue to see strong export demand during the quarter with 200,000 barrels per day of refined product exports. Specialty's adjusted net income increased $5,000,000 from improved base oil margins. On Slide 11, Corporate and Other segment had adjusted net costs of $183,000,000 this quarter compared with $162,000,000 in the prior quarter. The $21,000,000 increase reflects higher interest expense and taxes.
Slide 12 highlights the change in cash during the quarter. We entered the quarter with $842,000,000 in cash on our balance sheet. Cash from operations excluding the impact of working capital was $1,700,000,000 Working capital changes increased cash flow by $692,000,000 primarily from increased net payables as refining returned to normal operating levels following the Q1 turnarounds. During the quarter, we funded $538,000,000 of capital expenditures returned $602,000,000 to shareholders through dividends and the repurchase of shares and repaid $250,000,000 of debt. Our ending cash balance was $1,900,000,000 This concludes my review of the financial and operational results.
Next, I'll cover a few outlook items for the Q3. In Chemicals, we expect the global O and P utilization rate to be in the mid-90s. This reflects the Cedar Bayou ethane cracker at the recently increased capacity of £3,500,000,000 per year. In refining, we expect the worldwide crude utilization rate to be in the mid-90s and pretax turnaround expenses to be between $60,000,000 $80,000,000 We anticipate corporate and other costs to come in between $170,000,000 $190,000,000 after tax. With that, we'll now open the line for questions.
Thank
Neil Mehta from Goldman Sachs. Please go ahead. Your line is open.
Hey, thanks very much. Good morning, Jeff. Good morning, Greg and Kevin. I appreciate the comments today and congrats on a good quarter. I want to talk a little bit about the captures because they certainly came in better than what we expected on the refining segment.
And can you just help us understand, what drove the delta versus maybe what you guys were even modeling internally? And I suspect part of it has to do with the way we are modeling the crude capture versus the product capture, if that makes sense. You just have a tendency to have more of the crude discounts drop to the pretax margin, but just any of those deltas would be helpful in terms of framing the go forward?
Yes, I think refining performed exceptionally well in the quarter averaging 100 percent utilization. So I think the most important thing is we were up and running well in a strong margin environment. Turnaround expenses were down substantially quarter on quarter and that brought down operating costs. It increased volumes and helped improve yield. We also took advantage through our integrated supply network to capture crudes.
We benefited from the YWTI Brent differential. We benefited from inland crudes trading at steeper discounts, including Canadian heavy, Bakken and Permian crudes as well as improved heavy discounts on the Gulf Coast and on the West Coast as well. We also saw some improvement in product price realizations, especially on the Gulf Coast and in the West Coast as well. And I think finally RINs costs were cut in half during the quarter, so that helped capture rates as well.
That's helpful color. I wanted to build on that WCS point because we've seen the differentials really widen out here. You guys import more WCS than anybody else. So can you just kind of talk about how you see that playing out through the balance of this year and into 2019 ahead of Enbridge Line 3 and before the IMO impact?
Sure. We had the Syncrude outage this summer, which supported WCS temporarily, but now that project is starting to come back on. We expect additional volumes in August September. Fort Hills is continuing with its impressive ramp towards 200,000 barrels a day, potentially higher. As we look at maintenance activity, PADD II has well above average refinery maintenance planned for the fall.
And some of that is going to reduce the demand for WCS as well. So we see a seasonal opening of WCS discounts this fall. We expect the discount to be set by rail, assuming there is sufficient rail capacity, which would be the equivalent of kind of WTI minus 20. If rail is not sufficient, it could be wider. When you look at the Canadian exports by rail, we did see a new high in April, 190,000 barrels a day, but that's only about only slightly higher than the average 130,000 barrels a day last year.
So we're getting a little bit more rail, but not substantially more. So we expect WCS discounts to be attractive for at least the next 18 months and potentially longer.
Thanks, Chad.
Roger Read from Wells Fargo. Please go ahead. Your line is open.
Yes. Thank you. Good morning. And really, really great quarter there, I think we have to say. I'd like to come at it from the refining utilization side, 100 percent utilization.
And we've seen from the DOE stats really good performance for the whole industry. I was just curious, is this a function of that really is utilization or maybe there's been some increases in capacity that aren't exactly being measured properly, not so much for you, but maybe for the industry? And then how should we think about running above utilization levels as we roll into an IMO driven event next year?
Well, in our case, Roger, certainly, we came out of a heavy turnaround in the Q1. We came out, we ran really well. And given the market opportunities available to us, I think, currently run, I suspect that we're in a period where dips may come in just a little bit, but then as we come back into the maintenance season in the fall, you're going to see those dips open back up in many cases. IMO is going to be a nice tailwind, I think, for the industry as we start moving into 2019, strictly the back half of twenty nineteen. So I think that we're pretty constructive on both the supply and demand side.
We've got a strong economy going. And you think about the opportunities that come into 2019, we're pretty constructive on that. I don't know, Jeff, you want to add anything on color on the IMO?
No, I think that's all accurate. I think the IMO is going to benefit complex refining. And so I would expect higher utilization of the complex refineries in the U. S. And in our portfolio, higher utilization of coking capacity, which we're an industry leader there.
And so I think there will continue to be a focus on running well certainly within our portfolio.
Yes, I appreciate that. I guess that's what I'm trying to get at is, if you ran it 100% this quarter, the anticipation is that margins would be even more favorable in the latter part of 2019 into 2020. I mean, do we think about this as you can run it 102 or 103 or something like that? Or is there something else that we should be focused on like this kind of is it and so you just have simply work your way within the system as is?
Well, just a couple of points. I think that even in our Q2, we're probably about 3.5% due to downtime due to unplanned downtime and turnaround activity during the quarter. So obviously, we had assets that ran well above the 100% level coming into it. The other thing I would say, we've come through 2 heavy turnaround years in 2018 2017 for us. And so we're really, I think, from a portfolio standpoint, turnaround standpoint, well positioned for 2019 2020 to run well.
I appreciate that. And then as you look at secondary impacts of the IMO here, potential for some of the weaker competitors out there really outside the U. S. To get pushed out, Any thoughts about how that will affect crude flows or product demand?
Well, I think the refineries that produce high percentage of fuel oil are going to be the ones that are going to be stressed. A lot of Latin American refineries fall in that category. We'll have to see how the product flows adjust, but we're focused on our portfolio and making sure we can meet the standards across all our refineries.
Bill Gresh from JPMorgan.
First question just on chemicals. Could you just elaborate a little bit about what kind of contribution you think you saw from the cracker in the Q2? What kind of start up costs? Just kind of trying to tie it back to your mid cycle guidance kind of adjusted on a quarterly run rate basis, if you have anything on that?
Yes. Phil, it's Kevin. I'd say as you look at the Q2, you certainly have some ramp up in terms of utilization. So it's not you don't have a complete quarter of contribution from those assets, although by the end of the quarter, we were at very healthy utilization rates. I don't think start up expenses were anything to really move the needle in the quarter.
There may be a there may have been a little bit, but it's just not material. And I think as we step back and look at this, the mid cycle guidance that we've talked to previously is still intact. So still expect to generate that incremental EBITDA in the same range of numbers we've talked about in the past.
Yes. I think moving in the Q3, we're certainly would expect kind of run rate type levels of performance out of that asset. I think you think about the near term, so Dow was up, we're up now. ExxonMobil is coming up. And so near term, you could have some compression of margins as these volumes start to get absorbed in the marketplace.
Offsetting that though, the I mean, the global economy is strong. You saw the GDP number for the U. S. Today. And so we've got great demand on this.
And so we're still pretty constructive out over the next 3 to 4 years of good solid demand growth. And I think that our view is that there's probably more upside than downside on the margins if you want to look out in kind of this 3 to 4 year window.
And Greg, if I were to think about how that feeds into your timing of a potential second cracker, what are your latest thoughts there?
Well, I think you kind of start with the fundamentals. You still have 500,000, 600,000 barrels a day of ethane in rejection. There's more coming at us. There's going to be plenty of feedstock for the next wave, so to speak, of crackers. We're funding work on the second cracker today.
I think the FID decision will is when we obviously haven't taken yet, Phil, but I think that probably late 2019, 2020 is still what we're thinking in terms of FID on the next cracker. And we frankly like that spacing in between this project and the next project.
Okay. And then Kevin, just on the cash flow and the cash balances and the allocation of that. I know you've talked about wanting to pay some of the debt down that you incurred in the Q1. Obviously, you got some of the working capital reversal and the cash balance has built up nicely. So how do you think about the cash balances now?
And what you want to prioritize for the rest of the year?
Yes. So, dollars 1,900,000,000 at the end of the second quarter. Obviously, the Q1 not only impacted by the normal working capital drain that we see in 1Q, but with the Berkshire buyback, we drained cash to partly fund that as well. So getting cash back to a more comfortable range for us. I think you'll see to the extent we continue to have strong cash generation, we'll probably we'd probably do a bit more debt pay down.
That's probably running a little bit higher than we'd like it to be. I mean, the balance sheet is still strong, still with great credit ratings. But we'd like to do a little bit more on buybacks sorry, on debt pay down.
We need some more buybacks today, Bill. That's okay.
That's out there as well as a possibility. And then we've talked about the growth projects and the capital program. So we may end up building a little bit more cash. I think we're still if you look where we've been over the last 4, 5 years or so, we've had been running cash that's been $2,000,000,000 to $3,000,000,000 certainly for a chunk of that time. So it wouldn't surprise me if we end up carrying a little bit more cash for a period of time.
Got it. Okay. Thank you.
Paul Cheng from Barclays. Please go ahead. Your line is open.
Hey, guys. Good morning.
Hey, Paul.
Very good quarter.
Thank you.
Maybe that, Greg, just curious that in the refining in this quarter, if we have a similar market condition, do you think that is repeatable for your performance? Or that you think that this is every all the star is not yet right for you guys and will be difficult to repeat it?
Well, I think that we're set up to run well in terms of utilization. We don't have a lot of big turnaround in front of us coming into the Q3 from that standpoint. I think that the definitely the marketplace, the strengths of our portfolio. I think our commercial and supply folks did a really nice job getting the right crews to the front of the refineries, and then the guys in the refineries did a great job of running those crudes and creating value. But as I look out into the Q3, Q4, I'm still constructive on refining kind of going forward.
So whether we can repeat $1,300,000,000 quarter or not, I can't forecast that for you today. But I do think that refining is going to do well coming into the 3rd quarter.
Since the margin near term bottom in May, June, they have recovering in the last several days that have seen a certain surge. Just curious that have you guys see any theory behind why that the last several days that we see such a strong movement in the product margins?
I think it's mainly driven by utilization. We saw very strong utilization early in the summer and in June and that drove gasoline prices down, ended the quarter relatively soft in 2Q. Since that time, we've seen utilization come down. Demand's remained relatively healthy on the gasoline side and now gasoline cracks are back up to the middle or slightly above the 5 year range. On the diesel side, we're seeing really strong demand, 9% up year on year and that's driven by strong trucking activity with 8% increase year on year.
Rail movements are up 3.7% year on year and we're seeing strength in the areas where oil drilling activity is ongoing as well. And distillate inventories are at the low end or actually below the 5 year range on an absolute and days of demand cover basis. So distillate looks really strong.
Yes. Thank you. I mean, all those are great information. I'm just curious that because typically dose is not going to need to order certain for the last several days, a certain jump. So wondering that if your marketing people have seen any news or anything out there saying that have all the sudden happened in the last several days that may have triggered such a substantial move?
There's been some unplanned downtime, some heat related power issues, but nothing more specific than that.
And can you tell us that how much is the heavy oil you run-in the U. S. In the Q2 comparing to the quarter or the Q2 last year as a percentage?
It was up slightly. I don't have that off the top of my head, but I'd be happy to get back with you.
Okay. And for CapEx, Kevin, that the previous range that you guys given, is this still a good range even if we assume that you're going to make more money and have more cash?
The CapEx, Paul?
Yes.
Yes. So as you know, we've just recently sanctioned 2 large midstream projects at a consolidated level. Obviously, the Gray Oak pipeline being done at the MLP, but that rolls up into consolidated number. So year to date spend is running lower. So just under $900,000,000 year to date, the consolidated budget is $2,300,000,000 but we are seeing the spend rate pick up and we would expect that to continue into the second half of the year.
So at this point, I'd say there's potential that we could go a little bit over the $2,300,000,000 budget in aggregate. I don't think it would be significantly above that. I mean, we
I would guess at
this point, we'd be somewhere between $2,300,000,000 $2,500,000,000 for the year. Obviously, as the next few months go by, we'll have much better visibility into where that's going to end up.
How about the next several years, Kevin? Should we still assume about $2,500,000,000 kind of range? Or is this going to be higher?
Yes, I would. I think in overall terms, the $2,000,000,000 to $3,000,000,000 a year of CapEx is good guidance to go with still.
Two final questions. A quick one. One, do you guys think that we will have sufficient crude export capability in the Gulf Coast if, say over the next 2 or 3 years, we will continue to increase the volume that we need to export by 0.5000000 to 1,000,000 barrels per day a year. And whether that is a business you guys also want to get into more? And secondly, that when you contact with your government people, do you think that there's a high risk that IMO 2020 end up being pushed out because of political backslash if what we expect in terms of the rapid rise in the product prices come to materialize?
Thank you.
All right. Yes, Paul, I would say we do see a big opportunity for exports across oil and products. As part of the Gray Oak expansion, we've got the South Texas Gateway. And as we look at the majority of the large pipe long haul pipelines, they have got export options. And so we see export capability being added.
We believe most of the incremental production is going to get exported. And so we do see that opportunity and see the market addressing it. With regard to IMO, we are gaining confidence in the implementation date. The IMO certainly is emphasizing moving forward. When you look at the other fuels have already reduced sulfur and bunker fuel is small percentage of total transport demand, but it makes up the vast majority of SO2 emissions.
And so I think there is incentive to move forward. We see a recent announcement out of China announcing that they're going to increase their marine fuel regulations to require the 0.5 sulfur next year and then taking it down 0.1% sulfur in the following year. We've seen the IMO focus on inspections on both import and export facilities. And so we see this moving forward on Oneonetwenty 20. There may be or we would expect that there would be a system set up in the event that supply is not available on a one off basis that there may be a waiver, but it would be short term in nature and specific to particular incidents.
Thank you.
Thanks, Paul.
Justin Jenkins from Raymond James. Please go ahead. Your line is open.
Great. Thanks. Good morning, everybody. I guess maybe starting in the Permian, appreciate all the additional details on the Gray Oak project. But is it right to think that the scope of that project is being designed that it can be taken all the way to the $1,000,000 a day number with pretty little incremental capital from the $800,000,000 a day starting point?
We're putting in 30 inches pipe. So that kind of tells you that it's going to be a pretty easy lift to get to the 1,000,000 barrels a day. So yes, I think that look, a lot of interest still in the Permian and takeaway capacity. I think we're pleased that where we're at in terms of project execution. You've got the steel on order essentially, lined up the contractors and so the project is really on track.
So we're pleased with where we're at.
Perfect. Appreciate that. And then maybe following up on Phil's question on capital allocation. How should we think about M and A, if at all, in that process, maybe especially with some of the midstream packages out there
today? Well, I think we, like everyone else, kind of looks at everything that's out there. Things look really pricey to us, particularly in the midstream space. As you think about the opportunity to create value, we have such a great organic profile in front of us that we don't feel like we need to rush out and do something in terms of the M and A space today. So we'll continue to watch it.
If we can create value by doing it, we're certainly willing to do it. We've got the balance sheet and the capability to do it if the right opportunity happens to come our way.
Doug Leggate from Bank of America Merrill Lynch. Please go ahead. Your line is open.
Thanks. Good morning, everybody. Kevin, maybe I could if I could go back to the cash question. You got a nice distribution obviously from CPChem this quarter. I'm just curious as a kind of broad idea of how this might evolve.
Is that a biannual distribution? How do you expect that to look going forward? And is there a level of cash that you want to get back to? I think you kind of suggested you want to you obviously want to build a little bit more cash after the buyback, the Berkshire buyback and so on. Is there a level of cash you want to get to?
And I guess as a bolt on to that, the balance between share buybacks and dividends, latest thoughts and I've got a quick macro follow-up, please.
Okay. So in terms of absolute cash level, I'd say there's not a target level. There's not a number. Very comfortable with where we are today. So I think of when we were $800,000,000 at the end of the quarter, that's a bit lower than we like to be.
So you're probably looking at something north of $1,500,000,000 plus $1,500,000,000 to $3,000,000,000 is a very comfortable range to be in, but not targeting any one particular number on that. In terms of CPChem cash distributions, there is no set schedule on distributions. So we've guided to $600,000,000 to $800,000,000 this year. The increase significant increase from where we have been and it's driven by a function of higher operating cash flow with the new assets coming online as well as much lower capital spending at the CPChem level. Now ideally, a quarterly distribution would be perfect, but it doesn't necessarily play out like that.
So it's somewhat dependent on how the cash balances at CPChem move over month to month. And as a Board, we kind of work through what the appropriate distributions are going to be. So ratable would be nice and it probably will be not too far off of ratable, but it can still be somewhat lumpy there. Now there was a third one.
Can I just comment on that just a little bit? I mean, the Board can decide what to do at CPChem, but the basis of the foundation agreements are as we really don't hold a lot of cash at CPChem. We tend to distribute the cash out. Obviously, we won't hold enough cash to do the capital programs or whatever's going on at CPChem, but it's kind of a basic fundamental tenet of the joint venture. We tend to distribute the cash.
Okay. Thanks, Greg. Sorry, Kevin. The last one embedded in there was any change in the thoughts of buyback dividend balance?
Really not. So the principles around the dividend, secure, growing, competitive and obviously you saw the 14% increase last quarter. And then buybacks, we look at that on a intrinsic value. We look at where the shares are trading relative to our view of intrinsic value. We've guided to a $1,000,000,000 to $2,000,000,000 per year range in normal circumstances.
Obviously, year is a little bit unique with the large transaction we did last quarter. But in overall terms, no change.
Thanks. Greg, I wonder if I could just go to my macro question then. I've kind of got 2 parts to it, if I may. There's on IMO, there's obviously, you've been, I think, if I may phrase it this way, a little more measured than your expectations of how that may play out and the way you've characterized it. But we're starting to hear about new refinery or dormant refineries coming back up.
Hovenza has been mentioned. St. Croix has been mentioned. I think there's a a German refinery, is Oetha is one to be mentioned. I'm just curious as to how you could frame your thoughts as to how much conviction issue.
It's bit of a random one really, but are we comfortable if the export capacity gets built, the bottleneck gets cleared once the pipelines move? And assuming there's no trade war ramifications from the potential outlets there? And I'll leave it there. Thanks.
Yes. I think that we'll start go backwards with the export capacity is probably is going to get built. I think the infrastructure to clear all the products, whether it's crude, NGLs or gas are going to get built because it just looks like to us that the production is going to grow faster than what we can consume it here in the U. S. So I think that fundamental premise that we're going to be exporting all three products is a good one, and we actually want to participate in that.
So we talked about the Buckeye, but we're also by the end of the year, we're going to have Beaumont going from 600,000 to 900,000 barrels a day. You think about our kind of our export platforms off the U. S. Gulf Coast, we probably got 10% or 12% expansion capabilities laid into those over the next 2 years or so. So I think we're trying to position the portfolio to get ready to export more crude and products.
And then on IMO, I suspect that people and we're
It's right. I was about, you can probably speak to the speculation. It was private equity, it was speculating, so you're not selling it then.
We're happy with our position there, Doug. Let's put it like that. But yes, no, I think people I think IMO, it's kind of perceived as a big opportunity by people and people are going to try to play that opportunity to the extent that they can. I think that fundamentally, our view hasn't changed. I think that over the next, say, couple of years, it's going to be a nice tailwind for the industry.
I mean, we can argue about whether it's $5 or $10 on the distillate crack or what it's going to be. But I do think when you look out over a long enough time frame, we'll continue to build global refining capacity and that capacity will get directed to solve that problem. A lot of that capacity is going to go up in the Middle East and in China and India. So I just think that over time that the industry will work its way through this. And indeed that's been the history of the industry over a long period of time is that the big opportunities are tend to get competed away over time.
And so I just don't fundamentally have a different view on that today.
Just last bullet on very quickly. I mean, like all you guys, I mean, Joel was the same with Alero and Gary have been relatively constructive in the second half. Are you factoring in the announcement from Mexico that their entire refinery system could go down for maintenance in the second
half of the year and your thoughts?
So I just saw that. Yes. So that certainly is a nice tailwind.
Yes, it
could be a meaningful impact next year, an ongoing trend to the Venezuela refining utilization and Mexico refining As we think about IMO, there is it will likely take some time. There's not a substantial uptick in capital spending that's underway to meet the IMO specs. And these are projects that are capital intensive and long lead time. The high complexity refineries, many of them are running at high utilization rates already. So I think it will be a challenge for the industry, but a challenge we're up for.
Thanks everybody. Appreciate your answers. Take care.
Brad Heffern with RBC Capital Markets. Please go ahead. Your line is open.
Hey, good morning, everyone.
Good afternoon.
Question on the crackers. So you guys have already demonstrated above nameplate on that. I'm sure that you're not very far along in the debottlenecking process either. Any thoughts as to where that could go over time if you've already demonstrated such healthy level?
Well, I think that with all assets, we'll get better as we get more and more experience running it. We know that we have some, probably low cost cap to bottleneck in that facility too that I think that we'll be able to address better with you in the coming quarters. But certainly, the asset came up and ran better than our expectations. And probably, I think, it's probably the smoothest start up we've seen in the last 5 of those big assets that we've started
up. Okay. Great. And then on the new fracs, you guys obviously put out a cost estimate, no EBITDA number. I would think that the fracs themselves are probably just getting sort of a normal tolling fee, if you will.
But I know you overbuilt the original one, so I'd imagine the whole system should work better together. So any thoughts on what the EBITDA uplift across the whole hub is?
Well, on the new fracs themselves, you should expect kind of typical type midstream returns. And so let's call it 6% to 8%, and the fracs are probably to the higher end of that. The pipes are probably to the lower end of that. And so you can kind of back into it.
Okay. But is there any uplifts for the existing assets from having the 2 new fracs installed?
Yes. There's no question that a large part of the investment for Frac 1 was in infrastructure, pipes to get to Bellevue and back, some of the early cavern work that we did. Today off of Frac 1, we're making, I don't know, 38,000 barrels a day of propane and we're running the export facility at 200,000 barrels a day. And so that delta between what we're making and what we're exporting, we're actually bringing from Mount Bellevue. And so we're buying those barrels in Bellevue today and we're paying a fee to move them on the pipes.
And so there are going to be synergies and uplifts by making more of the propane at the Sweeny site to be exported.
Okay. Thank you.
Manav Gupta from Credit Suisse. Please go ahead. Your line is open.
Hey, guys. Looking at the ethylene cracker startup over the last decade, all the crackers that came online in Middle East between 'nine and 'twelve had some startup issues. One of your peers who achieved mechanical completion in 1Q could not start the cracker for 6 months and then ran into multiple issues at the startup. Your ethylene cracker has had one of the smoothest starts we have witnessed in the last decade. Most ethylene crackers achieve 70% to 80% design rate.
You're already hitting 106%. So it's pretty impressive. I'm just trying to understand how you did it. Like what did you guys do so differently that others could not and buck the trend?
Well, hopefully, we learned something over the 5 times when we were one of those parties that started up and had troubles in the Middle East. I think our last outing was our Saudi Polymers project, and it took 8 months to get that cracker up and running from the time that we started up, and we had multiple challenges and issues. I think that I think we had a dedicated project team of strong ops people on this project from the very beginning on the design all the way through the construction and the start up of the facility. I think that really helped. I think that as we watch the construction and we were going to the fabrication sites, we had better quality control this time.
And so we just didn't see the equipment issues starting up this facility. And then the construction, while we were probably late by 6 to 7 months and we're disappointed with that, the overall quality of this construction was very, very good.
Great job, guys. And second question is, on the Gulf Coast, it's good to see meaningful contribution from further refining earnings on the Gulf Coast. Can you talk about how BioBridge adds to this positive momentum and the uplift you get once you get the 2nd leg completed?
Well, no, certainly. I think BioBridge is an important asset for us. And we're running barrels over to our Lake Charles refinery. Obviously, we get the fee for moving the barrel, but on a general interest basis on, I don't know, 80,000, 90,000 barrels a day, we're probably picking up $1 a barrel or something like that for the general interest of the company, which is really a strong performance. We're anxious to get the pipe to St.
James completed this year. And then we're also looking at running pipe to St. James down to Alliance. So ultimately, we want to connect all of our Louisiana refineries with the Texas Gulf Coast. And from a general interest perspective, we think that's good.
And then the other thing I would just say about the Gulf Coast, we import a lot of Canadian heavy down. We run all we can. We sell the rest. But we got Canadian heavy into Squeenie this quarter, some into Lake Charles. Obviously, Lake Charles benefited by the Maya LLS also.
And so it just things worked well for us in the Gulf Coast this quarter.
Great. And last question is that ethane prices have moved up to $0.35 per gallon. And I was wondering if you could talk about how that impacts your entire NGL business? And does that actually change your view of how you intrinsically value DCP?
Well, I think that there's no question NGL prices have moved up. I don't think they moved up as much as people expected them to. At this point in the cycle given 3 cracker startups, each needing about 90,000 barrels a day of ethane. So I mean, we continue to like DCP. There's no question that a higher NGL price for the barrel also benefits them to the extent that we're pulling more ethane out of rejection in the areas where DCP contributes, that's also very, very positive towards DCP.
But it doesn't fundamentally change our view on DCP. We like DCP. We like the asset footprint they have in the Eagle Ford, in the Permian, in the Mid Continent, particularly in the DJ Basin. So good assets for DCP.
Matthew Blair from Tudor, Pickering, Holt. Please go ahead. Your line is open.
Hey, good morning, everyone.
Good morning.
Greg, I was wondering, CPChem have any interest in adding more ethylene derivative capacity? I know you've run more of an integrated model here, but we're looking at pretty low ethylene spot prices. And if we look out over the next 5 years or so, we definitely see a lot more cracker capacity coming online than derivative capacity. Not sure if you agree with that. I think you mentioned previously that PE demand growth was strong.
So what kind of interest, if any, would you have in, say, like a standalone PE unit to take advantage of some of these trends?
Yes. Well, first of all, I'd say, if you don't like the ethylene spot price today, just hang around a little bit because it's going to change. Look, CPChem generally runs just slightly long on ethylene. We like to be relatively balanced. And so I wouldn't be surprised to see them add or debottleneck some derivative capacity.
To your question, would we build speculative derivative capacity based on someone else's long? I don't think so. And the reason is we want to capture that value through the full chain. If you look, that value moves, right? It's not always in the derivative.
Sometimes it moves to the ethylene side. And so we like that integration and be able to participate in that full value chain.
Makes sense. And then on heavy Canadian, so Enbridge made some progress in their Line 3 replacement recently. I don't think Phillips is much of a shipper on Enbridge, but regardless it would add more WCS to the overall U. S. Supply mix.
How much of an appetite would you have to run additional WCS in either your Central Corridor or Gulf Coast system. Are you pretty maxed out? Or could you ramp runs if more supply was available?
Yes. We're bringing over 500,000 barrels a day of Canadian crude in today. So we're the largest importer of Canadian crude. We're probably running about 80% of it or so, I would guess. I don't know, Jeff, you've got the exact number, but it's right in that range.
So we're kind of maxed out on Canadian heavy today.
Yes, about 80% of that is heavy, and we're running what we can. We're not big shippers on Enbridge, Matthew.
Great. Thank you very much.
Craig Shere from Tuohy Brothers. Please go ahead. Your line is open.
Hi. Congratulations on the great quarter.
Thank
you. I understand nothing's really changed in terms of the capital allocation and we at least want to pay back another $1,000,000,000 maybe $1,000,000,000 a quarter around the debt we took out for the share buyback in the Q1. But it sounds like there's a vision here of maybe a really nice, call it, 2, maybe 3 year kind of one time ish, very strong cash flows on the low inventories, but leading into IMO 2020. And of course, the thinking that eventually that will get worked out by the market. But what do you do with a windfall?
I mean, if you come up with an extra couple of $1,000,000,000 and you don't think it's repeatable, how do you think about that?
Look, well, first of all, what a great problem to have.
And but
yes, I think our fundamental capital allocation strategy, which has served us well for 6 years, really isn't going to change. We kind of think about this sixty-forty percent, 60% of our cash available from all sources. We want to reinvest in our business to the extent that we have opportunities that we can generate acceptable returns. And then 40%, we're going to get back to shareholders through a strong, secure growing dividend and share repurchase as long as we're trading below intrinsic value on the share repurchase side. So we continue to look 3 years out, some of the parts historical multiples and if that value is higher than the price in the market, we're buying.
So we're buying today in the market. So I don't think that fundamental change that changes. Maybe we hold a little higher cash, maybe we pay down a little bit more debt along the way. But fundamentally, you're not going to see us change our capital allocation strategy.
In terms of the reinvestment, we had a little temporary hiatus as we worked on some massive project portfolio. And then you announced Gray Oak and Sweeny Fracs expansions. How much after that do you think we have? I mean, as we look into the early 2020s, do you think there's the ability if the cash flows materially increase to take it up to 3,000,000,000 to 4,000,000,000 dollars in growth CapEx on an annual basis for a couple of years?
So, yes, I'll just come back. I think the portfolio is going to generate $5,000,000,000 to $6,000,000,000 of cash. We got $1,000,000,000 of sustaining capital. We want to fund kind of another $1,000,000,000 to $2,000,000,000 of growth, so call it $2,000,000,000 to $3,000,000,000 of capital. So that takes care of that.
Got $1,500,000,000 dividend today and that leaves room for another $1,000,000,000 to $2,000,000,000 of share repurchases and that kind of all balance within our means. And so I think that you'll continue to see us work that. I do think there's going to be other opportunities. We'd like to do Frac IV out there. In the future, there may be more pipe opportunities, more export oriented opportunities for us as we think about 2020 beyond.
So I think we've got a good run-in front of us in terms of just the opportunity set that we see around infrastructure, midstream and of course the petrochemicals business.
Great. Thank you.
We have no further questions at this time. I will now turn the call back over to Jeff.
Thank you, Julie, and thank you for your interest in Phillips 66. If you have additional questions, please call Rosie or me. Thank you.
Thank you, ladies and gentlemen. This concludes